1015-00003 · Calloway-Briggs Renewables Inc · Diligence

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PRIVILEGED AND CONFIDENTIAL — ATTORNEY WORK PRODUCT

CALDERWOOD & HARKNESS LLP 1000 Louisiana Street, Suite 5500 Houston, TX 77002

MEMORANDUM

To: George Trujillo, Partner

From: David Stanton, Lead Associate; Michelle Tsao, Associate

Date: October 2022

Re: Texas Interconnection & ERCOT Regulatory Issues — Lone Star Battery Storage Project (Ector County, TX)

Matter No.: 1015-00003

Client: Calloway-Briggs Renewables Inc.

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I. Executive Summary

This memorandum analyzes the Electric Reliability Council of Texas ("ERCOT") interconnection process, network upgrade cost allocation framework, and the applicable regulatory landscape for battery energy storage systems ("BESS") under Texas law, as each relates to the Lone Star Battery Storage Project (the "Project"). The memorandum has been prepared at the request of Calloway-Briggs Renewables Inc. ("CBR") to support the development team's decision-making in connection with the negotiation and execution of the Project's Interconnection Agreement, and to inform the broader project finance and regulatory compliance strategy.

The Project consists of a 50 MW / 200 MWh lithium iron phosphate ("LFP") battery energy storage system being developed by Lone Star Storage I, LLC ("Lone Star"), a wholly owned Texas limited liability company subsidiary of CBR. The Project is located on a 15-acre parcel in Ector County, Texas (nearest postal address: 4800 West University Boulevard, Odessa, TX 79764). The total project development value is approximately $40,000,000.

The Project has been assigned ERCOT Interconnection Queue No. INR-22-03347, with a pending ERCOT Resource ID of LSBESS_01. The designated Point of Interconnection ("POI") is the Western Permian 138 kV Substation in Ector County, Texas, owned and operated by Aldermere & Co. ("Oncor"). The Full Interconnection Study ("FIS") was completed in August 2022 and identified estimated network upgrade costs of $2,800,000. The Project will be connected to the POI via an approximately 1.2-mile, 138 kV overhead gen-tie line from the Project site, with an on-site step-up transformer converting from the BESS native voltage of 34.5 kV to the interconnection voltage of 138 kV.

The expected energization date is July 15, 2023, with an expected commercial operation date ("COD") of August 15, 2023. The EPC Guaranteed COD under the engineering, procurement, and construction contract with Meridian Power Construction, Inc. ("Meridian Power") is September 1, 2023, with a 15-day cure period. The Interconnection Agreement is targeted for execution on December 1, 2022.

Based on our review, we have reached the following key conclusions:

• BESS Classification. BESS projects are treated as generation resources under ERCOT protocols for interconnection and market participation purposes. The dual-use nature of BESS (generation on discharge, load on charge) is addressed through ERCOT's Energy Storage Resource ("ESR") classification, which carries specific study and operational requirements.

• Regulatory Jurisdiction. The Public Utility Commission of Texas ("PUCT") has jurisdiction over electric utilities and power generation companies operating within ERCOT, and the regulatory treatment of standalone BESS is evolving. No material regulatory impediments have been identified for the Project, but ongoing monitoring of PUCT rulemaking activity and ERCOT protocol revisions is advisable.

• Network Upgrade Costs. The $2,800,000 in estimated network upgrade costs identified in the FIS represent a significant financial obligation that will be borne by Lone Star. These costs are estimates and are subject to adjustment upon completion of detailed engineering. Cost escalation risk should be contractually addressed through contingency budgeting and, to the extent achievable, negotiation of cost caps or true-up protections in the Interconnection Agreement.

• Timeline Feasibility. The timeline from FIS completion (August 2022) to expected energization (July 15, 2023) is approximately eleven months, and the timeline from targeted Interconnection Agreement execution (December 1, 2022) to expected energization is approximately seven and a half months. Both timelines are achievable but require active schedule management and close coordination with Oncor regarding the construction of network upgrades at the Western Permian Substation.

The balance of this memorandum provides detailed analysis supporting these conclusions and sets forth our specific recommendations for the Project team.

II. Background and Project Description

A. Project Overview

The Project is being developed by CBR, a Texas corporation headquartered at 2200 West Commerce Street, Suite 1400, Houston, TX 77002. CBR was founded in 2014 by Raymond T. Calloway (Chairman & CEO) and Sandra M. Briggs (President & COO). Since its founding, CBR has focused on the development, ownership, and operation of utility-scale renewable energy and energy storage assets within the ERCOT market. As of the date of this memorandum, CBR has approximately 1.2 GW of solar generation capacity and 400 MW of battery energy storage capacity in various stages of development, ranging from early-stage origination through commercial operation. CBR reported annual revenues of approximately $185 million for its fiscal year ending December 31, 2021, reflecting income from its operating portfolio as well as development fee income from projects reaching financial close and commercial operation.

The Project is held through a single-purpose project company, Lone Star Storage I, LLC (Employer Identification Number: 88-1623504), a Texas limited liability company wholly owned by CBR. Lone Star was formed specifically to hold all Project assets, contracts, and permits, consistent with standard project finance structuring requirements. Lone Star's registered agent is CT Agents of Texas, LLC, 1999 Bryan Street, Suite 900, Dallas, TX 75201.

The Project will deploy LFP BESS technology with a nameplate capacity of 50 MW and a storage duration of four hours, providing a total energy storage capacity of 200 MWh. The BESS equipment will be supplied by Harmon-Dietrich Energy Solutions, LLC under its Model HD-LFP-200E platform, which comprises lithium iron phosphate battery modules, ten (10) 5 MW power conversion system ("PCS") inverters, a battery management system ("BMS"), thermal management systems (HVAC), and containerized enclosures. Harmon-Dietrich is a domestic supplier with a manufacturing facility in Greenville, South Carolina, and has delivered over 800 MWh of LFP BESS equipment to projects across the United States. The Equipment Supply Agreement between Lone Star and Harmon-Dietrich has a total value of $18,400,000, with delivery on a FOB Project site basis in four shipments scheduled between March 15, 2023 and June 1, 2023.

The Project site consists of an approximately 15-acre parcel, being a portion of Survey No. 42, Block 42, T-1-S, Texas & Pacific Railroad Company Survey, Ector County, Texas. The site is leased from Permian Basin Land Holdings, LP ("PBLH") under a 25-year Ground Lease agreement, which includes two five-year renewal options, providing Lone Star with a potential term of up to 35 years. The Ground Lease is structured as a standard ground lease for utility-scale energy projects, with provisions for quiet enjoyment, access, and lender recognition.

Meridian Power Construction, Inc. has been selected as the engineering, procurement, and construction contractor for the Project. The EPC Contract is structured as a fixed-price, turnkey contract at a total price of $31,200,000. The EPC Contract scope encompasses site preparation, civil works, foundation construction, equipment installation and commissioning, the gen-tie line, and the on-site step-up transformer. A letter of intent and term sheet were executed with Meridian Power on October 14, 2022, and the definitive EPC Agreement is targeted for execution on December 1, 2022, concurrent with the Interconnection Agreement and other principal project agreements.

B. Capital Structure

The total development value of the Project is $40,000,000, which encompasses all costs from development through commercial operation, including EPC costs, equipment supply, network upgrade costs, development costs, financing costs, legal fees, permitting, insurance, and working capital reserves. The capital structure is as follows:

The debt component consists of a $26,000,000 construction-to-term loan from Brazos River National Bank, N.A. ("BRNB"), representing 65% of the total project development value. The loan will initially fund as a construction facility, converting to a term loan upon achievement of COD and satisfaction of conversion conditions. The equity component totals $14,000,000, of which $9,100,000 (65% of equity) will be contributed by CBR and $4,900,000 (35% of equity) will be contributed by Ridgepoint Capital Partners, LP ("Ridgepoint"), a Houston-based infrastructure investment fund that has co-invested with CBR on prior projects.

The estimated network upgrade costs of $2,800,000, payable by Lone Star to Oncor and/or ERCOT-designated transmission service providers, are included within the $40,000,000 total project development budget and are expected to be funded through a combination of debt draws and equity contributions in accordance with the pro rata funding provisions of the Credit Agreement.

C. Key Dates and Milestones

The following timeline summarizes the key dates and milestones for the Project from inception through expected commercial operation:

The timeline from the filing of the interconnection application in March 2022 to the expected COD in August 2023 spans approximately 17 months, which is within the range of typical development timelines for BESS projects in the ERCOT market. The critical contractual date is the EPC Guaranteed COD of September 1, 2023, which, together with the 15-day cure period, provides an outside date of September 16, 2023 for the achievement of commercial operation without triggering delay liquidated damages under the EPC Agreement.

III. ERCOT Interconnection Process for BESS Projects

A. Overview of ERCOT Interconnection Framework

The Electric Reliability Council of Texas operates as the independent system operator for the Texas Interconnection, the electric grid serving approximately 90% of the state's electric load. Unlike other major independent system operators ("ISOs") and regional transmission organizations ("RTOs") in the United States — such as PJM Interconnection, the Midcontinent Independent System Operator ("MISO"), the California Independent System Operator ("CAISO"), and the New York Independent System Operator ("NYISO") — ERCOT operates largely independently from federal jurisdiction under the Federal Energy Regulatory Commission ("FERC"). This jurisdictional distinction arises from the fact that the Texas Interconnection has only limited asynchronous ties to the Eastern and Western Interconnections, and therefore the ERCOT grid does not engage in interstate commerce in electricity in a manner that would trigger FERC's plenary jurisdiction under the Federal Power Act. As a result, the interconnection of generation resources to the ERCOT grid is governed primarily by Texas state law, the rules of the PUCT, and the ERCOT Protocols and Planning Guides, rather than by FERC's interconnection rules (e.g., FERC Order No. 2003 and its progeny, which govern interconnection in FERC-jurisdictional ISOs and RTOs).

The primary governing documents for the ERCOT interconnection process include the ERCOT Nodal Protocols and the ERCOT Planning Guide. The Planning Guide, particularly Section 5 (Generation Interconnection or Change Request), establishes the procedural framework for the submission, evaluation, and processing of interconnection requests from new generation resources seeking to connect to the ERCOT transmission system. These protocols set forth the application requirements, study procedures, financial security obligations, milestone schedules, and the standard terms upon which interconnection will be granted.

For purposes of the ERCOT interconnection process, BESS projects are classified as generation resources. This classification is significant because it determines the applicable study methodology, queue position rules, financial security requirements, and the form of interconnection agreement. It should be noted, however, that BESS assets possess a dual-use characteristic: they function as generation resources when discharging energy to the grid and as load resources when charging from the grid. ERCOT has addressed this dual nature through the creation of the Energy Storage Resource ("ESR") category within its resource classification framework. The ESR classification carries specific study requirements and operational obligations that are discussed in greater detail in Section V of this memorandum. For interconnection study purposes, a BESS project is evaluated based on its maximum injection capacity (in this case, 50 MW), which determines the scope of the powerflow, short circuit, and stability analyses conducted by ERCOT.

The distinction between the ERCOT interconnection framework and those of FERC-jurisdictional ISOs/RTOs has important practical implications for the Project. Most notably, the absence of FERC jurisdiction means that the interconnection process is not subject to the timelines, dispute resolution mechanisms, or cost allocation methodologies mandated by federal orders. While this affords ERCOT and the PUCT greater flexibility in designing interconnection procedures, it also means that certain protections available to interconnection customers in other regions — such as the refundability of network upgrade costs under certain FERC-approved tariff provisions — may not be available in ERCOT. These cost allocation issues are discussed in detail in Section IV of this memorandum.

B. Interconnection Application and Queue Position

The interconnection process in ERCOT commences with the submission of a Generation Interconnection or Change Request ("GINR") to ERCOT's Planning Department. The GINR is the formal application by which a proposed generation resource (including a BESS project classified as an ESR) requests permission to interconnect to the ERCOT transmission system at a specified point.

Lone Star filed its GINR with ERCOT in March 2022 and was assigned Queue No. INR-22-03347. The application requested interconnection of a 50 MW generation resource (the BESS facility) at the Western Permian 138 kV Substation in Ector County, Texas.

The GINR application requires the submission of detailed project information, including without limitation:

• A description of the proposed generation resource, including technology type, nameplate capacity (MW), energy storage capacity (MWh, for storage resources), and duration;

• The geographic location of the proposed facility, with sufficient specificity to identify the site for transmission planning purposes;

• The requested POI, identified by the name and voltage of the substation or transmission facility at which the resource will interconnect;

• The expected capacity at which the resource will inject power into the grid;

• A single-line electrical diagram showing the proposed facility layout, step-up transformer, gen-tie line, and interconnection to the POI;

• The projected in-service date for the facility; and

• Evidence of site control (e.g., a lease, option, or deed).

Upon acceptance of the GINR, ERCOT assigns the application a queue position, which determines the order in which competing interconnection requests at the same or electrically proximate POIs will be studied. Queue position is a critical asset in any interconnection process: a project with an earlier queue position benefits from favorable study assumptions because the transmission system is evaluated without the incremental burden of later-queued projects. Conversely, a later-queued project may face higher network upgrade cost estimates or feasibility challenges as a result of the cumulative impact of earlier-queued projects on the available transmission capacity.

ERCOT's queue management rules require interconnection applicants to meet specified milestones and maintain adequate financial security deposits to retain their queue positions. Failure to meet milestones or provide required financial security can result in loss of queue position, which would require the project to reapply and potentially face different (and likely less favorable) study results. For the Lone Star Project, queue position INR-22-03347 should be actively managed to avoid any risk of forfeiture.

The application fee and financial security deposit requirements applicable to the Project are established under the ERCOT Protocols and are scaled based on the size of the proposed resource. These deposits are typically refundable, in whole or in part, upon the interconnection resource achieving commercial operation, but may be forfeited if the project is withdrawn or fails to meet required milestones. We recommend confirming the current status of all financial security deposits associated with Queue No. INR-22-03347 and ensuring that all upcoming milestone requirements are calendared and tracked by the Project development team.

C. Interconnection Study Process

ERCOT employs a multi-phase study process to evaluate proposed generation interconnections. The study process is designed to identify the transmission system impacts of the proposed resource and to determine what, if any, network upgrades are required to accommodate the interconnection reliably. The three principal phases of the study process are as follows:

1. Screening Study. The Screening Study is a preliminary assessment of the available transmission capacity at the requested POI. This study provides a high-level identification of potential constraints on the transmission system that could affect the feasibility of the proposed interconnection. The Screening Study typically involves simplified powerflow analysis and may identify obvious thermal overloads, voltage violations, or stability concerns at the requested POI. The purpose of the Screening Study is to provide the interconnection applicant with early feedback on the viability of its requested interconnection before more detailed (and costly) studies are undertaken. Projects that pass the Screening Study without identification of significant constraints proceed to the Full Interconnection Study.

2. Full Interconnection Study (FIS). The FIS is a comprehensive technical evaluation of the proposed interconnection. The FIS involves detailed powerflow modeling, short circuit analysis, and transient stability analysis of the transmission system with the proposed resource modeled at its full requested injection capacity. The FIS evaluates the transmission system under a range of operating conditions and contingency scenarios (e.g., N-1 contingencies, in which the system is analyzed with one element out of service) to identify any thermal limit violations, voltage performance issues, or stability problems that would result from the addition of the new resource. Based on the results of the FIS, ERCOT identifies the network upgrades (if any) required to accommodate the proposed interconnection and provides an estimated cost for those upgrades. The FIS results serve as the basis for the network upgrade cost allocation to the interconnecting resource and form the foundation of the Interconnection Agreement.

3. Facilities Study. The Facilities Study is a detailed engineering study that provides refined cost estimates and construction specifications for the network upgrades identified in the FIS. The Facilities Study is typically performed by the transmission service provider responsible for constructing the upgrades (in this case, Oncor) and provides the interconnecting resource with a more precise estimate of the total cost of required upgrades. The Facilities Study may confirm the FIS estimate, or it may result in higher or lower cost estimates depending on the outcome of detailed engineering and current material and labor costs.

For the Lone Star Project, the Full Interconnection Study was completed in August 2022. The study modeled a 50 MW injection at the Western Permian 138 kV Substation and analyzed the thermal limits, voltage performance, and stability of the surrounding transmission system under various contingency scenarios. The FIS concluded that the proposed interconnection is feasible, subject to the completion of identified network upgrades at an estimated cost of $2,800,000. A summary of the FIS results is set forth in Appendix C to this memorandum.

It is important to note the risk of restudy in the ERCOT interconnection process. If other projects ahead of the Lone Star Project in the ERCOT queue at or near the Western Permian Substation withdraw, modify their scope, or otherwise change the assumptions upon which the Lone Star FIS was based, ERCOT may require the Lone Star FIS to be restudied. A restudy could result in different network upgrade requirements — either higher or lower — depending on the changed conditions. While a restudy could theoretically reduce the required upgrades (for example, if an earlier-queued project withdraws and relieves a previously identified constraint), it could also increase the required upgrades or identify new constraints. This restudy risk should be monitored through regular review of the ERCOT interconnection queue and communication with ERCOT's Planning Department.

The timeline from Lone Star's interconnection application (March 2022) to completion of the FIS (August 2022) was approximately five months. This timeline is consistent with typical ERCOT processing times for BESS projects requesting interconnection in less congested areas of the ERCOT grid. Interconnection requests in more congested areas, or those involving larger or more complex facilities, may experience longer study timelines.

D. Point of Interconnection — Western Permian 138 kV Substation

The designated POI for the Project is the Western Permian 138 kV Substation, located in Ector County, Texas. The substation is owned and operated by Oncor, which serves as the transmission and distribution service provider in this area of the ERCOT grid. The interconnection will occur at the 138 kV voltage level.

The on-site infrastructure required for the interconnection includes a step-up transformer that will convert the BESS native voltage of 34.5 kV (the output voltage of the PCS inverters) to the 138 kV interconnection voltage. The step-up transformer will be located on the Project site and is included within the EPC scope.

The gen-tie line connecting the Project site to the Western Permian Substation will consist of an approximately 1.2-mile overhead transmission line rated at 138 kV. The gen-tie line will be owned and maintained by Lone Star. The routing of the gen-tie line crosses one or more parcels between the Project site and the substation, necessitating the acquisition of right-of-way easements from the affected landowners. To the extent that any portion of the gen-tie route crosses land owned or controlled by PBLH (the lessor under the Ground Lease), the easement rights should be coordinated with the Ground Lease to ensure consistency and avoid any conflicts between the two instruments. Any portions of the gen-tie route crossing parcels owned by third parties will require separate easement agreements, and we recommend that the development team commence easement negotiations promptly to avoid delays.

At the Western Permian Substation, modifications will be required to accommodate the new interconnection. Based on the FIS results, the required substation modifications include the installation of an additional breaker position, metering equipment (including revenue-grade bidirectional meters), and protective relaying. These modifications will be designed and constructed by Oncor (or its designated contractors) at Lone Star's expense, with costs included within the $2,800,000 estimated network upgrade budget.

Oncor's role in the interconnection process is central. As the transmission and distribution service provider, Oncor is the counterparty to the Interconnection Agreement (along with ERCOT), and Oncor is responsible for the design, procurement, and construction of the network upgrades at the Western Permian Substation. The Interconnection Agreement will take the form of a Standard Generation Interconnection Agreement ("SGIA") or equivalent, based on the PUCT-approved standard form, with such modifications as may be necessary to address the specific characteristics of the BESS facility.

E. Interconnection Agreement

The Interconnection Agreement to be executed between Lone Star and Oncor will be based on the standard-form ERCOT interconnection agreement template approved by the PUCT. While the standard form provides a well-established contractual framework, it will need to be adapted to address BESS-specific requirements, including the dual-use nature of the facility (charging and discharging), bidirectional metering, state-of-charge management, and the ESR-specific operating obligations imposed by the ERCOT Protocols.

The key provisions of the Interconnection Agreement are expected to include the following:

(a) Identification of Parties. The Interconnection Agreement will identify Lone Star Storage I, LLC as the interconnection customer and Aldermere & Co. as the transmission service provider. ERCOT may also be identified as a party or third-party beneficiary.

(b) Facility Description. The agreement will describe the facility as a 50 MW / 200 MWh LFP battery energy storage system, including the technical specifications of the PCS inverters, step-up transformer, and gen-tie line.

(c) POI Specifications. The agreement will specify the Western Permian 138 kV Substation as the POI, including the interconnection voltage, metering point, and the physical location of the interconnection.

(d) Network Upgrade Scope and Cost Responsibility. The agreement will set forth the scope of network upgrades identified in the FIS, the estimated cost of $2,800,000, the payment terms (including deposit and true-up provisions), and the allocation of cost responsibility to Lone Star.

(e) Construction Timeline. The agreement will include milestone dates for the construction of both the Lone Star facilities and the Oncor network upgrades, as well as cure provisions for missed milestones.

(f) Metering and Telemetry Requirements. The agreement will specify the metering requirements at the POI, including bidirectional revenue-grade metering, and the telemetry requirements for real-time data communication with ERCOT's Energy Management System.

(g) Operating Protocols and Dispatching. The agreement will set forth the operating requirements for the BESS facility, including compliance with ERCOT's dispatch instructions, voltage control requirements, and frequency response obligations.

(h) Insurance Requirements. The agreement will specify the types and minimum amounts of insurance coverage that Lone Star must maintain during construction and operation of the facility.

(i) Indemnification Provisions. The agreement will include mutual indemnification obligations for losses arising from each party's negligent or willful acts or omissions, as well as specific indemnification for property damage and personal injury at the POI.

(j) Term and Termination. The agreement will specify the initial term, renewal provisions, and the conditions under which either party may terminate the agreement, including cure rights and notice requirements.

(k) Assignment Provisions. Critically, the agreement must include provisions permitting the collateral assignment of the Interconnection Agreement to BRNB as part of the lender's security package. The assignment provisions should include Oncor's consent to the collateral assignment, step-in rights for BRNB upon an event of default under the Credit Agreement, and adequate cure periods for BRNB following notice of a default by Lone Star. These provisions are essential for the bankability of the Interconnection Agreement and will be a key focus of the lender's counsel review.

The expected effective date of the Interconnection Agreement is December 1, 2022, and the expected energization date is July 15, 2023. It is important to note that execution of the Interconnection Agreement is a condition precedent to the first draw under the $26,000,000 Credit Agreement with BRNB. Accordingly, any delay in the execution of the Interconnection Agreement beyond December 1, 2022 could delay financial close and cascade through the Project schedule. The development team should prioritize the finalization of the Interconnection Agreement and maintain regular communication with Oncor's interconnection team to ensure timely execution.

IV. Network Upgrade Cost Allocation

A. ERCOT Cost Allocation Framework

Under the ERCOT Protocols and applicable PUCT rules, interconnecting generation resources are generally responsible for the cost of network upgrades required to accommodate their interconnection to the ERCOT transmission system. This cost allocation methodology places the financial burden of grid reinforcement on the developer seeking to interconnect, rather than on ratepayers or other market participants.

The ERCOT cost allocation framework distinguishes between two categories of interconnection-related costs:

(a) Direct Assignment Facilities. These are facilities that are used solely by the interconnecting resource and are not shared with other users of the transmission system. Examples include the gen-tie line, dedicated metering equipment, and interconnection-specific substation equipment such as the designated breaker position. The cost of direct assignment facilities is borne entirely by the interconnecting resource as a matter of both ERCOT policy and economic logic — these facilities serve no purpose other than to connect the specific project to the grid.

(b) Shared Network Upgrades. These are upgrades to the broader transmission system that are necessitated by the proposed interconnection but that also benefit other users of the grid. Examples include the reconductoring of a transmission line to increase its thermal rating, the addition of capacitor banks or static VAR compensators for voltage support, or the reinforcement of substation bus capacity. Under ERCOT's general approach, the cost of shared network upgrades identified in the FIS is assigned to the interconnecting resource that triggered the need for the upgrades, unless the upgrades separately qualify for inclusion in ERCOT's regional transmission planning process, in which case they may be socialized across ratepayers through the transmission cost recovery mechanism.

The PUCT's Substantive Rule 25.195 governs the recovery of transmission costs in the ERCOT region. Under Rule 25.195, transmission service providers such as Oncor may recover the costs of transmission facilities through rates charged to retail electric providers and end-use customers. However, network upgrades that are assigned to specific interconnecting resources under the ERCOT interconnection process are generally excluded from this rate recovery mechanism and remain the financial responsibility of the interconnecting resource.

A significant distinction between the ERCOT cost allocation framework and those of other ISOs and RTOs bears emphasis. In FERC-jurisdictional markets such as PJM and MISO, interconnecting generators may be entitled to refunds of network upgrade costs through transmission service credits or other mechanisms. Under FERC Order No. 2003 and subsequent orders, the cost of network upgrades funded by interconnection customers may be refunded over time through credits against transmission charges. ERCOT does not provide such refunds. Network upgrade costs paid by an interconnecting resource in ERCOT are, in general, non-refundable. This means that the $2,800,000 in estimated network upgrade costs for the Lone Star Project represents a sunk cost that Lone Star will not recover through credits or refunds from Oncor or ERCOT. This non-refundable nature underscores the importance of accurate cost estimation and adequate budgetary contingency.

B. Estimated Network Upgrade Costs for the Project

The FIS completed in August 2022 identified total estimated network upgrade costs of $2,800,000 for the Lone Star Project. Based on the study results, the anticipated upgrades include the following:

(a) Substation Modifications at Western Permian 138 kV Substation. The FIS identified the need for the addition of a dedicated breaker position at the Western Permian Substation to accommodate the new interconnection. This includes the installation of a 138 kV circuit breaker, bus extension work, revenue-grade bidirectional metering equipment, and protection and control system upgrades (including relay settings and communication infrastructure). These substation modifications represent the largest single component of the estimated network upgrade costs.

(b) Potential Transmission Line Reconductoring or Reinforcement. The FIS identified potential thermal limit violations on downstream transmission facilities under certain contingency scenarios. To address these violations, limited reconductoring or reinforcement of affected transmission lines may be required. The scope and cost of this work will be further defined in the Facilities Study.

(c) Communication and SCADA Integration. The interconnection of a new generation resource requires integration with the Supervisory Control and Data Acquisition ("SCADA") and telecommunications systems used by Oncor and ERCOT for real-time monitoring and control of the transmission system. This includes the installation of remote terminal units, fiber optic or microwave communication links, and integration with ERCOT's Energy Management System.

These network upgrade costs are payable by Lone Star to Oncor and/or other ERCOT-designated transmission service providers, as directed under the Interconnection Agreement. The $2,800,000 estimate is included within the total $40,000,000 project development budget and is expected to be funded through a combination of debt draws and equity contributions in accordance with the Credit Agreement.

The payment timing for network upgrade costs under ERCOT Interconnection Agreements typically follows a phased approach. An initial deposit is generally required upon execution of the Interconnection Agreement, with additional payments due at specified construction milestones, and the remaining balance due prior to energization. The specific payment schedule will be set forth in the Interconnection Agreement and should be reviewed carefully to ensure alignment with the Project's cash flow projections and the draw schedule under the Credit Agreement.

C. Risk Considerations Regarding Network Upgrade Costs

Several material risk factors relate to the network upgrade costs for the Project. Each is discussed below, together with potential mitigation strategies.

Cost Escalation Risk. The $2,800,000 figure is an estimate derived from the FIS. It is based on the study engineers' assessment of the required upgrades using current (or recent) unit cost assumptions for equipment, materials, and labor. Actual costs may differ — and may be materially higher — upon completion of the Facilities Study, which provides detailed engineering and cost estimates reflecting then-current market conditions. ERCOT Interconnection Agreements typically include true-up provisions under which the interconnecting resource is responsible for the actual cost of network upgrades as finally determined, rather than the FIS estimate. This means that Lone Star could be required to pay more than $2,800,000 if the Facilities Study reveals that the FIS estimate was too low, or if construction costs escalate between the FIS completion date and the date of construction. The true-up mechanism creates an open-ended financial exposure that should be addressed through adequate budgetary contingency.

Restudy Risk. As noted in Section III.C above, if projects ahead of the Lone Star Project in the ERCOT queue at or near the Western Permian Substation modify their scope, withdraw, or achieve COD, the transmission system conditions assumed in the FIS may change. In such event, ERCOT may require the Lone Star FIS to be restudied. A restudy could result in higher network upgrade cost estimates if, for example, a previously assumed network upgrade by an earlier-queued project no longer materializes, shifting the cost burden to the Lone Star Project. Conversely, a restudy could result in lower costs if an earlier-queued project withdraws and relieves a constraint that had been assigned to the Lone Star Project. The timing and outcome of any restudy are uncertain and are largely beyond the control of the development team.

Schedule Risk. The construction of network upgrades at the Western Permian Substation will be managed by Oncor and its contractors, not by Lone Star or Meridian Power. Delays in Oncor's procurement of equipment, scheduling of outages for substation work, or construction of the required modifications could delay the expected energization date of July 15, 2023. Because Lone Star has limited contractual leverage over Oncor's construction timeline (the Interconnection Agreement will impose milestone obligations on Oncor, but the remedies for Oncor's delay may be limited), this represents a significant schedule risk for the Project. A delay in energization could cascade to delay COD beyond August 15, 2023 and potentially beyond the EPC Guaranteed COD of September 1, 2023, triggering consequences under the EPC Agreement and potentially affecting the conversion of the construction loan to a term loan under the Credit Agreement.

Mitigation Strategies. We recommend the following strategies to mitigate these risks:

(i) Cost Cap or Cost-Sharing Mechanism. To the extent achievable, negotiate a cost cap or cost-sharing mechanism in the Interconnection Agreement that limits Lone Star's exposure to network upgrade cost increases above the FIS estimate. We note that the standard-form ERCOT interconnection agreement offers limited flexibility on this point, and Oncor may resist non-standard provisions. Nevertheless, the negotiation should be attempted, particularly given the current market conditions in which transmission service providers have an interest in facilitating new resource interconnections.

(ii) Budgetary Contingency. Include an adequate contingency within the project budget for network upgrade cost increases. We recommend a contingency of 10-15% above the $2,800,000 FIS estimate, or $280,000 to $420,000, bringing the budgeted network upgrade amount to approximately $3,080,000 to $3,220,000.

(iii) EPC Schedule Buffer. Ensure that the EPC Guaranteed COD of September 1, 2023 (with 15-day cure period to September 16, 2023) provides sufficient buffer for interconnection-related delays beyond the expected energization date of July 15, 2023. As discussed in Section VI.B below, the total buffer from expected energization to the last cure date is approximately 63 days, which is adequate but not generous.

(iv) Oncor Coordination. Coordinate closely with Oncor's project management and construction teams to monitor progress on network upgrade construction. Request Oncor's detailed construction schedule and incorporate it into the Project master schedule. Establish regular coordination meetings between Lone Star, Meridian Power, and Oncor.

(v) Independent Engineer Review. Ensure that Norgate Technical Advisors, Inc. (Dr. Phillip S. Reardon, P.E.), the Independent Engineer retained by BRNB, reviews the reasonableness of the network upgrade cost estimate and the feasibility of the construction timeline for network upgrades as part of its lender due diligence report.

D. Gen-Tie Line Considerations

The approximately 1.2-mile, 138 kV overhead gen-tie line connecting the Project site to the Western Permian Substation is classified as a "direct assignment" facility under the ERCOT cost allocation framework. As a direct assignment facility, the cost and construction responsibility for the gen-tie line rests entirely with Lone Star. The gen-tie line is not a shared network upgrade, and its costs are not subject to socialization or recovery through transmission rates.

The gen-tie line costs are understood to be included within the EPC scope under the $31,200,000 fixed-price EPC Contract with Meridian Power. However, we recommend confirming whether the gen-tie line construction is fully within Meridian Power's scope or whether any portion (e.g., the final connection at the Western Permian Substation) is separately contracted. The scope boundary between the EPC Contract and the Interconnection Agreement should be clearly delineated to avoid gaps or overlaps that could create construction coordination issues or cost disputes.

The acquisition of right-of-way easements for the gen-tie route is a critical path item. The gen-tie line crosses one or more parcels between the Project site and the Western Permian Substation, and easement agreements must be secured from the owners of each affected parcel. To the extent the gen-tie route crosses land owned or controlled by PBLH (the lessor under the Ground Lease), the easement rights should be coordinated with, and ideally incorporated into, the Ground Lease. For parcels owned by third parties, separate easement agreements must be negotiated and executed. We recommend that the development team commence easement negotiations immediately, as delays in easement acquisition could jeopardize the gen-tie construction timeline and, by extension, the energization date.

The gen-tie line construction requires appropriate permitting. Ector County Building Permit No. BP-2022-04517, issued October 28, 2022, may cover the gen-tie line construction, but this should be confirmed with the Ector County Permitting Office. The scope of the building permit should be reviewed to determine whether it encompasses the construction of a 138 kV overhead transmission line or whether additional county, state, or utility permits are required. In particular, overhead transmission lines may require coordination with the Texas Department of Transportation if the route crosses or parallels any state-maintained roadways or rights-of-way.

Environmental considerations for the gen-tie route have been preliminarily addressed through a desktop review conducted by the U.S. Fish and Wildlife Service ("USFWS") completed in August 2022. The desktop review found no critical habitat along the gen-tie corridor, and no Endangered Species Act consultation is anticipated. However, the development team should confirm that no additional environmental review (e.g., wetlands delineation, cultural resource survey) is required by any applicable federal, state, or local authority.

V. Regulatory Treatment of BESS Under Texas Law

A. PUCT Jurisdiction Over Energy Storage

The Public Utility Commission of Texas exercises jurisdiction over electric utilities, retail electric providers, and power generation companies operating within the ERCOT market, as established under the Texas Public Utility Regulatory Act ("PURA"), codified at Texas Utilities Code, Title 2, Subtitle B. The PUCT's regulatory authority is implemented through the PUCT Substantive Rules set forth in Title 16, Texas Administrative Code, Chapter 25.

The historical regulatory framework in Texas did not specifically contemplate standalone battery energy storage systems as a distinct category of electric infrastructure. Rather, BESS projects have been treated as generation resources for purposes of both interconnection and market participation, based on their ability to inject power into the ERCOT grid. This classification is pragmatic — it allows BESS projects to utilize the existing interconnection and market participation frameworks designed for generation resources — but it is not without conceptual tension, given that BESS projects also consume power (when charging) and thus share characteristics with load resources.

The PUCT Substantive Rules applicable to generation resources, including registration requirements, market participation rules, and reliability standards, are codified in Chapter 25. A power generation company operating in the ERCOT market must register with the PUCT and comply with applicable rules regarding market conduct, reporting, and reliability. Lone Star should register as a power generation company (or the applicable equivalent classification for energy storage) with the PUCT prior to commencing operations.

Under PURA, a "power generation company" is defined as a person that generates electricity and is intended to cover entities whose primary business is the production of electricity for sale in the wholesale market. Whether a standalone BESS facility — which does not generate electricity in the traditional sense but rather stores and dispatches energy that was generated by other resources — falls squarely within the statutory definition of "power generation company" has been the subject of ongoing discussion among market participants and regulators. To date, the PUCT has not issued a definitive rulemaking or declaratory order specifically resolving this question for standalone storage. In practice, however, BESS projects have been permitted to register and operate as generation resources without challenge, and we are not aware of any pending proceeding that would disrupt this treatment.

Legislative developments have begun to address the regulatory classification of energy storage more directly. Texas Senate Bill 1281, enacted in 2019, included provisions addressing energy storage in the context of integrated resource planning and market participation, although the bill's primary focus was on broader energy market reforms rather than standalone storage classification. Subsequent legislative activity, including proposals in the 87th and 88th Texas Legislatures, has considered more specific statutory definitions and regulatory frameworks for energy storage. The development team should monitor legislative developments that could affect the regulatory classification or permitting requirements for standalone BESS projects in Texas.

B. ERCOT Market Participation for BESS

BESS projects participate in the ERCOT wholesale energy markets as generation resources, using the ESR classification within ERCOT's resource registration framework. A 50 MW / 200 MWh BESS facility such as the Lone Star Project has several market participation options, each of which contributes to the project's revenue stack:

Energy Arbitrage. The most straightforward revenue stream for a BESS project is energy arbitrage — charging the battery during periods of low wholesale energy prices and discharging during periods of high prices. The ERCOT real-time and day-ahead energy markets exhibit significant price volatility, particularly during peak demand periods and grid stress events, creating opportunities for BESS operators to capture price spreads. The four-hour duration of the Lone Star Project (200 MWh) allows the facility to discharge at its full 50 MW capacity for four consecutive hours, which is well-suited to capturing afternoon and evening peak pricing in the ERCOT market.

Ancillary Services. BESS facilities are well-suited to provide ancillary services in the ERCOT market due to their fast response times and operational flexibility. The ancillary services available to the Project include:

• Regulation Up / Regulation Down: Frequency regulation services requiring rapid, automatic adjustments to output in response to system frequency deviations. BESS assets are particularly competitive in the regulation market due to their sub-second response capability.

• Responsive Reserve Service (RRS): A fast-responding reserve product designed to arrest frequency declines following the loss of a large generating unit. RRS requires resources to be capable of ramping to full output within specified timeframes, a capability that is well within the technical envelope of the HD-LFP-200E platform.

• ERCOT Contingency Reserve Service (ECRS): A reserve product introduced to provide additional contingency response capability during periods of elevated grid risk. ECRS requirements have become increasingly significant in the wake of Winter Storm Uri (February 2021) and subsequent ERCOT market reforms.

• Non-Spinning Reserve: A reserve product that does not require the resource to be synchronized to the grid but requires the ability to come online within a specified timeframe. BESS assets can typically qualify for non-spinning reserve if they maintain adequate state-of-charge.

Capacity and Reliability Services. ERCOT is an energy-only market and does not operate a traditional capacity market of the type found in PJM or ISO-NE. However, BESS projects can participate in reliability services and programs designed to ensure adequate resource availability during periods of grid stress. The potential introduction of a performance credit mechanism or other reliability-oriented market construct, currently under discussion at the PUCT and among ERCOT stakeholders, could provide an additional revenue stream for BESS projects. This evolving landscape is discussed further in Section V.D below.

The Project has applied for ERCOT Resource ID LSBESS_01, which is pending final assignment. Upon receipt of the Resource ID, Lone Star will need to complete the ERCOT resource registration process, which involves the submission of a Resource Registration Form containing detailed technical specifications, operating parameters, and telemetry requirements for the BESS facility.

Additionally, Lone Star must either register as a Qualified Scheduling Entity ("QSE") or contract with an existing QSE for scheduling and dispatch services. The QSE is the entity responsible for submitting bids and offers into the ERCOT markets on behalf of the resource, managing the resource's schedule, and communicating dispatch instructions between ERCOT and the facility operator. Given the operational complexity of QSE responsibilities and the administrative burden of QSE registration, it is common for project-level entities such as Lone Star to contract with an established third-party QSE rather than registering as a QSE themselves. We recommend that the development team identify and engage a QSE prior to energization to ensure seamless market participation upon COD.

C. BESS-Specific Regulatory Considerations

Several regulatory considerations are specific to BESS projects and warrant discussion in connection with the Lone Star Project:

Dual-Use Classification. As noted above, BESS projects function as both generation (when discharging) and load (when charging). ERCOT addresses this dual-use nature through the ESR resource category, which allows a single resource to participate in both the supply-side and demand-side of the ERCOT markets. The ESR classification imposes specific study requirements during the interconnection process (e.g., analysis of the facility's impact on the transmission system during both injection and withdrawal) and specific operational obligations during market participation (e.g., state-of-charge management, bidding and offer requirements that account for the finite energy capacity of the storage resource).

Metering. Bidirectional metering is required at the POI to separately measure energy injected into (discharge) and withdrawn from (charge) the ERCOT grid. The separate measurement of charge and discharge volumes is necessary for accurate settlement in the ERCOT wholesale markets, including energy market settlement, ancillary service performance verification, and transmission loss calculations. The metering equipment must meet ERCOT and Oncor specifications for revenue-grade accuracy and must be integrated with Oncor's meter data management systems and ERCOT's settlement systems.

State-of-Charge Management. ERCOT Protocols require ESRs participating in certain ancillary services to maintain minimum state-of-charge levels sufficient to deliver the committed service for the required duration. For example, if the Lone Star Project commits to providing four hours of RRS at 50 MW, it must maintain a state-of-charge of at least 200 MWh (less applicable losses) to ensure it can deliver the committed response. The BMS supplied by Harmon-Dietrich includes state-of-charge monitoring and management capabilities that can be configured to comply with ERCOT's requirements.

Emissions and Environmental Permits. The LFP BESS technology deployed at the Lone Star Project produces no direct air emissions during operation. Accordingly, no air quality permit from the Texas Commission on Environmental Quality ("TCEQ") is required. This is a significant advantage of BESS technology relative to gas-fired peaking resources that would compete for the same grid services. However, construction activity at the Project site, which exceeds one acre in area, triggers the requirement for a TCEQ Stormwater General Permit (Permit No. TXR150000). A Storm Water Pollution Prevention Plan ("SWPPP") was filed with TCEQ in November 2022 in satisfaction of this requirement.

Fire Safety and Hazardous Materials. While not a PUCT regulatory matter per se, the installation of a large-scale LFP battery system raises fire safety and hazardous materials considerations that fall within the jurisdiction of the Ector County Fire marshal and applicable building code authorities. LFP chemistry is generally regarded as more thermally stable than other lithium-ion chemistries (e.g., nickel manganese cobalt or "NMC"), but thermal runaway events, while rare, remain a recognized hazard. The Project should be designed and constructed in compliance with NFPA 855 (Standard for the Installation of Stationary Energy Storage Systems), which provides requirements for fire protection, spacing, ventilation, and emergency response planning for stationary battery installations. Coordination with the Ector County Fire marshal should occur during the permitting and construction phases to ensure that all applicable fire safety requirements are met.

Tax Treatment. The Texas property tax implications for BESS assets should be reviewed by the Project's tax advisors. BESS equipment (batteries, inverters, transformers, and associated balance-of-plant equipment) may be classified as personal property for Texas property tax purposes, and the applicable valuation methodology and exemptions should be analyzed. The Texas Tax Code Chapter 313 limitation on appraised value program, which provided property tax incentives for certain capital-intensive projects, expired on December 31, 2022 and is no longer available for new applications. The development team should evaluate whether any successor incentive programs are available. We also note that Texas does not currently provide a state sales tax exemption specific to standalone energy storage equipment, distinguishing BESS from certain solar and wind manufacturing equipment that may benefit from existing exemptions under the Texas Tax Code.

D. Evolving Regulatory Landscape

The regulatory environment for energy storage in Texas is evolving rapidly, driven by the increasing penetration of BESS projects in the ERCOT market, the lessons learned from Winter Storm Uri and other grid stress events, and the broader energy transition. Several areas of regulatory activity could affect the Lone Star Project during its development, construction, and early operating period:

PUCT Rulemaking Activity. The PUCT has engaged in rulemaking activity related to energy storage and broader market design in the wake of Winter Storm Uri. These rulemakings could affect the regulatory classification of energy storage, the requirements for ESR market participation, or the cost allocation methodology for transmission upgrades. While no pending rulemaking has been identified that would create a material impediment to the Lone Star Project, the regulatory landscape is fluid, and new rulemakings could be initiated at any time. We recommend that the engagement team monitor PUCT dockets on an ongoing basis and alert the development team to any material developments.

ERCOT Protocol Revision Requests (PRRs). The ERCOT stakeholder process regularly considers protocol revision requests that could affect ESR participation in the ERCOT markets. Areas of potential change include ancillary service qualification requirements for ESRs, dispatch protocols for ESRs (including state-of-charge management and must-run obligations), and settlement methodologies for ESR charge and discharge volumes. Changes to any of these protocols could affect the Lone Star Project's market participation strategy and revenue projections. We recommend monitoring the ERCOT Technical Advisory Committee and relevant working groups for PRRs affecting ESRs.

Market Design Changes. The PUCT has been considering significant market design changes for the ERCOT market, including the potential introduction of a performance credit mechanism ("PCM") or other reliability-oriented market construct. A PCM would create a market-based mechanism for compensating resources that provide reliability value to the ERCOT grid, which could provide an additional revenue stream for BESS projects. The details of any PCM — including eligibility criteria, crediting methodology, and market structure — remain under development and are subject to ongoing stakeholder debate. While the introduction of a PCM could be favorable to the Lone Star Project's economics, the timing and ultimate design of any such mechanism are uncertain, and the Project's financial model should not rely on PCM revenues until the mechanism is finalized and implemented.

Recommendation. We recommend that the CBR development team, in coordination with Calderwood & Harkness, establish a regular monitoring protocol for PUCT dockets, ERCOT stakeholder proceedings, and Texas legislative activity that could affect the Lone Star Project. Material developments should be flagged to the engagement team and evaluated for their impact on the Project's regulatory compliance, market participation strategy, and financial projections.

VI. Timeline Analysis: FIS Completion to Energization

A. Critical Path Summary

The critical path for the Lone Star Project from FIS completion to COD encompasses the following key milestones:

The overall duration from FIS completion (August 2022) to expected COD (August 2023) is approximately twelve months. The duration from targeted Interconnection Agreement execution (December 1, 2022) to expected energization (July 15, 2023) is approximately seven and a half months. The duration from targeted financial close and construction mobilization (February 2023) to expected energization is approximately five and a half months. Each of these timelines is achievable based on comparable BESS projects in the ERCOT market but requires disciplined schedule management and timely execution of all predecessor milestones.

A graphical timeline chart illustrating the critical path is set forth in Appendix E to this memorandum.

B. Key Interdependencies and Schedule Risks

The Project schedule is subject to several key interdependencies and risk factors that could affect the achievement of the expected energization and COD dates:

Oncor Construction Timeline. The construction of network upgrades at the Western Permian Substation is on Oncor's schedule and is managed by Oncor's procurement and construction teams, not by Lone Star or Meridian Power. The Lone Star development team has limited control over Oncor's schedule, and delays in Oncor's procurement of equipment (e.g., circuit breaker, metering equipment,

PRIVILEGED AND CONFIDENTIAL — ATTORNEY WORK PRODUCT
CALDERWOOD & HARKNESS LLP 1000 Louisiana Street, Suite 5500 Houston, TX 77002
MEMORANDUM
To: George Trujillo, Partner
From: David Stanton, Lead Associate; Michelle Tsao, Associate
Date: October 2022
Re: Texas Interconnection & ERCOT Regulatory Issues — Lone Star Battery Storage Project (Ector County, TX)
Matter No.: 1015-00003
Client: Calloway-Briggs Renewables Inc.
Right-click to update Table of Contents
I. Executive Summary
This memorandum analyzes the Electric Reliability Council of Texas ("ERCOT") interconnection process, network upgrade cost allocation framework, and the applicable regulatory landscape for battery energy storage systems ("BESS") under Texas law, as each relates to the Lone Star Battery Storage Project (the "Project"). The memorandum has been prepared at the request of Calloway-Briggs Renewables Inc. ("CBR") to support the development team's decision-making in connection with the negotiation and execution of the Project's Interconnection Agreement, and to inform the broader project finance and regulatory compliance strategy.
The Project consists of a 50 MW / 200 MWh lithium iron phosphate ("LFP") battery energy storage system being developed by Lone Star Storage I, LLC ("Lone Star"), a wholly owned Texas limited liability company subsidiary of CBR. The Project is located on a 15-acre parcel in Ector County, Texas (nearest postal address: 4800 West University Boulevard, Odessa, TX 79764). The total project development value is approximately $40,000,000.
The Project has been assigned ERCOT Interconnection Queue No. INR-22-03347, with a pending ERCOT Resource ID of LSBESS_01. The designated Point of Interconnection ("POI") is the Western Permian 138 kV Substation in Ector County, Texas, owned and operated by Aldermere & Co. ("Oncor"). The Full Interconnection Study ("FIS") was completed in August 2022 and identified estimated network upgrade costs of $2,800,000. The Project will be connected to the POI via an approximately 1.2-mile, 138 kV overhead gen-tie line from the Project site, with an on-site step-up transformer converting from the BESS native voltage of 34.5 kV to the interconnection voltage of 138 kV.
The expected energization date is July 15, 2023, with an expected commercial operation date ("COD") of August 15, 2023. The EPC Guaranteed COD under the engineering, procurement, and construction contract with Meridian Power Construction, Inc. ("Meridian Power") is September 1, 2023, with a 15-day cure period. The Interconnection Agreement is targeted for execution on December 1, 2022.
Based on our review, we have reached the following key conclusions:
•  BESS Classification. BESS projects are treated as generation resources under ERCOT protocols for interconnection and market participation purposes. The dual-use nature of BESS (generation on discharge, load on charge) is addressed through ERCOT's Energy Storage Resource ("ESR") classification, which carries specific study and operational requirements.
•  Regulatory Jurisdiction. The Public Utility Commission of Texas ("PUCT") has jurisdiction over electric utilities and power generation companies operating within ERCOT, and the regulatory treatment of standalone BESS is evolving. No material regulatory impediments have been identified for the Project, but ongoing monitoring of PUCT rulemaking activity and ERCOT protocol revisions is advisable.
•  Network Upgrade Costs. The $2,800,000 in estimated network upgrade costs identified in the FIS represent a significant financial obligation that will be borne by Lone Star. These costs are estimates and are subject to adjustment upon completion of detailed engineering. Cost escalation risk should be contractually addressed through contingency budgeting and, to the extent achievable, negotiation of cost caps or true-up protections in the Interconnection Agreement.
•  Timeline Feasibility. The timeline from FIS completion (August 2022) to expected energization (July 15, 2023) is approximately eleven months, and the timeline from targeted Interconnection Agreement execution (December 1, 2022) to expected energization is approximately seven and a half months. Both timelines are achievable but require active schedule management and close coordination with Oncor regarding the construction of network upgrades at the Western Permian Substation.
The balance of this memorandum provides detailed analysis supporting these conclusions and sets forth our specific recommendations for the Project team.
II. Background and Project Description
A. Project Overview
The Project is being developed by CBR, a Texas corporation headquartered at 2200 West Commerce Street, Suite 1400, Houston, TX 77002. CBR was founded in 2014 by Raymond T. Calloway (Chairman & CEO) and Sandra M. Briggs (President & COO). Since its founding, CBR has focused on the development, ownership, and operation of utility-scale renewable energy and energy storage assets within the ERCOT market. As of the date of this memorandum, CBR has approximately 1.2 GW of solar generation capacity and 400 MW of battery energy storage capacity in various stages of development, ranging from early-stage origination through commercial operation. CBR reported annual revenues of approximately $185 million for its fiscal year ending December 31, 2021, reflecting income from its operating portfolio as well as development fee income from projects reaching financial close and commercial operation.
The Project is held through a single-purpose project company, Lone Star Storage I, LLC (Employer Identification Number: 88-1623504), a Texas limited liability company wholly owned by CBR. Lone Star was formed specifically to hold all Project assets, contracts, and permits, consistent with standard project finance structuring requirements. Lone Star's registered agent is CT Agents of Texas, LLC, 1999 Bryan Street, Suite 900, Dallas, TX 75201.
The Project will deploy LFP BESS technology with a nameplate capacity of 50 MW and a storage duration of four hours, providing a total energy storage capacity of 200 MWh. The BESS equipment will be supplied by Harmon-Dietrich Energy Solutions, LLC under its Model HD-LFP-200E platform, which comprises lithium iron phosphate battery modules, ten (10) 5 MW power conversion system ("PCS") inverters, a battery management system ("BMS"), thermal management systems (HVAC), and containerized enclosures. Harmon-Dietrich is a domestic supplier with a manufacturing facility in Greenville, South Carolina, and has delivered over 800 MWh of LFP BESS equipment to projects across the United States. The Equipment Supply Agreement between Lone Star and Harmon-Dietrich has a total value of $18,400,000, with delivery on a FOB Project site basis in four shipments scheduled between March 15, 2023 and June 1, 2023.
The Project site consists of an approximately 15-acre parcel, being a portion of Survey No. 42, Block 42, T-1-S, Texas & Pacific Railroad Company Survey, Ector County, Texas. The site is leased from Permian Basin Land Holdings, LP ("PBLH") under a 25-year Ground Lease agreement, which includes two five-year renewal options, providing Lone Star with a potential term of up to 35 years. The Ground Lease is structured as a standard ground lease for utility-scale energy projects, with provisions for quiet enjoyment, access, and lender recognition.
Meridian Power Construction, Inc. has been selected as the engineering, procurement, and construction contractor for the Project. The EPC Contract is structured as a fixed-price, turnkey contract at a total price of $31,200,000. The EPC Contract scope encompasses site preparation, civil works, foundation construction, equipment installation and commissioning, the gen-tie line, and the on-site step-up transformer. A letter of intent and term sheet were executed with Meridian Power on October 14, 2022, and the definitive EPC Agreement is targeted for execution on December 1, 2022, concurrent with the Interconnection Agreement and other principal project agreements.
B. Capital Structure
The total development value of the Project is $40,000,000, which encompasses all costs from development through commercial operation, including EPC costs, equipment supply, network upgrade costs, development costs, financing costs, legal fees, permitting, insurance, and working capital reserves. The capital structure is as follows:
The debt component consists of a $26,000,000 construction-to-term loan from Brazos River National Bank, N.A. ("BRNB"), representing 65% of the total project development value. The loan will initially fund as a construction facility, converting to a term loan upon achievement of COD and satisfaction of conversion conditions. The equity component totals $14,000,000, of which $9,100,000 (65% of equity) will be contributed by CBR and $4,900,000 (35% of equity) will be contributed by Ridgepoint Capital Partners, LP ("Ridgepoint"), a Houston-based infrastructure investment fund that has co-invested with CBR on prior projects.
The estimated network upgrade costs of $2,800,000, payable by Lone Star to Oncor and/or ERCOT-designated transmission service providers, are included within the $40,000,000 total project development budget and are expected to be funded through a combination of debt draws and equity contributions in accordance with the pro rata funding provisions of the Credit Agreement.
C. Key Dates and Milestones
The following timeline summarizes the key dates and milestones for the Project from inception through expected commercial operation:
The timeline from the filing of the interconnection application in March 2022 to the expected COD in August 2023 spans approximately 17 months, which is within the range of typical development timelines for BESS projects in the ERCOT market. The critical contractual date is the EPC Guaranteed COD of September 1, 2023, which, together with the 15-day cure period, provides an outside date of September 16, 2023 for the achievement of commercial operation without triggering delay liquidated damages under the EPC Agreement.
III. ERCOT Interconnection Process for BESS Projects
A. Overview of ERCOT Interconnection Framework
The Electric Reliability Council of Texas operates as the independent system operator for the Texas Interconnection, the electric grid serving approximately 90% of the state's electric load. Unlike other major independent system operators ("ISOs") and regional transmission organizations ("RTOs") in the United States — such as PJM Interconnection, the Midcontinent Independent System Operator ("MISO"), the California Independent System Operator ("CAISO"), and the New York Independent System Operator ("NYISO") — ERCOT operates largely independently from federal jurisdiction under the Federal Energy Regulatory Commission ("FERC"). This jurisdictional distinction arises from the fact that the Texas Interconnection has only limited asynchronous ties to the Eastern and Western Interconnections, and therefore the ERCOT grid does not engage in interstate commerce in electricity in a manner that would trigger FERC's plenary jurisdiction under the Federal Power Act. As a result, the interconnection of generation resources to the ERCOT grid is governed primarily by Texas state law, the rules of the PUCT, and the ERCOT Protocols and Planning Guides, rather than by FERC's interconnection rules (e.g., FERC Order No. 2003 and its progeny, which govern interconnection in FERC-jurisdictional ISOs and RTOs).
The primary governing documents for the ERCOT interconnection process include the ERCOT Nodal Protocols and the ERCOT Planning Guide. The Planning Guide, particularly Section 5 (Generation Interconnection or Change Request), establishes the procedural framework for the submission, evaluation, and processing of interconnection requests from new generation resources seeking to connect to the ERCOT transmission system. These protocols set forth the application requirements, study procedures, financial security obligations, milestone schedules, and the standard terms upon which interconnection will be granted.
For purposes of the ERCOT interconnection process, BESS projects are classified as generation resources. This classification is significant because it determines the applicable study methodology, queue position rules, financial security requirements, and the form of interconnection agreement. It should be noted, however, that BESS assets possess a dual-use characteristic: they function as generation resources when discharging energy to the grid and as load resources when charging from the grid. ERCOT has addressed this dual nature through the creation of the Energy Storage Resource ("ESR") category within its resource classification framework. The ESR classification carries specific study requirements and operational obligations that are discussed in greater detail in Section V of this memorandum. For interconnection study purposes, a BESS project is evaluated based on its maximum injection capacity (in this case, 50 MW), which determines the scope of the powerflow, short circuit, and stability analyses conducted by ERCOT.
The distinction between the ERCOT interconnection framework and those of FERC-jurisdictional ISOs/RTOs has important practical implications for the Project. Most notably, the absence of FERC jurisdiction means that the interconnection process is not subject to the timelines, dispute resolution mechanisms, or cost allocation methodologies mandated by federal orders. While this affords ERCOT and the PUCT greater flexibility in designing interconnection procedures, it also means that certain protections available to interconnection customers in other regions — such as the refundability of network upgrade costs under certain FERC-approved tariff provisions — may not be available in ERCOT. These cost allocation issues are discussed in detail in Section IV of this memorandum.
B. Interconnection Application and Queue Position
The interconnection process in ERCOT commences with the submission of a Generation Interconnection or Change Request ("GINR") to ERCOT's Planning Department. The GINR is the formal application by which a proposed generation resource (including a BESS project classified as an ESR) requests permission to interconnect to the ERCOT transmission system at a specified point.
Lone Star filed its GINR with ERCOT in March 2022 and was assigned Queue No. INR-22-03347. The application requested interconnection of a 50 MW generation resource (the BESS facility) at the Western Permian 138 kV Substation in Ector County, Texas.
The GINR application requires the submission of detailed project information, including without limitation:
•  A description of the proposed generation resource, including technology type, nameplate capacity (MW), energy storage capacity (MWh, for storage resources), and duration;
•  The geographic location of the proposed facility, with sufficient specificity to identify the site for transmission planning purposes;
•  The requested POI, identified by the name and voltage of the substation or transmission facility at which the resource will interconnect;
•  The expected capacity at which the resource will inject power into the grid;
•  A single-line electrical diagram showing the proposed facility layout, step-up transformer, gen-tie line, and interconnection to the POI;
•  The projected in-service date for the facility; and
•  Evidence of site control (e.g., a lease, option, or deed).
Upon acceptance of the GINR, ERCOT assigns the application a queue position, which determines the order in which competing interconnection requests at the same or electrically proximate POIs will be studied. Queue position is a critical asset in any interconnection process: a project with an earlier queue position benefits from favorable study assumptions because the transmission system is evaluated without the incremental burden of later-queued projects. Conversely, a later-queued project may face higher network upgrade cost estimates or feasibility challenges as a result of the cumulative impact of earlier-queued projects on the available transmission capacity.
ERCOT's queue management rules require interconnection applicants to meet specified milestones and maintain adequate financial security deposits to retain their queue positions. Failure to meet milestones or provide required financial security can result in loss of queue position, which would require the project to reapply and potentially face different (and likely less favorable) study results. For the Lone Star Project, queue position INR-22-03347 should be actively managed to avoid any risk of forfeiture.
The application fee and financial security deposit requirements applicable to the Project are established under the ERCOT Protocols and are scaled based on the size of the proposed resource. These deposits are typically refundable, in whole or in part, upon the interconnection resource achieving commercial operation, but may be forfeited if the project is withdrawn or fails to meet required milestones. We recommend confirming the current status of all financial security deposits associated with Queue No. INR-22-03347 and ensuring that all upcoming milestone requirements are calendared and tracked by the Project development team.
C. Interconnection Study Process
ERCOT employs a multi-phase study process to evaluate proposed generation interconnections. The study process is designed to identify the transmission system impacts of the proposed resource and to determine what, if any, network upgrades are required to accommodate the interconnection reliably. The three principal phases of the study process are as follows:
1. Screening Study. The Screening Study is a preliminary assessment of the available transmission capacity at the requested POI. This study provides a high-level identification of potential constraints on the transmission system that could affect the feasibility of the proposed interconnection. The Screening Study typically involves simplified powerflow analysis and may identify obvious thermal overloads, voltage violations, or stability concerns at the requested POI. The purpose of the Screening Study is to provide the interconnection applicant with early feedback on the viability of its requested interconnection before more detailed (and costly) studies are undertaken. Projects that pass the Screening Study without identification of significant constraints proceed to the Full Interconnection Study.
2. Full Interconnection Study (FIS). The FIS is a comprehensive technical evaluation of the proposed interconnection. The FIS involves detailed powerflow modeling, short circuit analysis, and transient stability analysis of the transmission system with the proposed resource modeled at its full requested injection capacity. The FIS evaluates the transmission system under a range of operating conditions and contingency scenarios (e.g., N-1 contingencies, in which the system is analyzed with one element out of service) to identify any thermal limit violations, voltage performance issues, or stability problems that would result from the addition of the new resource. Based on the results of the FIS, ERCOT identifies the network upgrades (if any) required to accommodate the proposed interconnection and provides an estimated cost for those upgrades. The FIS results serve as the basis for the network upgrade cost allocation to the interconnecting resource and form the foundation of the Interconnection Agreement.
3. Facilities Study. The Facilities Study is a detailed engineering study that provides refined cost estimates and construction specifications for the network upgrades identified in the FIS. The Facilities Study is typically performed by the transmission service provider responsible for constructing the upgrades (in this case, Oncor) and provides the interconnecting resource with a more precise estimate of the total cost of required upgrades. The Facilities Study may confirm the FIS estimate, or it may result in higher or lower cost estimates depending on the outcome of detailed engineering and current material and labor costs.
For the Lone Star Project, the Full Interconnection Study was completed in August 2022. The study modeled a 50 MW injection at the Western Permian 138 kV Substation and analyzed the thermal limits, voltage performance, and stability of the surrounding transmission system under various contingency scenarios. The FIS concluded that the proposed interconnection is feasible, subject to the completion of identified network upgrades at an estimated cost of $2,800,000. A summary of the FIS results is set forth in Appendix C to this memorandum.
It is important to note the risk of restudy in the ERCOT interconnection process. If other projects ahead of the Lone Star Project in the ERCOT queue at or near the Western Permian Substation withdraw, modify their scope, or otherwise change the assumptions upon which the Lone Star FIS was based, ERCOT may require the Lone Star FIS to be restudied. A restudy could result in different network upgrade requirements — either higher or lower — depending on the changed conditions. While a restudy could theoretically reduce the required upgrades (for example, if an earlier-queued project withdraws and relieves a previously identified constraint), it could also increase the required upgrades or identify new constraints. This restudy risk should be monitored through regular review of the ERCOT interconnection queue and communication with ERCOT's Planning Department.
The timeline from Lone Star's interconnection application (March 2022) to completion of the FIS (August 2022) was approximately five months. This timeline is consistent with typical ERCOT processing times for BESS projects requesting interconnection in less congested areas of the ERCOT grid. Interconnection requests in more congested areas, or those involving larger or more complex facilities, may experience longer study timelines.
D. Point of Interconnection — Western Permian 138 kV Substation
The designated POI for the Project is the Western Permian 138 kV Substation, located in Ector County, Texas. The substation is owned and operated by Oncor, which serves as the transmission and distribution service provider in this area of the ERCOT grid. The interconnection will occur at the 138 kV voltage level.
The on-site infrastructure required for the interconnection includes a step-up transformer that will convert the BESS native voltage of 34.5 kV (the output voltage of the PCS inverters) to the 138 kV interconnection voltage. The step-up transformer will be located on the Project site and is included within the EPC scope.
The gen-tie line connecting the Project site to the Western Permian Substation will consist of an approximately 1.2-mile overhead transmission line rated at 138 kV. The gen-tie line will be owned and maintained by Lone Star. The routing of the gen-tie line crosses one or more parcels between the Project site and the substation, necessitating the acquisition of right-of-way easements from the affected landowners. To the extent that any portion of the gen-tie route crosses land owned or controlled by PBLH (the lessor under the Ground Lease), the easement rights should be coordinated with the Ground Lease to ensure consistency and avoid any conflicts between the two instruments. Any portions of the gen-tie route crossing parcels owned by third parties will require separate easement agreements, and we recommend that the development team commence easement negotiations promptly to avoid delays.
At the Western Permian Substation, modifications will be required to accommodate the new interconnection. Based on the FIS results, the required substation modifications include the installation of an additional breaker position, metering equipment (including revenue-grade bidirectional meters), and protective relaying. These modifications will be designed and constructed by Oncor (or its designated contractors) at Lone Star's expense, with costs included within the $2,800,000 estimated network upgrade budget.
Oncor's role in the interconnection process is central. As the transmission and distribution service provider, Oncor is the counterparty to the Interconnection Agreement (along with ERCOT), and Oncor is responsible for the design, procurement, and construction of the network upgrades at the Western Permian Substation. The Interconnection Agreement will take the form of a Standard Generation Interconnection Agreement ("SGIA") or equivalent, based on the PUCT-approved standard form, with such modifications as may be necessary to address the specific characteristics of the BESS facility.
E. Interconnection Agreement
The Interconnection Agreement to be executed between Lone Star and Oncor will be based on the standard-form ERCOT interconnection agreement template approved by the PUCT. While the standard form provides a well-established contractual framework, it will need to be adapted to address BESS-specific requirements, including the dual-use nature of the facility (charging and discharging), bidirectional metering, state-of-charge management, and the ESR-specific operating obligations imposed by the ERCOT Protocols.
The key provisions of the Interconnection Agreement are expected to include the following:
(a) Identification of Parties. The Interconnection Agreement will identify Lone Star Storage I, LLC as the interconnection customer and Aldermere & Co. as the transmission service provider. ERCOT may also be identified as a party or third-party beneficiary.
(b) Facility Description. The agreement will describe the facility as a 50 MW / 200 MWh LFP battery energy storage system, including the technical specifications of the PCS inverters, step-up transformer, and gen-tie line.
(c) POI Specifications. The agreement will specify the Western Permian 138 kV Substation as the POI, including the interconnection voltage, metering point, and the physical location of the interconnection.
(d) Network Upgrade Scope and Cost Responsibility. The agreement will set forth the scope of network upgrades identified in the FIS, the estimated cost of $2,800,000, the payment terms (including deposit and true-up provisions), and the allocation of cost responsibility to Lone Star.
(e) Construction Timeline. The agreement will include milestone dates for the construction of both the Lone Star facilities and the Oncor network upgrades, as well as cure provisions for missed milestones.
(f) Metering and Telemetry Requirements. The agreement will specify the metering requirements at the POI, including bidirectional revenue-grade metering, and the telemetry requirements for real-time data communication with ERCOT's Energy Management System.
(g) Operating Protocols and Dispatching. The agreement will set forth the operating requirements for the BESS facility, including compliance with ERCOT's dispatch instructions, voltage control requirements, and frequency response obligations.
(h) Insurance Requirements. The agreement will specify the types and minimum amounts of insurance coverage that Lone Star must maintain during construction and operation of the facility.
(i) Indemnification Provisions. The agreement will include mutual indemnification obligations for losses arising from each party's negligent or willful acts or omissions, as well as specific indemnification for property damage and personal injury at the POI.
(j) Term and Termination. The agreement will specify the initial term, renewal provisions, and the conditions under which either party may terminate the agreement, including cure rights and notice requirements.
(k) Assignment Provisions. Critically, the agreement must include provisions permitting the collateral assignment of the Interconnection Agreement to BRNB as part of the lender's security package. The assignment provisions should include Oncor's consent to the collateral assignment, step-in rights for BRNB upon an event of default under the Credit Agreement, and adequate cure periods for BRNB following notice of a default by Lone Star. These provisions are essential for the bankability of the Interconnection Agreement and will be a key focus of the lender's counsel review.
The expected effective date of the Interconnection Agreement is December 1, 2022, and the expected energization date is July 15, 2023. It is important to note that execution of the Interconnection Agreement is a condition precedent to the first draw under the $26,000,000 Credit Agreement with BRNB. Accordingly, any delay in the execution of the Interconnection Agreement beyond December 1, 2022 could delay financial close and cascade through the Project schedule. The development team should prioritize the finalization of the Interconnection Agreement and maintain regular communication with Oncor's interconnection team to ensure timely execution.
IV. Network Upgrade Cost Allocation
A. ERCOT Cost Allocation Framework
Under the ERCOT Protocols and applicable PUCT rules, interconnecting generation resources are generally responsible for the cost of network upgrades required to accommodate their interconnection to the ERCOT transmission system. This cost allocation methodology places the financial burden of grid reinforcement on the developer seeking to interconnect, rather than on ratepayers or other market participants.
The ERCOT cost allocation framework distinguishes between two categories of interconnection-related costs:
(a) Direct Assignment Facilities. These are facilities that are used solely by the interconnecting resource and are not shared with other users of the transmission system. Examples include the gen-tie line, dedicated metering equipment, and interconnection-specific substation equipment such as the designated breaker position. The cost of direct assignment facilities is borne entirely by the interconnecting resource as a matter of both ERCOT policy and economic logic — these facilities serve no purpose other than to connect the specific project to the grid.
(b) Shared Network Upgrades. These are upgrades to the broader transmission system that are necessitated by the proposed interconnection but that also benefit other users of the grid. Examples include the reconductoring of a transmission line to increase its thermal rating, the addition of capacitor banks or static VAR compensators for voltage support, or the reinforcement of substation bus capacity. Under ERCOT's general approach, the cost of shared network upgrades identified in the FIS is assigned to the interconnecting resource that triggered the need for the upgrades, unless the upgrades separately qualify for inclusion in ERCOT's regional transmission planning process, in which case they may be socialized across ratepayers through the transmission cost recovery mechanism.
The PUCT's Substantive Rule 25.195 governs the recovery of transmission costs in the ERCOT region. Under Rule 25.195, transmission service providers such as Oncor may recover the costs of transmission facilities through rates charged to retail electric providers and end-use customers. However, network upgrades that are assigned to specific interconnecting resources under the ERCOT interconnection process are generally excluded from this rate recovery mechanism and remain the financial responsibility of the interconnecting resource.
A significant distinction between the ERCOT cost allocation framework and those of other ISOs and RTOs bears emphasis. In FERC-jurisdictional markets such as PJM and MISO, interconnecting generators may be entitled to refunds of network upgrade costs through transmission service credits or other mechanisms. Under FERC Order No. 2003 and subsequent orders, the cost of network upgrades funded by interconnection customers may be refunded over time through credits against transmission charges. ERCOT does not provide such refunds. Network upgrade costs paid by an interconnecting resource in ERCOT are, in general, non-refundable. This means that the $2,800,000 in estimated network upgrade costs for the Lone Star Project represents a sunk cost that Lone Star will not recover through credits or refunds from Oncor or ERCOT. This non-refundable nature underscores the importance of accurate cost estimation and adequate budgetary contingency.
B. Estimated Network Upgrade Costs for the Project
The FIS completed in August 2022 identified total estimated network upgrade costs of $2,800,000 for the Lone Star Project. Based on the study results, the anticipated upgrades include the following:
(a) Substation Modifications at Western Permian 138 kV Substation. The FIS identified the need for the addition of a dedicated breaker position at the Western Permian Substation to accommodate the new interconnection. This includes the installation of a 138 kV circuit breaker, bus extension work, revenue-grade bidirectional metering equipment, and protection and control system upgrades (including relay settings and communication infrastructure). These substation modifications represent the largest single component of the estimated network upgrade costs.
(b) Potential Transmission Line Reconductoring or Reinforcement. The FIS identified potential thermal limit violations on downstream transmission facilities under certain contingency scenarios. To address these violations, limited reconductoring or reinforcement of affected transmission lines may be required. The scope and cost of this work will be further defined in the Facilities Study.
(c) Communication and SCADA Integration. The interconnection of a new generation resource requires integration with the Supervisory Control and Data Acquisition ("SCADA") and telecommunications systems used by Oncor and ERCOT for real-time monitoring and control of the transmission system. This includes the installation of remote terminal units, fiber optic or microwave communication links, and integration with ERCOT's Energy Management System.
These network upgrade costs are payable by Lone Star to Oncor and/or other ERCOT-designated transmission service providers, as directed under the Interconnection Agreement. The $2,800,000 estimate is included within the total $40,000,000 project development budget and is expected to be funded through a combination of debt draws and equity contributions in accordance with the Credit Agreement.
The payment timing for network upgrade costs under ERCOT Interconnection Agreements typically follows a phased approach. An initial deposit is generally required upon execution of the Interconnection Agreement, with additional payments due at specified construction milestones, and the remaining balance due prior to energization. The specific payment schedule will be set forth in the Interconnection Agreement and should be reviewed carefully to ensure alignment with the Project's cash flow projections and the draw schedule under the Credit Agreement.
C. Risk Considerations Regarding Network Upgrade Costs
Several material risk factors relate to the network upgrade costs for the Project. Each is discussed below, together with potential mitigation strategies.
Cost Escalation Risk. The $2,800,000 figure is an estimate derived from the FIS. It is based on the study engineers' assessment of the required upgrades using current (or recent) unit cost assumptions for equipment, materials, and labor. Actual costs may differ — and may be materially higher — upon completion of the Facilities Study, which provides detailed engineering and cost estimates reflecting then-current market conditions. ERCOT Interconnection Agreements typically include true-up provisions under which the interconnecting resource is responsible for the actual cost of network upgrades as finally determined, rather than the FIS estimate. This means that Lone Star could be required to pay more than $2,800,000 if the Facilities Study reveals that the FIS estimate was too low, or if construction costs escalate between the FIS completion date and the date of construction. The true-up mechanism creates an open-ended financial exposure that should be addressed through adequate budgetary contingency.
Restudy Risk. As noted in Section III.C above, if projects ahead of the Lone Star Project in the ERCOT queue at or near the Western Permian Substation modify their scope, withdraw, or achieve COD, the transmission system conditions assumed in the FIS may change. In such event, ERCOT may require the Lone Star FIS to be restudied. A restudy could result in higher network upgrade cost estimates if, for example, a previously assumed network upgrade by an earlier-queued project no longer materializes, shifting the cost burden to the Lone Star Project. Conversely, a restudy could result in lower costs if an earlier-queued project withdraws and relieves a constraint that had been assigned to the Lone Star Project. The timing and outcome of any restudy are uncertain and are largely beyond the control of the development team.
Schedule Risk. The construction of network upgrades at the Western Permian Substation will be managed by Oncor and its contractors, not by Lone Star or Meridian Power. Delays in Oncor's procurement of equipment, scheduling of outages for substation work, or construction of the required modifications could delay the expected energization date of July 15, 2023. Because Lone Star has limited contractual leverage over Oncor's construction timeline (the Interconnection Agreement will impose milestone obligations on Oncor, but the remedies for Oncor's delay may be limited), this represents a significant schedule risk for the Project. A delay in energization could cascade to delay COD beyond August 15, 2023 and potentially beyond the EPC Guaranteed COD of September 1, 2023, triggering consequences under the EPC Agreement and potentially affecting the conversion of the construction loan to a term loan under the Credit Agreement.
Mitigation Strategies. We recommend the following strategies to mitigate these risks:
(i) Cost Cap or Cost-Sharing Mechanism. To the extent achievable, negotiate a cost cap or cost-sharing mechanism in the Interconnection Agreement that limits Lone Star's exposure to network upgrade cost increases above the FIS estimate. We note that the standard-form ERCOT interconnection agreement offers limited flexibility on this point, and Oncor may resist non-standard provisions. Nevertheless, the negotiation should be attempted, particularly given the current market conditions in which transmission service providers have an interest in facilitating new resource interconnections.
(ii) Budgetary Contingency. Include an adequate contingency within the project budget for network upgrade cost increases. We recommend a contingency of 10-15% above the $2,800,000 FIS estimate, or $280,000 to $420,000, bringing the budgeted network upgrade amount to approximately $3,080,000 to $3,220,000.
(iii) EPC Schedule Buffer. Ensure that the EPC Guaranteed COD of September 1, 2023 (with 15-day cure period to September 16, 2023) provides sufficient buffer for interconnection-related delays beyond the expected energization date of July 15, 2023. As discussed in Section VI.B below, the total buffer from expected energization to the last cure date is approximately 63 days, which is adequate but not generous.
(iv) Oncor Coordination. Coordinate closely with Oncor's project management and construction teams to monitor progress on network upgrade construction. Request Oncor's detailed construction schedule and incorporate it into the Project master schedule. Establish regular coordination meetings between Lone Star, Meridian Power, and Oncor.
(v) Independent Engineer Review. Ensure that Norgate Technical Advisors, Inc. (Dr. Phillip S. Reardon, P.E.), the Independent Engineer retained by BRNB, reviews the reasonableness of the network upgrade cost estimate and the feasibility of the construction timeline for network upgrades as part of its lender due diligence report.
D. Gen-Tie Line Considerations
The approximately 1.2-mile, 138 kV overhead gen-tie line connecting the Project site to the Western Permian Substation is classified as a "direct assignment" facility under the ERCOT cost allocation framework. As a direct assignment facility, the cost and construction responsibility for the gen-tie line rests entirely with Lone Star. The gen-tie line is not a shared network upgrade, and its costs are not subject to socialization or recovery through transmission rates.
The gen-tie line costs are understood to be included within the EPC scope under the $31,200,000 fixed-price EPC Contract with Meridian Power. However, we recommend confirming whether the gen-tie line construction is fully within Meridian Power's scope or whether any portion (e.g., the final connection at the Western Permian Substation) is separately contracted. The scope boundary between the EPC Contract and the Interconnection Agreement should be clearly delineated to avoid gaps or overlaps that could create construction coordination issues or cost disputes.
The acquisition of right-of-way easements for the gen-tie route is a critical path item. The gen-tie line crosses one or more parcels between the Project site and the Western Permian Substation, and easement agreements must be secured from the owners of each affected parcel. To the extent the gen-tie route crosses land owned or controlled by PBLH (the lessor under the Ground Lease), the easement rights should be coordinated with, and ideally incorporated into, the Ground Lease. For parcels owned by third parties, separate easement agreements must be negotiated and executed. We recommend that the development team commence easement negotiations immediately, as delays in easement acquisition could jeopardize the gen-tie construction timeline and, by extension, the energization date.
The gen-tie line construction requires appropriate permitting. Ector County Building Permit No. BP-2022-04517, issued October 28, 2022, may cover the gen-tie line construction, but this should be confirmed with the Ector County Permitting Office. The scope of the building permit should be reviewed to determine whether it encompasses the construction of a 138 kV overhead transmission line or whether additional county, state, or utility permits are required. In particular, overhead transmission lines may require coordination with the Texas Department of Transportation if the route crosses or parallels any state-maintained roadways or rights-of-way.
Environmental considerations for the gen-tie route have been preliminarily addressed through a desktop review conducted by the U.S. Fish and Wildlife Service ("USFWS") completed in August 2022. The desktop review found no critical habitat along the gen-tie corridor, and no Endangered Species Act consultation is anticipated. However, the development team should confirm that no additional environmental review (e.g., wetlands delineation, cultural resource survey) is required by any applicable federal, state, or local authority.
V. Regulatory Treatment of BESS Under Texas Law
A. PUCT Jurisdiction Over Energy Storage
The Public Utility Commission of Texas exercises jurisdiction over electric utilities, retail electric providers, and power generation companies operating within the ERCOT market, as established under the Texas Public Utility Regulatory Act ("PURA"), codified at Texas Utilities Code, Title 2, Subtitle B. The PUCT's regulatory authority is implemented through the PUCT Substantive Rules set forth in Title 16, Texas Administrative Code, Chapter 25.
The historical regulatory framework in Texas did not specifically contemplate standalone battery energy storage systems as a distinct category of electric infrastructure. Rather, BESS projects have been treated as generation resources for purposes of both interconnection and market participation, based on their ability to inject power into the ERCOT grid. This classification is pragmatic — it allows BESS projects to utilize the existing interconnection and market participation frameworks designed for generation resources — but it is not without conceptual tension, given that BESS projects also consume power (when charging) and thus share characteristics with load resources.
The PUCT Substantive Rules applicable to generation resources, including registration requirements, market participation rules, and reliability standards, are codified in Chapter 25. A power generation company operating in the ERCOT market must register with the PUCT and comply with applicable rules regarding market conduct, reporting, and reliability. Lone Star should register as a power generation company (or the applicable equivalent classification for energy storage) with the PUCT prior to commencing operations.
Under PURA, a "power generation company" is defined as a person that generates electricity and is intended to cover entities whose primary business is the production of electricity for sale in the wholesale market. Whether a standalone BESS facility — which does not generate electricity in the traditional sense but rather stores and dispatches energy that was generated by other resources — falls squarely within the statutory definition of "power generation company" has been the subject of ongoing discussion among market participants and regulators. To date, the PUCT has not issued a definitive rulemaking or declaratory order specifically resolving this question for standalone storage. In practice, however, BESS projects have been permitted to register and operate as generation resources without challenge, and we are not aware of any pending proceeding that would disrupt this treatment.
Legislative developments have begun to address the regulatory classification of energy storage more directly. Texas Senate Bill 1281, enacted in 2019, included provisions addressing energy storage in the context of integrated resource planning and market participation, although the bill's primary focus was on broader energy market reforms rather than standalone storage classification. Subsequent legislative activity, including proposals in the 87th and 88th Texas Legislatures, has considered more specific statutory definitions and regulatory frameworks for energy storage. The development team should monitor legislative developments that could affect the regulatory classification or permitting requirements for standalone BESS projects in Texas.
B. ERCOT Market Participation for BESS
BESS projects participate in the ERCOT wholesale energy markets as generation resources, using the ESR classification within ERCOT's resource registration framework. A 50 MW / 200 MWh BESS facility such as the Lone Star Project has several market participation options, each of which contributes to the project's revenue stack:
Energy Arbitrage. The most straightforward revenue stream for a BESS project is energy arbitrage — charging the battery during periods of low wholesale energy prices and discharging during periods of high prices. The ERCOT real-time and day-ahead energy markets exhibit significant price volatility, particularly during peak demand periods and grid stress events, creating opportunities for BESS operators to capture price spreads. The four-hour duration of the Lone Star Project (200 MWh) allows the facility to discharge at its full 50 MW capacity for four consecutive hours, which is well-suited to capturing afternoon and evening peak pricing in the ERCOT market.
Ancillary Services. BESS facilities are well-suited to provide ancillary services in the ERCOT market due to their fast response times and operational flexibility. The ancillary services available to the Project include:
•  Regulation Up / Regulation Down: Frequency regulation services requiring rapid, automatic adjustments to output in response to system frequency deviations. BESS assets are particularly competitive in the regulation market due to their sub-second response capability.
•  Responsive Reserve Service (RRS): A fast-responding reserve product designed to arrest frequency declines following the loss of a large generating unit. RRS requires resources to be capable of ramping to full output within specified timeframes, a capability that is well within the technical envelope of the HD-LFP-200E platform.
•  ERCOT Contingency Reserve Service (ECRS): A reserve product introduced to provide additional contingency response capability during periods of elevated grid risk. ECRS requirements have become increasingly significant in the wake of Winter Storm Uri (February 2021) and subsequent ERCOT market reforms.
•  Non-Spinning Reserve: A reserve product that does not require the resource to be synchronized to the grid but requires the ability to come online within a specified timeframe. BESS assets can typically qualify for non-spinning reserve if they maintain adequate state-of-charge.
Capacity and Reliability Services. ERCOT is an energy-only market and does not operate a traditional capacity market of the type found in PJM or ISO-NE. However, BESS projects can participate in reliability services and programs designed to ensure adequate resource availability during periods of grid stress. The potential introduction of a performance credit mechanism or other reliability-oriented market construct, currently under discussion at the PUCT and among ERCOT stakeholders, could provide an additional revenue stream for BESS projects. This evolving landscape is discussed further in Section V.D below.
The Project has applied for ERCOT Resource ID LSBESS_01, which is pending final assignment. Upon receipt of the Resource ID, Lone Star will need to complete the ERCOT resource registration process, which involves the submission of a Resource Registration Form containing detailed technical specifications, operating parameters, and telemetry requirements for the BESS facility.
Additionally, Lone Star must either register as a Qualified Scheduling Entity ("QSE") or contract with an existing QSE for scheduling and dispatch services. The QSE is the entity responsible for submitting bids and offers into the ERCOT markets on behalf of the resource, managing the resource's schedule, and communicating dispatch instructions between ERCOT and the facility operator. Given the operational complexity of QSE responsibilities and the administrative burden of QSE registration, it is common for project-level entities such as Lone Star to contract with an established third-party QSE rather than registering as a QSE themselves. We recommend that the development team identify and engage a QSE prior to energization to ensure seamless market participation upon COD.
C. BESS-Specific Regulatory Considerations
Several regulatory considerations are specific to BESS projects and warrant discussion in connection with the Lone Star Project:
Dual-Use Classification. As noted above, BESS projects function as both generation (when discharging) and load (when charging). ERCOT addresses this dual-use nature through the ESR resource category, which allows a single resource to participate in both the supply-side and demand-side of the ERCOT markets. The ESR classification imposes specific study requirements during the interconnection process (e.g., analysis of the facility's impact on the transmission system during both injection and withdrawal) and specific operational obligations during market participation (e.g., state-of-charge management, bidding and offer requirements that account for the finite energy capacity of the storage resource).
Metering. Bidirectional metering is required at the POI to separately measure energy injected into (discharge) and withdrawn from (charge) the ERCOT grid. The separate measurement of charge and discharge volumes is necessary for accurate settlement in the ERCOT wholesale markets, including energy market settlement, ancillary service performance verification, and transmission loss calculations. The metering equipment must meet ERCOT and Oncor specifications for revenue-grade accuracy and must be integrated with Oncor's meter data management systems and ERCOT's settlement systems.
State-of-Charge Management. ERCOT Protocols require ESRs participating in certain ancillary services to maintain minimum state-of-charge levels sufficient to deliver the committed service for the required duration. For example, if the Lone Star Project commits to providing four hours of RRS at 50 MW, it must maintain a state-of-charge of at least 200 MWh (less applicable losses) to ensure it can deliver the committed response. The BMS supplied by Harmon-Dietrich includes state-of-charge monitoring and management capabilities that can be configured to comply with ERCOT's requirements.
Emissions and Environmental Permits. The LFP BESS technology deployed at the Lone Star Project produces no direct air emissions during operation. Accordingly, no air quality permit from the Texas Commission on Environmental Quality ("TCEQ") is required. This is a significant advantage of BESS technology relative to gas-fired peaking resources that would compete for the same grid services. However, construction activity at the Project site, which exceeds one acre in area, triggers the requirement for a TCEQ Stormwater General Permit (Permit No. TXR150000). A Storm Water Pollution Prevention Plan ("SWPPP") was filed with TCEQ in November 2022 in satisfaction of this requirement.
Fire Safety and Hazardous Materials. While not a PUCT regulatory matter per se, the installation of a large-scale LFP battery system raises fire safety and hazardous materials considerations that fall within the jurisdiction of the Ector County Fire marshal and applicable building code authorities. LFP chemistry is generally regarded as more thermally stable than other lithium-ion chemistries (e.g., nickel manganese cobalt or "NMC"), but thermal runaway events, while rare, remain a recognized hazard. The Project should be designed and constructed in compliance with NFPA 855 (Standard for the Installation of Stationary Energy Storage Systems), which provides requirements for fire protection, spacing, ventilation, and emergency response planning for stationary battery installations. Coordination with the Ector County Fire marshal should occur during the permitting and construction phases to ensure that all applicable fire safety requirements are met.
Tax Treatment. The Texas property tax implications for BESS assets should be reviewed by the Project's tax advisors. BESS equipment (batteries, inverters, transformers, and associated balance-of-plant equipment) may be classified as personal property for Texas property tax purposes, and the applicable valuation methodology and exemptions should be analyzed. The Texas Tax Code Chapter 313 limitation on appraised value program, which provided property tax incentives for certain capital-intensive projects, expired on December 31, 2022 and is no longer available for new applications. The development team should evaluate whether any successor incentive programs are available. We also note that Texas does not currently provide a state sales tax exemption specific to standalone energy storage equipment, distinguishing BESS from certain solar and wind manufacturing equipment that may benefit from existing exemptions under the Texas Tax Code.
D. Evolving Regulatory Landscape
The regulatory environment for energy storage in Texas is evolving rapidly, driven by the increasing penetration of BESS projects in the ERCOT market, the lessons learned from Winter Storm Uri and other grid stress events, and the broader energy transition. Several areas of regulatory activity could affect the Lone Star Project during its development, construction, and early operating period:
PUCT Rulemaking Activity. The PUCT has engaged in rulemaking activity related to energy storage and broader market design in the wake of Winter Storm Uri. These rulemakings could affect the regulatory classification of energy storage, the requirements for ESR market participation, or the cost allocation methodology for transmission upgrades. While no pending rulemaking has been identified that would create a material impediment to the Lone Star Project, the regulatory landscape is fluid, and new rulemakings could be initiated at any time. We recommend that the engagement team monitor PUCT dockets on an ongoing basis and alert the development team to any material developments.
ERCOT Protocol Revision Requests (PRRs). The ERCOT stakeholder process regularly considers protocol revision requests that could affect ESR participation in the ERCOT markets. Areas of potential change include ancillary service qualification requirements for ESRs, dispatch protocols for ESRs (including state-of-charge management and must-run obligations), and settlement methodologies for ESR charge and discharge volumes. Changes to any of these protocols could affect the Lone Star Project's market participation strategy and revenue projections. We recommend monitoring the ERCOT Technical Advisory Committee and relevant working groups for PRRs affecting ESRs.
Market Design Changes. The PUCT has been considering significant market design changes for the ERCOT market, including the potential introduction of a performance credit mechanism ("PCM") or other reliability-oriented market construct. A PCM would create a market-based mechanism for compensating resources that provide reliability value to the ERCOT grid, which could provide an additional revenue stream for BESS projects. The details of any PCM — including eligibility criteria, crediting methodology, and market structure — remain under development and are subject to ongoing stakeholder debate. While the introduction of a PCM could be favorable to the Lone Star Project's economics, the timing and ultimate design of any such mechanism are uncertain, and the Project's financial model should not rely on PCM revenues until the mechanism is finalized and implemented.
Recommendation. We recommend that the CBR development team, in coordination with Calderwood & Harkness, establish a regular monitoring protocol for PUCT dockets, ERCOT stakeholder proceedings, and Texas legislative activity that could affect the Lone Star Project. Material developments should be flagged to the engagement team and evaluated for their impact on the Project's regulatory compliance, market participation strategy, and financial projections.
VI. Timeline Analysis: FIS Completion to Energization
A. Critical Path Summary
The critical path for the Lone Star Project from FIS completion to COD encompasses the following key milestones:
The overall duration from FIS completion (August 2022) to expected COD (August 2023) is approximately twelve months. The duration from targeted Interconnection Agreement execution (December 1, 2022) to expected energization (July 15, 2023) is approximately seven and a half months. The duration from targeted financial close and construction mobilization (February 2023) to expected energization is approximately five and a half months. Each of these timelines is achievable based on comparable BESS projects in the ERCOT market but requires disciplined schedule management and timely execution of all predecessor milestones.
A graphical timeline chart illustrating the critical path is set forth in Appendix E to this memorandum.
B. Key Interdependencies and Schedule Risks
The Project schedule is subject to several key interdependencies and risk factors that could affect the achievement of the expected energization and COD dates:
Oncor Construction Timeline. The construction of network upgrades at the Western Permian Substation is on Oncor's schedule and is managed by Oncor's procurement and construction teams, not by Lone Star or Meridian Power. The Lone Star development team has limited control over Oncor's schedule, and delays in Oncor's procurement of equipment (e.g., circuit breaker, metering equipment,

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