PART 2. PUBLIC UTILITY COMMISSION OF TEXAS
CHAPTER 25. SUBSTANTIVE RULES APPLICABLE TO ELECTRIC SERVICE PROVIDERS
SUBCHAPTER S. WHOLESALE MARKETS
The Public Utility Commission of Texas (commission) adopts new 16 Texas Administrative Code (TAC) §25.510, relating to the Texas Energy Fund (TEF) In-ERCOT Generation Loan Program. The commission adopts this rule with changes to the proposed text as published in the December 15, 2023, issue of the Texas Register (48 TexReg 7267). The rule will be republished. New §25.510 implements Public Utility Regulatory Act (PURA) §§34.0104, 34.0106, and 34.0108, created by Senate Bill (S.B.) 2627 as enacted by the 88th Texas Legislature (R.S.). The new rule will establish procedures for applying for a loan for construction of dispatchable electric generation facilities within the ERCOT region, evaluation criteria, and terms for repayment. The new rule will also specify performance standards that will be included in the terms of the loan, to which a loan recipient must adhere. The rule is adopted in Project No. 55826.
The commission received comments on the proposed rule from Advanced Power, Brownsville Public Utilities Board (BPUB), Calpine Corporation (Calpine), Competitive Power Ventures Inc. (CPV), City Public Service Board (CPS Energy), Drax Group, Electric Reliability Council of Texas Inc. (ERCOT), Golden Spread Electric Cooperative Inc. (Golden Spread), Grid Resilience in Texas (GRIT), Hunt Energy Network LLC (HEN), Lower Colorado River Authority (LCRA), LS Power Development LLC (LSP), NRG Energy Inc. (NRG), Shell Energy North America (US) LP (Shell Energy), the Sierra Club, Targa Resources LLC (Targa), Texas Competitive Power Advocates (TCPA), Texas Electric Cooperatives Inc. (TEC), the Texas Oil & Gas Association (TXOGA), the Texas Public Power Association (TPPA), Texas Industrial Energy Consumers (TIEC), USA Compression Partners LLC (USA Compression), Vistra Corp. (Vistra), Wartsila North America Inc. (Wartsila), and WattBridge Texas LLC (WattBridge).
TCPA requested a public hearing, which was held on January 25, 2024. The following entities offered oral comments: Calpine, CPS Energy, Enchanted Rock, HEN, LCRA, LSP, NRG, Sierra Club, Targa, TCPA, TIEC, TPPA, Vistra, Wartsila, and WattBridge.
Note on Definition of Entities
The following terms are used in this order. "Applicant" refers to the entity applying to the In-ERCOT Generation Loan Program under §25.510. "Corporate sponsor" refers to the corporate parent entity of an applicant. Use of this term accommodates a scenario in which a project-specific corporate entity is established to own a newly built facility after the loan application process. If a project entity is formed just prior to the loan application process and therefore lacks history, the credit and experience of the corporate sponsor may be considered. "TEF administrator" refers to the individuals responsible for administering the TEF programs. The term may apply to commission staff or to a contractor hired to assist with certain program functions. The specific duties and responsibilities of any contractor hired to assist with the administration of the TEF programs are defined by the terms of the commission's contract with that entity, which will be publicly available on the commission's website. Decisions of the TEF administrator are subject to the oversight of the commission.
Duties of TEF Administrator and Commission Staff
The commission will evaluate applications for TEF funding with the assistance of commission staff and the contractor hired to perform duties assigned to the commission's TEF administrator. The contractor will be responsible for assessing each application for completeness, providing commission staff with recommendations for funding according to the requirements of PURA §§34.0104 and 34.0106 and the evaluation criteria listed in §25.510, and conducting due diligence on each application to gauge the feasibility of each proposal. Commission staff will review the contractor's recommendations and, again relying on the program's evaluation criteria, will provide recommendations for approval to the commission. The commission will approve an application in consideration of these recommendations, the statutory requirements, and the criteria listed in §25.510.
Evaluation Criteria Preferences
The TEF administrator's review will assess the extent to which an applicant has thoroughly addressed each of the evaluation criteria enumerated in §25.510. An applicant's response to criteria related to electric generation service history and to financial attributes, such as financial modeling, creditworthiness, and risk management strategies, will garner the closest scrutiny. For example, an applicant demonstrating more extensive and relevant generation service experience will receive a more favorable application assessment. Similarly, applicants proposing to use a larger ratio of equity to debt relative to other applications will also achieve a more favorable evaluation. Applications proposing financial structures with corporate guarantees of TEF project debt will also result in a more favorable evaluation.
Although §25.510(f)(1)(A)(iii) establishes as an evaluation criterion the history of generation operations in Texas and the United States, a lack of experience in either location will not disqualify an applicant from receiving a TEF loan. Additionally, applicants proposing financial structures that rely on various forms of debt for the non-TEF portion of the funding will be considered, but preference will be given to applications with equity at the project level. More complex capital structures, such as those with multiple tiers of creditors, may require negotiated intercreditor agreements that can extend time to completion, resulting in a lower score.
Public Comments
The commission invited interested parties to address three questions related to the eligibility requirements of the proposed rule.
1. Should the rule require registration as a power generation company (PGC) with the commission as a condition for eligibility to receive a loan? Why or why not?
Among commenters that favored registration as a PGC, there were differing views as to the timing of the registration. Sierra Club suggested requiring registration as a PGC prior to applying for a TEF loan. WattBridge, HEN, Drax Group, NRG, LSP, and TCPA suggested requiring registration as a PGC prior to loan disbursement but opposed requiring registration at the time of application. Wartsila recommended adding this requirement as a condition to receive the loan but did not specify whether PGC registration should be a condition for eligibility to apply. HEN, Shell Energy, NRG, LSP, and TCPA suggested PGC registration should be received by the commercial operations date (COD) of the generator that is the subject of the loan application per §25.109, relating to Registration by Power Generation Companies and Self-Generators, and continuously maintained for eligibility.
TIEC and Calpine suggested that registration should not be required prior to applying for or receiving TEF funding. However, TIEC stated that a loan recipient should be required to register prior to generating energy as required by PURA and commission rules.
Targa did not oppose a PGC registration requirement if the commission desires applicants for the loan program to be subject to the regulatory requirements for PGCs.
TEC, CPS Energy, TPPA, BPUB, GRIT, TXOGA, Targa, and LCRA opposed a requirement to register as a PGC, because this would exclude municipally owned electric utilities (MOUs) and electric cooperatives. TXOGA suggested that eligibility should be based on new construction or upgrades of 100 megawatts (MW) or more of dispatchable generation, not a company's scope of business. GRIT stated that SB 2627 does not include a requirement to register as a PGC and applying it would potentially discriminate against certain generating facilities without regard for the facilities' potential contributions to the reliable generation of electricity for the ERCOT region.
Commission Response
The commission agrees with commenters who recommended requiring an applicant to register as a PGC prior to receipt of awarded loan funds. PURA §39.351 requires a person to register as a PGC prior to generating electricity in the ERCOT region. Therefore, it is appropriate to require PGC registration for awarded entities, but not require registration as a condition of application on the chance that the commission rejects an applicant's proposal.
However, the commission also agrees with TEC, CPS Energy, TPPA, BPUB and LCRA, who stated that requiring an applicant to register as a PGC would exclude MOUs, electric cooperatives, and river authorities. The commission modifies the rule at (h)(1)(G) to allow an exception to PGC registration for those three types of entities.
The commission disagrees with TXOGA's recommendation to limit eligibility requirements to only the scale of the project. PGC registration is required for all entities other than MOUs, electric cooperatives, and river authorities, notwithstanding upgrades to existing facilities or new construction for the reason noted above. The commission also disagrees with GRIT because PGC registration is required for a person prior to generating electricity in the ERCOT region as discussed above.
2. Should the rule require registration as a Generation Resource (GR) with ERCOT as a condition for eligibility to receive a loan? Why or why not?
Shell Energy, Sierra Club, BPUB, CPS Energy, and TPPA supported requiring registration with ERCOT as a GR. Wartsila and Vistra recommended adding this requirement as a condition to receive the loan but did not specify whether it should be a condition for eligibility to apply.
WattBridge, HEN, Calpine, NRG, LSP, and TCPA opposed requiring registration as a GR with ERCOT at the time of application for a TEF loan. Instead, these parties argued, registration timeline requirements should be consistent with existing ERCOT protocols. Specifically, HEN argued that some applicants might move forward with a project only if the project receives a loan from the TEF. LCRA and TIEC also asserted that registration should be required consistent with existing ERCOT protocols.
Targa did not oppose a GR registration requirement if the commission intends to make loan applicants subject to ERCOT's GR requirements. However, Targa commented that the commission should recognize that a GR that serves critical natural gas infrastructure may need to remain available to serve co-located critical load during an energy emergency, consistent with existing commission rule requirements and House Bill 3648 and S.B. 3, both enacted by the 87th Texas Legislature (R.S.).
GRIT opposed a requirement to register as a GR, arguing that such a requirement is improperly narrow given the much broader eligibility criteria in the statute. GRIT suggested that resources that are registered as Settlement Only Distribution Generators (SODGs), Private Use Networks (PUNs) with dispatchable generation, or GRs with ERCOT should be eligible to receive a TEF loan.
TXOGA, Drax Group, and TEC opposed a requirement to register as a GR.
Commission Response
In order for a generation facility to provide energy and ancillary services to the ERCOT system, be available for reliability unit commitment, and make energy offers, the facility must be registered with ERCOT as a GR. The commission finds that by describing loan-eligible projects as both dispatchable and primarily in service of the ERCOT system under PURA §34.0104(a) and §34.0106(b)(1), the most appropriate ERCOT asset registration type is GR.
The commission modifies §25.510(h) to require an applicant that is awarded a TEF loan to register the facility as a GR in the normal course of the ERCOT commissioning process. This requirement will ensure that these units can be available to ERCOT in the most efficient way.
3. How should the commission evaluate PURA §34.0106(b)'s prohibition against providing a loan to an electric generating facility that will be used primarily to serve an industrial load or private use network (PUN)?
TIEC recommended that eligibility of a "facility" under PURA §34.0106 should be determined by comparing the industrial site's net dependable capacity of generation to the maximum non-coincident peak (NCP) demand of the co-located load. Any new, excess capacity of 100 MW or more should be eligible for TEF participation on a pro-rata basis, according to TIEC's recommendation.
Wartsila agreed with TIEC, noting that excess capacity co-located with an industrial facility or PUN would be exported to the grid for market consumption. Therefore, that capacity would not be used "primarily to serve" the industrial facility or PUN.
Drax Group argued that serving additional load behind the meter should not preclude eligibility for the TEF loan program provided that 100 MW capacity requirement for ERCOT is met.
GRIT recommended that projects with excess dispatchable generation capacity within PUNs and resources behind an industrial customer's meter be eligible to participate in the loan program, provided that the dispatchable generation is primarily available for delivery to the ERCOT grid. GRIT also supported TIEC's comments filed under Project No. 54999, in advance of the September 21st workshop, which stated that there are companies considering building on-site dispatchable generating facilities and may oversize those facilities if the excess capacity were eligible for TEF loans.
LCRA recommended that a facility serving an industrial load or PUN be eligible for a loan if 100 MW of new capacity is dedicated to ERCOT. LCRA stated that if this criterion is met, the facility does not "primarily serve" the industrial load or PUN and is therefore eligible.
LSP recommended the commission evaluate "dual-use projects" based on energy, not on capacity.
Calpine commented that for a generator serving industrial load or within a PUN to qualify, it must always have 100 MW of capacity available for ERCOT wholesale markets, according to PURA §34.0104(a). Calpine expressed concern that allowing industrial load or PUN generation in the eligible pool of applicants potentially increases administrative costs and tasks to ensure the generation project is truly separated from the host load.
Calpine argued that the commission should not interpret §34.0106(b) as "precluding or deprioritizing" those PUN facilities that export full capacity to ERCOT but are also party to an "offtake" agreement with an industrial load that is served not by a PUN but by the ERCOT grid. In such an arrangement, the generator is exporting its power to the grid for market consumption while the dedicated offtaker buys it back pursuant to the terms of a contract. The full power of the facility is used to maintain overall ERCOT system frequency and is therefore primarily used in service of the grid. The generator, in this instance, is primarily serving the ERCOT grid, and has arrangements that are similar to a generator having power sales agreements with other retail electric providers serving residential or commercial customers.
Enchanted Rock suggested that excess dispatchable generation capacity within PUNs and behind industrial customer meters be eligible to participate in this program where dispatchable generation is primarily available for delivery to the ERCOT grid. Enchanted Rock further suggested that, if a percentage threshold is adopted, 90 percent of the total potential annual output from the generating facility should be supplied to the grid.
Shell Energy recommended that any cost directly linked to a PUN be excluded from eligibility for a TEF loan and that the loan should only cover prorated project costs for the total net capacity that will be injected into ERCOT.
Sierra Club urged the commission to focus on resources intended to serve the ERCOT wholesale market and not to allow taxpayer funds to be used for PUNs or industrial load facilities that, for the most part, are intended to self-provide energy to industrial loads.
TEC did not oppose the funding of facilities that are built to serve both the bulk power system and a PUN. TEC recommended that the commission require any entity submitting a loan application for a facility that will serve a PUN or industrial load to provide supporting documentation as to how the facility will support the ERCOT grid.
TCPA commented that the commission should interpret PURA §34.0106(b) to mean that the commission should not use the TEF funds to subsidize private, behind-the-meter generation. TCPA recommended that any costs that are not directly related to the production of electricity and its delivery to the ERCOT grid be excluded from the estimated project costs for the purpose of calculating the eligible loan amounts. Specifically, TCPA referred to facilities that would serve an industrial load in PUNs that are attempting to participate in the TEF.
TPPA submitted comments that were joined by BPUB and CPS Energy. TPPA did not oppose facilities that serve both the bulk power system and a PUN being eligible for the loan but provided a list of factors that the commission should consider for evaluating applications for such facilities.
Commission response
To determine whether an electric generating facility will be used primarily to serve an industrial load or PUN, the adopted rule relies upon a calculation of excess dispatchable capacity of the generation resources located at the facility. An applicant for a TEF loan must attest that it will provide at least the greater of 100 MW or 50 percent of the nameplate capacity to the ERCOT market. For example, a 300 MW co-located facility with a generation resource or resources that dedicates 160 MW to the ERCOT region will be deemed to primarily serve the ERCOT region. However, a 300 MW co-located facility with a generation resource or resources that dedicates 140 MW to the ERCOT region will be considered to primarily serve the associated industrial load or PUN. The capacity of a new facility will be evaluated as a whole--not on a net export basis--and it must exceed 100 MW. Accordingly, the entire facility must not primarily serve an industrial load or PUN. This determination will be based on a comparison between the sum of nameplate capacity of each new or upgraded generation resource at the facility and the maximum NCP demand of the associated industrial load or PUN. The portion of the entire facility's total nameplate capacity that will be expected to serve the industrial load or PUN must be less than 50 percent. Furthermore, the commission will consider the percentage of nameplate capacity of a new or upgraded generation resource that will be used to serve an industrial load or PUN as a factor in evaluating applications. The commission declines to adopt additional factors as recommended by TPPA, because the single factor provides a clear and replicable calculation that determines eligibility.
TXOGA recommended that "primarily serve" should not include critical gas suppliers and critical customers because maintaining energy to those entities is necessary for reliability.
Targa requested clarification on whether a facility may be eligible if the facility has 100 MW of nameplate capacity that either serves critical gas suppliers or critical customers or provides excess energy generation to the grid.
Commission response
The commission declines to accept the recommendation of TXOGA to exclude critical gas suppliers and critical customers when evaluating if the new capacity is primarily serving industrial load or PUN. Whether capacity is used to serve critical gas suppliers or critical customers is not a factor in determining if a facility primarily serves an industrial load or PUN.
3.a. Should the commission prescribe a percentage of total energy output that an electric generating facility must achieve to be eligible for a loan? If so, what percentage should the commission prescribe?
Wartsila disagreed that a percentage of total energy output should be prescribed as a threshold for TEF loan eligibility. Wartsila stated that a facility that provides 100 MW of capacity to ERCOT should be eligible, regardless of how much capacity provided to a PUN.
TIEC opposed an eligibility threshold based on percentage of the generator's output that is exported to the grid and instead recommended using the amount of generation capacity as the threshold. TIEC argued that as long as 100 MW of generation capacity is being dedicated to the ERCOT market, then the facility should be eligible.
LCRA recommended that the eligibility threshold for TEF loan should be a minimum of 100 MW of new capacity dedicated to serving and participating in the ERCOT wholesale market. LCRA suggested this in conjunction with requiring appropriate facility configurations, metering schemes at the outset, and an affidavit from the applicant committing that no less than 100 MW of capacity will be dedicated to serving the grid. LCRA explained that using such factors for the eligibility threshold avoids needless complexity and policing of meter data to determine whether the energy output of the facility met the statutory requirements during a historical look-back period.
GRIT recommended that, if percentage of output is used, an eligibility threshold of 90 percent or greater of the total potential annual energy output from the electric generating facility must be supplied to the ERCOT grid via dispatchable load reduction or export. GRIT noted that a total energy threshold is not necessary for a facility within a PUN if it reserves over 100 MW of dispatchable generating capacity to serve the grid in excess of the capacity reserved to serve the co-located load. GRIT concluded that "primarily serve" is therefore met because a defined amount of capacity is committed to ERCOT and not to on-site loads.
Shell Energy commented that although the total energy output will vary by technology and market price signals, generation facilities must be required to demonstrate the ability to meet more than 50 percent capacity level. Shell Energy also recommended that during emergency conditions, if the facility does not make 100 percent of the net capacity projected in the loan application available to the grid, any liquidated damages from the Engineering, Procurement, and Construction contract should be passed back to the fund as loan pre-payment.
Sierra Club recommended that to the extent funding is available, at least 50.1 percent of the energy from a PUN or industrial load should be intended for the ERCOT wholesale electricity market and that the commission should only allow loans on the part of the generation that serves the larger market.
TEC recommended that the commission develop factors for evaluation, such as the percent of time power flows to ERCOT, ERCOT's functional control of the facility, regular use of the unit, and percentage of output used by ERCOT versus the industrial load or PUN. TEC did not recommend a specific qualifying threshold.
TCPA recommended that, if the commission permits PUNs to qualify for the TEF, it should prescribe a percentage of no less than 51 percent of total facility net output in the ERCOT wholesale market to be eligible for the loan. TCPA further asserted that the eligible amount of the loan should be tied directly to the percentage of total net energy output in the ERCOT wholesale market.
TPPA provided several factors that the commission must consider when evaluating the eligibility of facilities serving both the ERCOT market and an industrial load or PUN. These include assessment of whether the energy generated at the facility's low sustainable limit would initially serve industrial load or PUN or be offered into ERCOT market; percentage of nameplate capacity that is expected to serve load or PUN at any time and under seasonal net capacities for peak load seasons; energy offering practices; number of hours that any energy generated is expected to serve ERCOT; availability of full generation output during emergency conditions; benefits to other industrial processes such as from the use of steam from cogeneration units; and any other factors that the commission deems appropriate.
TIEC opposed an eligibility threshold based on the percentage of the generator's output that is exported to the grid and instead recommended using the amount of capacity as the standard. TIEC argued that as long as 100 MW of generation capacity is dedicated to the ERCOT grid, then the facility is eligible.
TXOGA stated that it would be overly prescriptive to mandate that a specific percentage of a PUN's total energy output serve the grid rather than the PUN or industrial load.
Commission response
The commission determines that the eligibility threshold for a project will be measured by nameplate capacity, rather than energy output. The factors determining security-constrained economic dispatch can be outside a generation entity's control and could affect the amount of its energy output that is exported to the grid. Therefore, it is appropriate to rely on nameplate capacity rather than energy output measured over a period of time as a criterion for project eligibility.
3.b. Should the commission employ another method to ensure that an electric generating facility primarily serves the ERCOT grid? If so, what method is appropriate and why?
Shell Energy argued that a GR must be primarily dedicated to providing energy and ancillary services to the ERCOT market to be eligible for a TEF loan. A facility that is switchable to another grid, must only be able to do so upon approval from ERCOT and would be required to switch back if needed.
As stated above, TEC recommended that the commission develop factors for evaluation, including but not limited to ERCOT's functional control of the facility and regular use of the unit.
TCPA recommended that the commission use North American Electric Reliability Corporation (NERC) Generating Availability Data System (GADS) definitions for "availability", based on the facility's Equivalent Unplanned Outage Factor (EUOF), rather than EAF, and that performance should be calculated on a rolling average of at least 12 months as opposed to on an hourly basis. TCPA recommended that the commission specify a methodology that prohibits a facility from allocating less equivalent outage hours to the portion of the facility serving ERCOT load.
TPPA recommended that the rule include clawback provisions for facilities whose market behaviors did not align with the description in the initial application, and facilities that end up primarily supporting an industrial load or PUN should be considered in default of the loan.
As stated above, TIEC argued that as long as 100 MW of generation capacity is being dedicated to the ERCOT grid, then the facility is eligible to participate in the TEF program.
TXOGA recommended introducing a "Support Service Requirement" that would condition the receipt of the loan on the facility providing certain grid support services during critical periods.
Commission Response
An electric generating facility that will serve an industrial load or a PUN is eligible to apply for a TEF loan if it fulfils the eligibility conditions described under subsection (c). The capacity of a new facility will be evaluated as a whole for purposes of determining if it primarily serves an industrial load or a PUN. Whether the entire facility primarily serves an industrial load or PUN will be based on a comparison between the sum of the nameplate capacity of each new or upgraded generation resource at the facility and the maximum NCP demand of the associated industrial load or PUN. For an electric generating facility that will not provide all capacity exclusively to the ERCOT power region, only the additional cost to upgrade or construct the capacity that exclusively serves the ERCOT region will be eligible for a loan under this program and will be funded proportionally. The commission modifies the rule accordingly.
General Comments
Relationship among Texas Energy Fund Programs
TPPA, TCPA, and Vistra requested clarification on how much of the TEF will be allocated toward each program within each fund: In-ERCOT Generation Loan Program, Completion Bonus Grants (CBG), Grants for Facilities Outside ERCOT Power Region, and the Texas Backup Power Package (BPP). TPPA shared concerns that total appropriations will be depleted in the In-ERCOT Generation Loan Program with none left over for the other three programs.
TPPA requested clarification on how the loan program will interact with the BPP. TPPA alleged that an applicant cannot participate in both the TEF and BPP and recommended this be stated explicitly in the rule.
LCRA stated that knowing whether and to what degree participation in TEF and CBG programs is permissible "will be a significant determinant for entities in deciding whether they will apply for the loan program."
Wartsila favored allowing loan program recipients to be eligible to apply for a CBG, if eligibility requirements are met. Wartsila also recommended that loan program recipients be eligible for a CBG and recommended that evaluations for both programs be independent. Wartsila specifically referred to proposed §25.511(d)(1)(J), relating to Texas Energy Fund Completion Bonus Grant Program, in Project No. 55812. This provision requires "a statement of whether the applicant applied for a loan under 16 TAC §25.510 as well as the commission's determination on the loan application." To reduce bias, Wartsila recommended independent evaluations for both the In-ERCOT Generation Loan Program and the CBG, and that grant applicants who did not receive a loan be considered "equivalently" for the CBG.
Commission Response
PURA Chapter 34 provides independent eligibility and evaluation criteria for each TEF program. While PURA §34.0106(e)(2) allocates an aggregated maximum of $7.2 billion from the TEF to both programs, applicants or projects for each of the two programs need not be related or known in advance. Each TEF program is independent with respect to eligibility and evaluation criteria. Therefore, it is unnecessary to modify proposed §25.510 to refer to other TEF programs.
Because the universe of applicants for each TEF program is not known at this time, the total amount of funds that should be allocated toward each program also cannot be determined. For this reason, the commission declines to revise the proposed rule to add specific amounts to be allocated among each of the four programs.
Regarding Wartsila's comment on independent evaluations, the In-ERCOT Generation Loan and CBG programs have different goals and criteria. Applications to each will be evaluated within the scope of the relevant program. Thus, application, receipt, or denial of a loan does not increase or decrease the likelihood of being awarded a CBG.
Public reporting
TXOGA asked if the commission has considered how the agency will report to stakeholders and the public on the program, if there would be monthly or quarterly updates via the commission open meetings or filings in the appropriate docket, and if there are other considerations, for transparency, that the commission is considering.
Sierra Club recommended making public information on any application for a loan available through the commission's filings interchange and allowing public comments to be made. In addition, Sierra Club suggested that the commission create a quarterly report on any applications received or any loans approved or denied. Sierra Club commented that this would allow policymakers and the public at large to see if the program has been successful in incentivizing new construction of dispatchable generation.
Commission Response
The commission may require public reporting on the TEF at open meetings, but any such specific requirement is beyond the scope of this rulemaking. The commission declines to modify the proposed rule to add any specific public reporting.
MOUs and River Authorities
CPS Energy noted several ways in which the proposed rule appeared to exclude participation by MOUs, while LCRA had similar comments regarding river authorities. Their concerns centered on proposed §25.510(g)(2), which requires the TEF loan to be "the senior debt secured by the electric generating facility to be completed." CPS Energy and LCRA pointed out that, as political subdivisions of the state, they are prevented from pledging their real estate as security, but they can pledge the revenues of their utility systems as security for senior debt. In addition, both MOUs and river authorities have statutory restrictions on the seniority of their debt. For example, CPS Energy stated that "Chapter 1502 places a statutory first lien on gross revenues for payment of operations and maintenance expenses of the system." Because of these statutory limitations applicable to MOUs and river authorities, both CPS Energy and LCRA recommended modifying the proposed rule to allow for their participation. Specifically, LCRA suggested defining "senior debt" as "debt having no senior rights to the security securing the fund loans, but which may be on parity with or equal to the borrower' s other senior debt." CPS Energy also suggested adding a subsection to the proposed rule that lists the relevant security requirements and loan agreements exclusively applicable to MOUs consistent with Texas statutory law.
Commission Response
PURA §34.0104(e) contemplates the inclusion of river authorities and MOUs as potential borrowers in the in-ERCOT Generation Loan Program. The commission acknowledges that these public power entities are subject to other laws governing project financing and the encumbrance of utility assets. Accordingly, the commission modifies subsections (g) and (h) to allow an MOU or river authority to obtain a TEF loan on terms equivalent with corporate applicants.
Timing of Loan Funds
CPV recommended modifying the rule to "allow sponsors to access the program [funds] for construction financing, term financing, or for combined construction and term financing" which could benefit project progression. CPV remarked that this would facilitate initial institutional construction bridge financing with the expectation and commitment of the TEF as "construction take-out financing." CPV stated that this additional flexibility in the program would avoid potential delays in projects that may occur if sponsors purposely delay a project until it qualifies for the TEF.
Commission Response
Under PURA §34.0104, loans combine construction and term financing into a single project loan with a 20-year term. Therefore, the loan structure will not be a series of financings that change from initial construction bridge financing to take-out financing or other loans as hypothesized. The commission declines to modify the rule to allow for serialized loans or refinancings of TEF loans.
Standards for Evaluating Loan Repayment Ability
LSP recommended identifying, well in advance of the notice of intent (NOI) due date, what practices the commission will adopt regarding sizing project debt. LSP suggested applying more conservative standards when evaluating an applicant's ability to repay over the term of the loan and sizing the loan appropriately.
Commission Response
Under PURA §34.0104(b)(2), the TEF loan is for an amount not to exceed of 60 percent of estimated costs of the facility to be constructed. However, a particular applicant's credit profile may not support the maximum statutory loan amount. The amount for which an applicant may qualify cannot be known until after the TEF administrator conducts its due diligence. It is, therefore, unnecessary to identify further detail on sizing project debt.
Debt Sizing and Project Prioritization
LSP requested clarification on how TEF funds would be allocated in the event the total funds requested by qualified loan recipients exceed the available amount. LSP also recommended requiring project applicants to disclose the minimum amount of TEF debt that would make projects viable.
NRG recommended establishing prioritization criteria and prioritizing projects that are in the best position from a project viability standpoint. NRG specifically recommended that priority be given to projects that are close to financial close. Similarly, LCRA suggested prioritizing projects that are at an advanced stage of development and are the most likely to be eligible for CBG.
Vistra disagreed with NRG about prioritizing projects that are nearest to financial close and recommended establishing several tranches to fund loans, each with its own application window.
Commission Response
The commission disagrees with NRG's suggestion to prioritize projects based on their proximity to financial close. One major TEF objective is to solicit proposals to develop up to 10,000 MW of newly installed, dispatchable generation, and the commission seeks to develop as broad a pool of applicants as reasonably possible in order to meet this objective. Prioritizing projects that are closer to financial close unreasonably limits the applicant pool.
Additionally, the commission disagrees with Vistra's suggestion to segregate portions of the TEF into distinct funding tranches. The commission will allocate funds based on the applications received and the goals of the TEF, not an arbitrary amount of funding at a set time. The commission accordingly declines to state the priorities requested by the commenters.
Interconnection
Vistra suggested the rule language, or another commission rule, should expressly state that ERCOT and transmission service providers (TSPs) are obligated to prioritize interconnection of projects awarded TEF loans and should mirror the requirement of SB 2627 that requires ERCOT to prioritize these interconnections.
Commission Response
The prioritization of interconnection for projects awarded a TEF loan is beyond the scope of this rulemaking. Therefore, the commission declines to modify the rule as recommended by Vistra.
Proposed §25.510(b)-Definitions
Proposed §25.510(b) defines certain terms used in the rule.
TIEC recommended adding a definition for the term "electric generating facility" and proposed that it mean "an entire generation unit, or specified portion of a generation unit's capacity." TIEC suggested that the definition would allow facilities serving co-located industrial load that may oversize generation facilities with the intent to sell excess capacity to the ERCOT system, to participate.
LCRA recommended either adding a definition of "senior debt" or for the commission to explicitly document its interpretation of "senior debt" in the preamble adopting the rule, as described further below in response to §25.510(g).
Vistra recommended adding §25.510(b)(3) to define EUOF. Vistra advocated for the use of EUOF instead of the equivalent availability factor (EAF) as the required performance threshold for borrowers.
Commission Response
The commission declines to define "electric generating facility" in the rule because the term is already defined in §25.5.
The commission disagrees with LCRA's recommendation to add to the rule a definition of "senior debt." PURA §34.0104(b)(3) specifies TEF loans to be "the senior debt secured by the facility." However, the commission adds a provision at (g)(2) to allow only MOUs and river authorities to pledge an interest in net revenues of the utility system the TEF-funded facility is a part of, even if the MOU or river authority has previously made a pledge of those same net revenues of the utility system.
The commission declines to use EUOF as the required performance threshold for borrowers. Instead, the commission will rely on ERCOT availability data to determine generation resource performance and modifies §25.510(b)(3) to define the 12-month performance availability factor (PAF) that reflects the use of such ERCOT data.
Proposed §25.510(b)(2)-Definition of COD
Proposed §25.510(b)(2) defines the term "commercial operations date" (COD) as the date on which the electric generating facility has completed all qualification testing administered by ERCOT and is approved for participation in the ERCOT market, as identified by ERCOT in the applicable monthly generator interconnection status (GIS) report.
WattBridge recommended tying the definition of COD to Part 3 approval within the ERCOT commissioning process. WattBridge noted that Part 3 approval would allow a new generator to participate in the day-ahead market.
Vistra recommended the commission accept any ERCOT record demonstrating the COD rather than solely relying on the ERCOT GIS report.
HEN stated that it is unclear what is meant by "completed all qualification testing administered by ERCOT and is approved for participation in the ERCOT market" and recommended removing it. Vistra and HEN recommended removing the phrase "as identified by ERCOT in the applicable monthly generator interconnection status report" from the COD definition. HEN recommended tying COD to ERCOT Part 2 approval and using ERCOT's New Generator Commissioning Checklist.
TPPA and Calpine noted that the definition of COD is different between proposed §25.510 and proposed §25.511 and recommended consistency in definitions across rules.
Commission Response
The commission agrees with Vistra that COD should not depend on the ERCOT monthly GIS report. The commission agrees with commenters that recommended tying COD to the ERCOT generator commissioning checklist and modifies the definition of COD to align it with ERCOT's resource commissioning date as defined in ERCOT protocols. The resource commissioning date represents the conclusion of the commissioning process and indicates a generation resource's fully interconnected status with the ERCOT power region.
The commission agrees with TPPA and Calpine that the definition of COD should be consistent between §25.510 and §25.511. The commission modifies the rule and will subsequently align §25.511 in Project No. 55812.
Proposed §25.510(c)(2) - Eligible Activities
Proposed §25.510(c)(2) describes activities that are eligible for a loan.
Aggregation
TXOGA suggested considering ways to allow for smaller generation units or aggregated units to be eligible for funds from the TEF to disperse needed dispatchable resources throughout the state. GRIT proposed adding language in §25.510(c)(2)(A) to include facilities across multiple locations.
USA Compression recommended aligning §25.510(c)(2) with proposed §25.511(c)(1), which defines "capacity of at least 100 MW" by including all the MWs provided by "(A) The construction of new dispatchable electric generating facilities providing power for the ERCOT region; or (B) The addition of new dispatchable electric generating facilities at an existing location providing power for the ERCOT region." USA Compression stated this modification would incentivize distributed generation in the loan program.
Commission Response
The commission disagrees with the commenters' recommendations to allow entities that aggregate electric generating facilities across multiple locations to apply for TEF funding. To be eligible for TEF funding, a project must be an upgrade of an existing facility or new facility construction and install at least 100 MW in nameplate capacity behind a single point of interconnection. PURA §34.0104(a) explicitly describes an eligible upgrade project as one that would result in the net increase of 100 MW for "each facility." Similarly, construction of new facilities that "each have a generation capacity of at least 100 megawatts" is required for the projects to be eligible for TEF funding.
New eligible activity
TIEC recommended adding a new provision to the eligible activities for a loan: "For an electric generating facility that serves load behind the retail meter, any new net dependable capacity that exceeds the maximum non-coincident peak demand of the co-located loads by at least 100 MW." TIEC suggested the rule should base facility eligibility on the total net dependable capacity of the generation facility in excess of the maximum NCP demand of the associated load.
CPV recommended revising the rule to allow a power project with carbon capture to be eligible for the loan program as a single entity. CPV suggested allowing costs for both energy production and carbon capture to be included in the loan program. CPV noted that if the Environmental Protection Agency's proposed 111B and D regulations take effect as currently written, the regulations would negatively affect plants that do not build decarbonization technology and result in significant extra costs for Combined Cycle Gas Turbine technology and associated carbon capture facility.
Commission Response
TIEC's position regarding net dependable capacity fails to address the term "primarily" in PURA §34.0106(b). Whether an electric generating facility primarily serves a co-located load is based on a comparison between the sum of the nameplate capacity of each generation resource at the new or upgraded facility and the maximum NCP demand of the associated industrial load or PUN. The portion of nameplate capacity that will be expected to serve the industrial load or PUN must be less than 50 percent, and the remaining capacity serving the ERCOT market must be greater than 100 MW. For this reason, the commission declines to modify the proposed rule based on TIEC's suggestion.
The commission clarifies that components not clearly required for generation, such as carbon capture, are not eligible loan costs. Even if such components may be related to generation, carbon capture technology does not result in a net capacity increase for the ERCOT power region, and therefore, such costs are not authorized under PURA §34.0104. Accordingly, the commission declines to make any changes in response to CPV's recommendation to allow estimated costs related to carbon capture devices associated with the facility.
Measuring capacity increase
TPPA recommended clarifying that the 100 MW requirement is based on nameplate capacity rather than summer or winter net dependable capability.
Calpine requested that the commission measure "net increase" for upgrades to existing facilities based on a facility's average High Sustained Limit (HSL) in the year prior to filing for a TEF loan. Calpine advised against measuring "net increase" using the facility's installed capacity rating, because the installed capacity rating is the maximum power that a generating unit can produce during normal sustained operating conditions as specified by the equipment manufacturer.
Commission Response
The commission agrees with TPPA that the 100 MW "net increase" eligibility threshold should be measured by nameplate capacity and modifies the provision accordingly. PURA §34.0104 does not establish a preference for seasonal capacity ratings and, therefore, consideration of a project's potential to operate during normal conditions is appropriate. The commission disagrees with Calpine that "net increase" for upgrades should be calculated based on average HSL because this measurement cannot be applied to new construction. To quantify capacity during application evaluation, the commission must use a standard and easily identifiable metric that is relevant to both new construction and upgrades to existing facilities.
Definition of "new construction" and "upgrades to existing"
LSP suggested clarifying the categories of "new construction" and "upgrades to existing." LSP recommended classifying the addition of a new prime mover and generator set at an existing power plant as "new construction." LSP proposed limiting "upgrades to existing" to the modifications of an existing prime mover or generator.
Vistra suggested mirroring statute by removing the word "new" in "new construction" as the term "new construction" is undefined and injects uncertainty into determinations of eligibility. Vistra recommended replacing the word "new" in proposed §25.510(c)(2)(A) with a cross reference to §25.510(c)(4)(C) or removing it.
Commission Response
The commission modifies the rule to clarify that "new construction" refers to an instance when an electric generating facility will be built where no point of interconnection exists, while "upgrades to existing" refers to construction where a point of interconnection already exists, and an additional point of interconnection is not required for the deliverability of energy from the upgraded capacity.
Proposed §25.510(c)(3)-Eligibility Requirements for Proposed Facility
Proposed §25.510(c)(3) defines the requirements to which a proposed facility must adhere.
Golden Spread and TEC held similar positions regarding switchable facilities. Golden Spread advised that existing facilities that serve a non-ERCOT interconnection should be eligible for loans if the existing facility newly interconnects to ERCOT. Golden Spread requested modification to the language to recognize that switchable resources may not always provide power to the ERCOT grid during the term of a loan. TEC recommended allowing generators that can provide power to ERCOT and other independent system operators (ISOs) to participate in the program.
TPPA opposed permitting loan awards to facilities capable of switching power from ERCOT to a neighboring regional transmission organization. TPPA expressed concern that a facility could be designed to provide energy to ERCOT (as switchable), receive a loan, then not provide any energy to ERCOT.
Commission Response
The commission declines to modify the rule to include switchable facilities as eligible loan projects. GRs that can switch operations between two separate transmission networks are governed by agreements between the reliability coordinators for those networks, and thus it becomes increasingly difficult to ensure that generation capacity supported by TEF funding primarily provides power to the ERCOT network. The commission modifies the rule at (c)(4)(D) to clarify that projects to construct or operate switchable facilities are not eligible for a TEF loan.
Vistra recommended requiring applicants to register as a "generation entity" because this will ensure the commission's weatherization rules at §25.55 apply.
Commission Response
Facilities that receive loans under this program must register as a GR with ERCOT and therefore must adhere to the requirements of §25.55. The commission modifies §25.510(h) to require an applicant that is awarded a TEF loan to register the facility as a GR in the normal course of the ERCOT commissioning process.
Proposed §25.510(c)(3)(A) and (c)(3)(B)-Eligibility Requirements for Proposed Facility
Proposed §25.510(c)(3) states that a proposed facility must be designed to interconnect and provide power to the ERCOT power region and must be designed to participate in the ERCOT wholesale market.
TPPA recommended the removal of the phrase "be designed to" in §25.510(c)(3)(A) and (c)(3)(B) because a strict reading could allow a facility that is designed, but is ultimately not built, to receive a loan. TPPA noted that a facility could be designed to provide energy to ERCOT (as switchable), receive a loan, then not provide any energy to ERCOT.
Commission Response
The commission disagrees with TPPA's comments because new and upgraded facilities must necessarily be in the design phase of development, not existing, and other provisions of the rule guard against the possibility that an applicant will receive a loan but not build a facility.
Proposed §25.510(c)(4)(A)-Non-Eligible Activities
Proposed §25.510(c)(4)(A) prohibits the construction or operation of an electric energy storage facility from being eligible for a loan.
Sierra Club suggested an amendment to add language that allows for electric energy storage to be included as part of an overall facility, but that portion must be excluded from the application for a loan, and that thermal energy storage facilities be eligible for a loan.
TPPA stated that "electric energy storage facility" is an undefined term and requested clarity on its distinction with "energy storage resource."
Commission Response
The commission disagrees with Sierra Club's proposed modification to the rule. PURA §34.0104(a) states an electric energy storage facility is not eligible. Although it is unnecessary to define the term "electric energy storage facility," the commission notes that the incidental presence of some electric energy storage at a facility is insufficient by itself to classify it as an "electric energy storage facility." Whether the presence of some energy storage renders the facility an electric energy storage facility will be determined on a case-by-case basis and will generally be based on whether the energy storage will be used to support operations or will be used for later resale. With respect to energy storage more broadly, the commission notes that the TEF is directed to "dispatchable electric generating facilities"--not energy storage. Accordingly, to the extent that a dispatchable electric generating facility is configured to store some of its energy output, such storage is outside the scope of this rule. Other types of storage, such as thermal, may be included as part of the proposed facility.
The commission agrees with TPPA that the term "electric energy storage facility" is not explicitly defined. The commission declines to define the term electric energy storage facility but clarifies that "electric energy storage facility" and "energy storage resource" are not synonymous.
Proposed §25.510(c)(4)(B)-Non-Eligible Activities
Proposed §25.510(c)(4)(B) prohibits the construction or operation of a natural gas transmission pipeline from being eligible for a loan.
TPPA recommended adding language to ensure that infrastructure constructed and operated as part of interconnecting the natural gas generation facility to its fuel supply is not excluded from eligibility.
Commission Response
The commission agrees with TPPA's recommendation and modifies the rule to explicitly include natural gas interconnection infrastructure as part of the facility.
Proposed §25.510(c)(4)(D)-Non-Eligible Activities
Proposed §25.510(c)(4)(D) prohibits operations that primarily serve an industrial load or PUN from being eligible for a loan.
TPPA suggested the commission should require an annual affidavit from loan recipients that serve an industrial load or PUN regarding their activities in the wholesale market. TPPA also suggested that commission staff conduct an annual review of these facilities' operations. TPPA noted that these actions would provide assurance that facilities supported by TEF loans primarily serve the overall ERCOT market, rather than individual consumers. TPPA made the same recommendation for §25.510(h)(1)(H), regarding compliance and audit covenants.
Targa recommended allowing generators that serve critical gas suppliers and critical customers to be eligible if the generators also serve ERCOT. Targa cited rules of statutory construction and stated that the commission must examine the changes to PURA since Winter Storm Uri, referring to changes made by S.B. 3, H.B. 3648 (87th Legislature, R.S), and H.B. 5066 (88th Legislature. R.S.). Targa provided redlines consistent with the recommendations.
Calpine recommended prioritizing generators that deliver all generation capacity to the ERCOT system over co-located generators and noted in many instances that a PUN generator or generator serving a dedicated industrial load is in the service of primarily serving its dedicated load and, therefore, cannot also primarily serve the ERCOT wholesale market. Calpine suggested clarifying what else it might mean to "primarily serve an industrial or PUN load." Calpine recommended that a PGC should not be considered as "primarily serving an industrial or PUN load" if it exports its full capacity to the ERCOT grid while also being party to an offtake agreement with an industrial load.
Vistra suggested the commission should not evaluate proposed projects that serve an industrial load or a PUN on the limited grounds of whether the project will be available during an Energy Emergency Alert (EEA). Rather, it recommended that the commission should examine how much output the project will provide to the bulk power system holistically. Vistra recommended the commission prioritize facilities that will participate fully in the market and, if the PUNs are funded, then the loan funding should be appropriately prorated relative to the participation in the market. Vistra also recommended that "Operation" be changed to be "Construction or operation of a facility."
GRIT supported TIEC's comments that, if an electric generating facility is offering 100 MW exclusively to the ERCOT bulk power system, it should qualify regardless of how much capacity it supplies to a co-located load, but if a facility is idle most of the time and is considered by its co-located load as backup, it could offer its currently unused potential to the bulk power system as long as less than 10 percent of its energy output is going toward the co-located load. GRIT provided redlines consistent with its recommendations.
TCPA recommended that the commission not embrace anything less restrictive than what is already contained in the proposed rule. TCPA also recommended avoiding tying eligibility to point in time capacity snapshots or EEA event or NCPs. TCPA suggested focusing on standalone projects first that are dedicated to generation and ERCOT and that, if the projects are not behind the meter and they are a hedge between customer and generator or if the energy is flowing to the transmission system, then it should qualify.
Commission Response:
The commission disagrees with Targa's proposal and declines to provide an exception for proposed facilities that will primarily serve critical gas suppliers and critical customers. Such proposed facilities are subject to the same requirements as other proposed facilities.
The commission agrees with commenters that generation facilities that primarily serve the ERCOT market should be prioritized for funding over facilities that primarily serve dedicated industrial load and clarifies the eligibility conditions for such facilities under subsection (c). The commission also agrees with the redlines provided by Vistra and modifies subsection (c)(4)(D) accordingly.
Proposed §25.510(d)(1)-Notice of Intent (NOI) to Apply
Proposed §25.510(d)(1) states that an applicant must submit an NOI at least 60 days before submitting an application and defines the requirements that must be included.
Sierra Club recommended adding a requirement for information about regulatory and environmental permits in the NOI to apply, including the applicant's efforts to meet such requirements.
Calpine recommended the addition of new rule language to require a Generation Interconnection or Change Request, a completed ERCOT screening study, and a Full Interconnection Study agreement at the NOI stage to demonstrate the applicant has sufficient capital to cover the 40 percent of projected costs not covered by the loan. Calpine asserted that this information would also demonstrate the viability of the proposed facility and construction timeline. Calpine suggested that the applicant should also have demonstrated site control to ERCOT and submit an attestation of compliance with the Lone Star Infrastructure Protection Act under the ERCOT Planning Guide. Calpine urged the development of forms for the NOI, the application, and all other required ancillary documents.
CPV recommended reducing the 60-day period for the NOI to 30 days to reduce unnecessary delays for resources in advanced development stages and approaching the commencement of construction.
WattBridge recommended allowing NOIs so that applicants may apply as soon as possible. WattBridge remarked that it does not see June 1st as the start of application acceptance, but as the date when the first batch of applications is ready for awarding. WattBridge suggested that this approach prevents further compression of the timeline and helps avoid jeopardizing the COD target of Summer 2026.
Commission Response
The commission intends the NOI to serve as a statement of interest and expression of initial project viability for program management and planning purposes only. Incorporating the information requested by Sierra Club and Calpine is unnecessary because it does not relate to loan program administration. However, the commission will require regulatory and environmental compliance information as part of the application phase and will be assessed during the due diligence. Accordingly, the commission declines to modify the rule.
In response to Calpine's request that standardized forms be developed for the application process, the commission will develop a web-based portal to receive information required in the NOI.
The commission agrees with CPV's recommendation to reduce the 60-day period for submission of a NOI. Instead of requiring NOI submission at least 30 days before an application, as CPV suggested, the commission modifies the rule to require an applicant to submit the NOI no later than May 31, 2024, correlating to an application open date of June 1, 2024.
Proposed §25.510(d), (e), and (f)-Notice of Intent to Apply, Application Requirements and Process, and Evaluation Criteria
Proposed §25.510(d) describes requirements for an applicant to submit an NOI and to separately file a letter with the commission. Proposed §25.510(e) defines the application requirements, all of which must be submitted by "the applicant." Proposed §25.510(f) defines the evaluation criteria the commission will use when approving or denying an application, all of which refer to evaluation of "the applicant."
Vistra recommended revisions to the rule to allow a corporate parent of a subsidiary applicant to submit an NOI, application, and supporting information on behalf of its subsidiary because at the time of application, the project company might not be formed, capitalized, or have sufficient stand-alone resources. Vistra further stated that some projects might not be economically viable without a TEF loan, and the program will be more efficient and effective if a corporate parent can apply on behalf of a subsidiary. Vistra proposed changes to allow corporate parents to submit the NOI on behalf of subsidiary applicants. Vistra also recommended that the commission consider the corporate parent's creditworthiness when evaluating the subsidiary's application.
Commission Response
The commission agrees with Vistra that a project entity applicant may not yet exist at the time of the NOI. Accordingly, a corporate sponsor or parent entity may submit an NOI or apply on behalf of a project entity so long as the project entity is the eventual party to the loan agreement and provides appropriate evidence confirming it is the subsidiary of the corporate sponsor or parent. The commission modifies the rule accordingly.
Proposed §25.510(d)(1)(A), (d)(2), and (e)(1)-Notice of Intent to Apply, Application Requirements and Process
Proposed §25.510(d)(1)(A) requires the NOI to include the applicant's corporate name and the name of the electric generating facility for which it seeks a loan. Proposed §25.510(d)(2) states that the applicant must separately and concurrently file a letter with the commission stating the applicant's corporate name and the MW capacity that the requested loan amount will finance. Proposed §25.510(e)(1) states an application must include the applicant's corporate name and the name of the electric generating facility for which it requests a loan.
CPS Energy recommended removing the term "corporate" and replacing it with "legal" in §25.510(d)(1)(A), (d)(2), and (e)(1) because municipalities do not have a corporate name and would therefore be ineligible to apply based on the requirement.
TPPA recommended adding the term "proposed" before "name of the electric generating facility" in §25.510(d)(1)(A) because the name of the electric generating facility may change.
Commission Response
The commission agrees with CPS Energy that an applicant's "legal name" is more appropriate to capture all types of applicants. The commission modifies the rule accordingly. The commission agrees with TPPA that the name of an electric generating facility may change after submission of the NOI. The commission therefore modifies the rule to request the proposed name of the electric generating facility in the NOI.
Proposed §25.510(d)(1)(E)-Notice of Intent to Apply
Proposed §25.510(d)(1)(E) requires that for each electric generating facility, information demonstrating that the applicant is capable of financing project-related costs not supported by a loan awarded under this section to be submitted as part of the NOI.
Advanced Power recommended allowing the applicant to establish its ability to fund the necessary equity through a combination of a non-binding equity commitment(s) and an established track-record of successfully financing thermal generation projects in the United States. Advanced Power also recommended allowing a phased process where a non-binding equity commitment(s) is included as part of the initial NOI for TEF funding, followed by a binding equity agreement closer to financial close and prior to the disbursal of TEF funds where the state's involvement in the financing of the project is known.
NRG recommended allowing applicants to submit an attestation regarding proposed financing of all non-TEF loan amounts. NRG stated this would be simpler than requiring financial statements or equity commitment letters at NOI stage, which is early for a project.
Commission Response
The commission agrees with Advanced Power that it is not commercially reasonable to require an applicant to provide a binding equity agreement at the NOI stage. For the NOI, an applicant proposing to use equity must include a non-binding equity commitment letter to demonstrate that the applicant is capable of financing project-related costs not supported by a TEF loan. For the application, an applicant proposing to use equity must submit a binding equity commitment letter with its application. An applicant proposing to fund the balance of costs through subordinated debt must submit evidence of its ability to fund those costs at both the NOI stage and in its application. The commission modifies (d)(1) and (e)(4)(C)(i) accordingly.
With the exception of a requirement to provide a non-binding equity commitment letter, the commission declines to specify the form or format of information provided in section (d)(1)(E). Accordingly, the commission declines to incorporate NRG's proposed change to allow an applicant to provide an attestation of a proposed financing plan.
Proposed §25.510(d)(2) -NOI to Apply Requirements
Proposed §25.510(d)(2) states that in concurrence with the NOI, the applicant must separately file a letter with the commission stating the applicant's corporate name and the MW capacity that the requested loan amount will finance.
TIEC recommended requiring applicants to include the anticipated COD in the NOI letter separately required by §25.510(d)(2) and also suggested adding language to the rule to track loan program progress at least quarterly for transparency. TIEC commented that the public should have visibility into this program, and the information submitted in the NOI will be publicly available in ERCOT reports later anyway.
TPPA requested clarification on whether the letter filed with the commission is publicly available information.
Calpine recommended requiring a demonstration of creditworthiness at the time of NOI submission. Calpine stated that this will assist the commission in evaluating an applicant's financial fitness and access to financing for the 40 percent of anticipated project costs not covered by the TEF loan.
Commission Response
The commission notes that estimated COD in the NOI may be commercially sensitive information. The fact that some NOI information may become public through ERCOT data tracking does not consider the status of an applicant's business activities at the time of NOI submission. The commission declines TIEC's request to include estimated COD in the letter separately filed under paragraph (d)(2). Further, the commission declines to add specific language to track loan program progress because any such reporting is beyond the scope of this rule.
In response to Calpine's position that the NOI should include a showing of creditworthiness, the commission notes that the NOI is not a TEF loan application. Instead, the NOI will serve as a diagnostic tool to allow the commission to gauge potential program participation. The commission will appraise an applicant's creditworthiness upon submission of an application. The Commission therefore declines to make Calpine's requested change.
The commission confirms that the letter filed pursuant to paragraph (d)(2) will be publicly available.
Proposed §25.510(e)-Application Requirements and Process
Proposed §25.510(e) prescribes the form and manner a loan application must be submitted to the commission.
NRG requested the provision specify June 1, 2024 as the date the commission will begin accepting applications.
TCPA requested communication on whether applications are going to be reviewed in batches with an opening and closing date.
Commission Response
The commission modifies the rule to state that the application process will be open for a minimum of an eight-week window, beginning on June 1, 2024, at 12:00 a.m. and through at least July 27, 2024, at 11:59 p.m. The commission also modifies the rule to allow the executive director to extend the application window by providing public notice of the extension at least 30 days prior to the previously announced window closure date. In addition, the commission further modifies the rule to allow the executive director to open additional application windows if necessary to achieve the objectives of the TEF. The rule is also modified to state that an applicant that submits an NOI will receive a description of the application and due diligence process.
Proposed §25.510(e)(4)(A)-Application Requirements and Process
Proposed §25.510(e)(4)(A) requires an applicant to submit a copy of any information submitted to ERCOT regarding the applicant's attestation of market participant citizenship, ownership, or headquarters.
TPPA recommended requiring a separate attestation directly from the applicant to ensure compliance with the Lone Star Infrastructure Protection Act (LSIPA) in case the applicant has yet not submitted such information to ERCOT by the time it applies for a TEF loan. TPPA explained that if an applicant has not submitted such information to ERCOT at the time of the application because the facility has not yet been constructed and interconnected, the applicant could therefore apply for a TEF loan without providing this information.
Commission Response
The commission agrees with TPPA's recommendation and modifies subsection (e)(4)(A) to require an applicant to submit a direct attestation relating to the information required under this subsection, if this information has not already been submitted to ERCOT.
Proposed §25.510(e)(4)(A), (f)(1)(A)(i), and (f)(1)(A)(iii)-Application Requirements and Process
Proposed §25.510(e)(4)(A) requires applicants to submit information regarding attestation of market participant citizenship, ownership, or headquarters. Proposed §25.510(f)(1)(A)(i) and §f)(1)(A)(iii) establish that the commission will evaluate applications, in part, based on the applicant's history of electricity generation in Texas and the United States.
Wartsila recommended granting equal consideration to applicants from any North American country or applicants with a successful history of electricity generation within North America.
Commission Response
The commission declines to modify the rule as recommended by Wartsila because it is unnecessary and out of scope. The commission's review under PURA §34.0104(c)(1)(C) is limited to an evaluation of each applicant's history of operations in Texas and the United States, but the statute does not preclude evaluation of the applicant's operations in other North American countries.
The commission will evaluate sponsors and applicants based on experience developing, owning, and operating relevant power generation assets in Texas and the United States. However, the commission will evaluate applications holistically, and a lack of experience in Texas or the United States will not in itself disqualify an applicant from being eligible for or receiving a TEF loan.
Proposed §25.510(e)(4)(B)-Applicant's Prior Experience with Dispatchable Electric Generating Facilities
Proposed §25.510(e)(4)(B) details evidence of the applicant's prior experience with siting, permitting, financing, constructing, commissioning, operating, and maintaining dispatchable electric generating facilities to provide reliable electric service in competitive energy markets.
TPPA recommended not requiring evidence of an applicant's prior experience with dispatchable electric generating facilities because this conflicts with PURA §34.0104(c)(1)(C), which requires the commission to evaluate an applicant's entire history of electric generation operations, which may include non-dispatchable generation operational experience. TPPA requested additional information on the necessity of this provision.
Calpine recommended requiring evidence that an applicant has fifteen years of experience with siting, permitting, financing, constructing, commissioning, operating, and maintaining dispatchable electric generating facilities to provide reliable electric service in competitive energy markets.
Commission Response
The commission agrees with TPPA that the word "dispatchable" can be deleted to account for an applicant's experience with any type of generation, not just dispatchable facilities, to align the rule more closely with the statute. The commission modifies the rule accordingly.
The commission rejects Calpine's recommendation to require at least fifteen years of experience because it would unnecessarily limit potentially feasible projects and because the commission will assess an applicant's overall history of electric generation operations as one of the evaluation criteria.
Proposed §25.510(e)(4)(C)(i)-Ability to Fund Project
Proposed §25.510(e)(4)(C)(i) requires evidence of an applicant's creditworthiness, including an equity commitment letter demonstrating the ability to fund the necessary project equity (40 percent of the remaining estimated cost of construction) plus the required three percent construction escrow deposit amount.
CPV supported the proposed rule's requirement for firm equity commitments to be equal to 40 percent of the project cost.
To address possible contingencies not included in the initial estimated cost of construction, Calpine suggested requiring applicants to cover contingency costs with non-TEF sources. Calpine recommended that the additional amount either be five percent of the overall estimated project costs or another amount to be determined on a case-by-case basis, as approved by the commission, based on a quantitative risk analysis. Calpine further recommended that an applicant should be required to confirm that the contingency funds are liquid, immediately available, and unrestricted funds, dedicated exclusively to development of the dispatchable generation facility for the purpose of mitigating the facility's performance risk.
Vistra recommended adding "at least" in front of "40 percent of the remaining estimated cost of construction."
LCRA recommended removing the term "equity" from §25.510(e)(4)(C)(i) while TIEC and CPV also suggested replacing "equity" with "financial commitment letter." LCRA commented that non-TEF costs may be funded through debt, not equity. TIEC stated that applicants may want to borrow less than 60 percent of project costs from TEF and may want to finance the remaining costs rather than use equity and recommended that applicants should be allowed to do so.
Golden Spread recommended reducing the equity commitment from 40 percent to 20 percent because electric cooperatives may be unwilling or unable to contribute 40 percent equity to a construction project.
Commission Response
The commission agrees with Calpine that contingency costs must be covered by non-TEF sources. However, the commission declines to set a particular contingency cost level in the rule because such a determination will be made on a case-by-case basis.
An applicant must provide evidence of its ability, or the ability of the borrower's corporate sponsor, to fund the required balance of 40 percent or more of the project costs that are not financed by a TEF loan. The balance of financing separate from the TEF loan can be structured and proposed at the discretion of the applicant; however, a non-binding equity commitment letter for the balance of costs plus the required three percent construction escrow deposit amount is required under §25.510(d)(1), in accordance with PURA §34.0104(g). The commission modifies the provision accordingly. The commission declines to require a specific equity commitment for the final funding of the non-TEF portion of the financing requirement; however, the commission modifies the proposed rule to state that if an applicant is proposing to use equity to fund any of the non-TEF portion, the applicant must provide a binding equity commitment letter with the application. Therefore, it is unnecessary to use 20 percent as an equity requirement, as requested by Golden Spread. Accordingly, the commission modifies §25.510(e)(4)(c)(i) and (h)(1)(B)(i) to remove the requirement for at least 40 percent equity and to clarify that other sources of funding besides equity contributions may be used to fund the non-TEF portion of the project costs.
Proposed §25.510(e)(4)(C)(ii)-Applicant Financial Statements
Proposed §25.510(e)(4)(C)(ii) requires evidence of an applicant's creditworthiness including financial statements, statements of the applicant's total assets, total liabilities, net worth, and credit ratings issued by major credit rating agencies.
Advanced Power recommended that a lack of credit rating at the time the application is submitted should not disqualify a project from receiving TEF funding; otherwise, the commission risks "significantly limiting the number of applications received to only those larger developers that have a credit rating at the time the application is filed." Instead, Advanced Power proposed that applicants may demonstrate the ability to arrange credit financing and an established track record of successfully financing thermal generation projects. Advanced Power made similar comments on subsection (d)(1)(E).
WattBridge suggested requiring financial statements only if the applicant has financial statements available. WattBridge noted that power plant developers often create a new and separate legal entity for specific projects, and this new entity may not have financial statements prior to financial closing. In addition, WattBridge stated that projects' financial viability to repay the TEF loan hinges on ERCOT market revenues and the generation resource meeting the required availability and performance metrics.
NRG recommended requiring financial statements and associated total assets, liabilities, net worth, and credit ratings to come from the applicant or the entity providing the applicant with the equity commitment letter under §25.510(e)(4)(C)(i).
CPV recommended qualifying the requirement to provide credit ratings with "if applicable" to allow for privately held companies to participate in the TEF.
HEN suggested requiring credit ratings only if the applicant is rated by major credit agencies. Privately held companies may not have a credit rating but can provide financial statements to demonstrate creditworthiness.
Wartsila and GRIT recommended adding three new subparagraphs adopting a holistic review of an applicant's net worth, liquidity, and other financial statements.
Commission Response
The commission modifies the rule to require an applicant to provide financial statements, if available, for itself and its parent company. The commission also clarifies that sponsors or applicants are not required to have credit ratings issued by major credit rating agencies but do need to provide audited financial statements for a minimum of five years. If sponsors or applicants do have credit ratings, those ratings will be considered during the TEF administrator's due diligence.
Proposed §25.510(e)(5)-Application Requirements and Process
Proposed §25.510(e)(5) describes the project information that is required to be included in the application process.
Sierra Club recommended adding a requirement for applicants to show how the facility will contribute to meeting "overall energy use" in the ERCOT region.
Commission Response
The commission declines to modify the rule as requested by the Sierra Club because it is unnecessary given the performance standards that are required under §25.510(h)(1)(A). However, applicants are free to include this information in the narrative response to §25.510(e)(5)(A).
Proposed §25.510(e)(5)(A)-Project Information
Proposed §25.510(e)(5)(A) requires an applicant to provide a narrative explanation that details how the facility will contribute to reliability during peak winter and summer load in the ERCOT region, including the project's plans for ensuring adequate fuel supplies and preparations for compliance with 16 TAC §25.55 (relating to Weather Emergency Preparedness).
Vistra recommended that registration with ERCOT as a generation entity should be required of all facilities receiving state funds, such as from the TEF, to ensure the weatherization requirements of §25.55 apply and to be consistent with SB 2627's goal of improving reliability.
Commission Response
The commission agrees with Vistra and, while registration of the facility's GR as a generation resource with ERCOT already would require the recipient to adhere to the requirements of §25.55, the commission modifies the rule to explicitly require the electric generating facility qualifying for the TEF loan to adhere to the requirements of §25.55.
Proposed §25.510(e)(5)(C)-Project-Specific Information
Proposed §25.510(e)(5)(C) requires an applicant to submit project-specific information that will allow the commission to determine and evaluate the viability and attributes of the electric generating facility.
Shell Energy recommended the commission require that projects undergo a certification of feasibility by an independent engineer to address the feasibility of the project, its location, and all supporting commercial agreements relating to fuel, water, site control, and interconnection.
USA Compression recommended that the application allow applicants to list each "individual electric generating facility" that is part of the applicant's "new/upgraded electric generating facility"; provide separate descriptions of the operational attributes of each individual electric generating facility that is a part of the applicant's new or upgraded electric generating facility; and include separate construction schedules and commercial operations dates for each individual electric generating facility that is a part of the applicant's new/upgraded electric generating facility.
Commission Response
The commission agrees with Shell Energy and adds subsection (f)(3) to the proposed rule to state that an applicant must submit a feasibility study at the applicant's expense, prepared by an independent engineer, that aligns with leading industry practice for review by the TEF administrator. The feasibility study is not required at the time of application but can be included in the application as supporting documentation if it is available.
The commission disagrees with USA Compression's recommendation to permit listing, descriptions, and construction schedules and commercial operations dates for individual facilities because the aggregation of discrete facilities to meet the requirements of a TEF loan is not permissible. However, the commission notes that a single facility may comprise multiple GRs, and additional detail for each GR is appropriate. The commission modifies the provision to explicitly require resource-level detail.
Proposed §25.510(e)(5)(C)(i) - Application Requirements and Process
Proposed §25.510(e)(5)(C)(i) requires a table with the resource operation attributes, including nameplate capacity, seasonal net maximum sustainable ratings during winter and summer, cold and hot temperature start times, and the original equipment manufacturer's estimated EAF calculation in NERC GADS be submitted during the application.
USA Compression recommended the commission prioritize flexible, fast-ramping, multi-hour-duration dispatchable generation projects for In-ERCOT Generation Loans and to add "resource ramp rate" as an attribute as a required field in the table.
Commission Response
Though it is not definitive, ramp rate is an indicator of generator flexibility, which can support reliability. The commission notes that ramp rate is listed in §25.510(f)(1)(A)(iv). Therefore, the commission modifies the rule to align the requested information in §25.510(e) with the evaluation criteria in §25.510(f).
However, the commission declines to specifically prioritize an application for flexible, fast-ramping, multi-hour-duration dispatchable generation projects because the commission prioritizes applications that best meet statutory criteria, and the TEF administrator will assess projects holistically after first accounting for statutory criteria.
Proposed §25.510(e)(5)(C)(i), (f)(1)(A)(ii), and (f)(1)(A)(iv)-Application Requirements and Process, Evaluation Criteria
Proposed §25.510(f)(1)(A)(ii) evaluates the applicant's quality of services and management, as shown by the applicant's prior history of electricity generation in Texas and the United States, and proposed organizational structure for the project for which the applicant seeks a loan. Proposed §25.510(f)(1)(A)(iv) evaluates the applicant's resource operation attributes, including fuel type and heat rate, seasonal net maximum sustainable rating, resource ramp rate, and capacity factor.
Wartsila recommended implementing a three-step framework to evaluate loan applications so that funding is prioritized based on project readiness, financial solvency, and resource attributes. Wartsila suggested that applicants must earn a satisfactory evaluation in each phase of the application process. Wartsila's proposed three-phase evaluation process incorporated the following steps: verification of project diligence and timeline; evaluation of applicant creditworthiness and project suitability; and evaluation of proposed project's resource attributes and benefit to the ERCOT bulk power system.
Commission Response
The commission will evaluate applications for program eligibility based on the requirements enumerated in PURA §§34.0104 and 34.0106 and for compliance with the criteria detailed in §25.510(f). Applications will be assessed based on their response to statutory and regulatory evaluation criteria, which does not necessarily align with a project's phase of development.
Each application will undergo a due diligence review, an evaluation of the applicant's or sponsor's creditworthiness, and an assessment of project feasibility, to include a review of the proposed resource's operational attributes, as detailed in the evaluation criteria enumerated in §25.510(h). Accordingly, it is unnecessary to modify the rule as recommended by Wartsila.
Proposed §25.510(e)(5)(C)(ii)-Project-Specific Information
Proposed §25.510(e)(5)(C)(ii) requires the applicant to submit a statement indicating whether the electric generating facility will serve an industrial load or PUN, and if so, a description of how the electric generating facility will primarily serve and benefit the ERCOT bulk power system given its relationship to an industrial load or PUN. Additionally, the rule requires an applicant to state whether full generation output would be available to the ERCOT bulk power system during any EEA, and provide a copy of any information submitted to ERCOT regarding PUN net generation capacity availability.
HEN recommended revisions to strengthen the requirements for a GR located within a PUN or serving a retail load to qualify for a loan. Specifically, HEN recommended the statement include details of all obligations or commitments of the generating facility to provide capacity to the industrial load or PUN as well as information regarding the facility's metering and interconnection arrangements.
Commission Response
The commission agrees with HEN's recommendation and modifies the rule to specify that a generating facility that is serving an industrial load or PUN must provide an attestation relating to (i) the net nameplate capacity that will be dedicated to ERCOT, (ii) details of the facility's obligations or commitments to the industrial load or PUN, and (iii) availability of its entire available capacity to ERCOT during an energy emergency alert. However, the commission notes that the metering and interconnection arrangements should be reflected on the required one-line diagrams and declines to restate that requirement here.
Proposed §25.510(e)(5)(C)(iii)-Project-Specific Information
Proposed §25.510(e)(5)(C)(iii) states an applicant should provide a one-line diagram of the proposed project, if available.
TPPA requested that the commission provide a definition and clarify the meaning of a "one-line diagram." Specifically, TPPA asked whether the requested one-line diagram would be at the plant level or for transmission planning, as there is a substantial difference between the two. TPPA recommended that, if the one-line diagram is to "locate the project within the ERCOT transmission system" then it be a "firm" requirement and the phrase "if available" be removed from the rule.
Commission Response
The commission notes that the term "one-line diagram" is a generally understood term in the electric industry and does not require a definition. However, the commission agrees that additional clarity regarding the subject matter of the requested "one-line diagram" is appropriate. The commission notes that the requested one-line diagram is at the facility level. The commission also agrees with TPPA's suggestion to remove the phrase "if available," as a proposed one-line diagram should be available at the time of application.
Proposed §25.510(e)(5)(C)(vi) and (e)(5)(C)(xii)-Project-Specific Information
Proposed §25.510(e)(5)(C)(vi) requests a description of the electrical interconnection plan, including, among other things, a copy of the executed standard generation interconnection agreement (SGIA). Proposed §25.510(e)(5)(C)(xii) requests a proposed project schedule with anticipated dates for major project milestones, such as execution of the SGIA.
Vistra and HEN recommended changing the requirements in §25.510(e)(5)(C)(vi) for submitting for the signed SGIA. Vistra suggested removing the SGIA requirement and instead requiring completion only of the screening study as an application prerequisite because it is not required by statute and would "impede the TEF program's ability to meet the statutory deadline of disbursing all initial funds before December 31, 2025." Vistra explained completion of a screening study, which takes 45-90 days, is a reasonable filter to show that an applicant is sufficiently committed to the proposed projects. Vistra also noted other SGIA prerequisites, such as a full interconnection study with the TSP, may take up to a year to complete and that a generator will be incurring administrative, engineering, and legal fees during that time. HEN recommended requiring the provision of the executed interconnection agreement in the loan application only if available because a utility may not execute an SGIA until the full interconnection studies are completed. HEN noted that such a change would also align the provision with 25.510(e)(5)(C)(xii) which requires the proposed project schedule, including the expected date to execute the interconnection agreement.
TPPA requested clarity as to whether an executed SGIA is a requirement for the application or if a timeline with an anticipated date of execution would satisfy both proposed §25.510(e)(5)(C)(vi) and (e)(5)(C)(xii). TPPA also recommended that the rule require a signed letter of intent or memorandum of understanding for MOUs and electric cooperatives instead of a full SGIA because the SGIA requirement would force MOUs and electric cooperatives to execute an interconnection agreement with themselves when interconnecting their own generation to their own transmission facilities.
Wartsila approved of the requirement for a signed SGIA and recommended removing the language "if completed" related to the interconnection screening study found in §25.510(e)(5)(C)(vi).
Commission Response
The commission agrees with commenters that completion of the SGIA is a step that arrives later in project planning and, as a result, requiring applicants to submit a copy of an executed SGIA may unnecessarily limit the number of eligible projects. Therefore, the commission agrees with HEN's recommendation to eliminate the requirement and modifies the provision accordingly. In addition, the commission modifies (e)(5)(C)(vi) to require a copy of the ERCOT screening study and the full interconnection study only if completed. If these studies have not been completed at the time of application, the applicant should provide projected dates for these milestones in its proposed project schedule, as required by (e)(5)(C)(xii). In response to TPPA, the commission modifies (e)(5)(C)(xii) to require a projected date for execution of the SGIA only if applicable.
Proposed §25.510(e)(5)(C)(ix)-Project-Specific Information
Proposed §25.510(e)(5)(C)(ix) requires a list of all required environmental, construction, and operating permits with current approval status.
Advanced Power recommended the commission require a comprehensive permitting matrix that includes an outline of timeframes and methodology, or confirmation that certain permits are not required. Advanced Power expressed concern that the proposed language creates ambiguity regarding the required status of the permitting included in the matrix. Advanced Power also suggested the provision be revised for clarity regarding the required status of all necessary permits at the time the application is submitted.
Sierra Club recommended requiring applicants to give a timeline for receiving final permit approval.
Commission Response
The commission confirms that applicants will be required to submit permitting information and status on all necessary permits and approvals as part of the application process. The necessary permits depend, in part, on the design and characteristics of the facility. Thus, the commission declines to provide an exhaustive and exclusive list. The commission will use this information to evaluate project feasibility as described under §25.510(f)(2)(D).
Proposed §25.510(e)(5)(C)(x)-Project-Specific Information
Proposed §25.510(e)(5)(C)(x) requires a description of the air emissions compliance plan, including evidence of receipt of any required air emissions credits.
WattBridge recommended removing the requirement to have air emission credits in hand at time of application due to the expense and risk associated with their purchase prior to the start of construction.
Commission Response
Section 25.510(e)(5)(C)(x) does not require the applicant to have air emissions credits in hand at the time of application, though an applicant may submit any evidence showing that it has obtained air emissions to demonstrate project readiness.
Proposed §25.510(e)(5)(C)(xi)-Project-Specific Information
Proposed §25.510(e)(5)(C)(xi) requests a detailed financial forecast of cash available for debt service, covering a period equal to the repayment period of the loan, including sources of revenue and an annual operating and maintenance budget.
Calpine recommended requiring applicants to include financial forecasting of cash available for emergency conditions in addition to the currently required financial forecasting. Further, Calpine suggested the commission should give preference to applicants who can demonstrate sufficient financial resources to address emergency circumstances to ensure public confidence that a TEF loan recipient will be ready and available to perform in the event of an emergency.
Vistra recommended adding the requirement of sources of capital to §25.510(e)(5)(C)(xi).
Commission Response
The commission confirms that, as part of the application process, the borrower will be requested to provide a detailed financial model including forecasted revenues, expenses, cash flows, and all financial statements. The commission modifies the rule to reflect this.
The commission declines, however, to require applicants to demonstrate access to specific financial resources for use in emergency conditions. Facilities must adhere to the commission's weather preparedness requirements under §25.55, and thus financial resources needed to meet those regulations will already be incorporated into the project's financial forecasts.
Proposed §25.510(e)(6)-Estimated Cost
Proposed §25.510(e)(6) lists the costs to be included in the estimated costs provided in a project application.
Shell Energy recommended that development fees associated with affiliate transactions and any dedicated PUN costs should not be considered a project cost for purposes of the loan program and that no program funds should be forwarded for payment of these types of items.
TPPA recommended requiring projections for ongoing maintenance and operational costs, such as staffing and fuel, to ensure efficient use of taxpayer dollars.
NRG suggested that project costs should include a reasonable project contingency of up to 5 percent for potential unknown costs, loan interest accrued during construction, and property tax payments. NRG stated the inclusion of such costs is standard industry practice and recommended these costs be explicitly stated to be covered by a TEF loan to remove any ambiguity.
CPV recommended including additional estimated project costs in §25.510(e)(6) for items such as consultants, contingency costs, and taxes and insurance.
TCPA recommended if the commission permits PUNs to qualify for the TEF, no less than 51 percent of total facility net energy output in the ERCOT wholesale market should be eligible for a loan. TCPA argued that the eligible amount of the loan should be tied directly to the percentage of total net energy output in the ERCOT wholesale market. TCPA added that costs directly attributable to or associated with the portion that serves the PUN or industrial load should not be eligible.
HEN recommended the commission require applicants to provide total estimated dollar cost per MW so that applications can be comparatively evaluated.
Calpine and HEN requested the commission clarify what costs are intended to be included in §25.510(e)(6)(H), related to interest rate protection costs. HEN stated that because the interest rate in the loan is fixed at three percent, protection should not be required for the loan itself. HEN suggested that, if the intent is for the interest rate protection to apply to the financing for the remaining 40 percent of the project, such protection may not be necessary or applicable in all instances.
Commission Response
The commission confirms that applicants must include all estimated projects costs directly related to the project under consideration for a TEF loan. These costs should be described in detail in the independent engineer's report described in (f)(3) or other supporting information submitted by the applicant. Where the costs in CPV's list are directly related to the project under consideration, the commission confirms that these costs should be submitted as part of an application. The commission agrees with NRG's suggestion for interest accrued and capitalized during construction to be included as a project cost and modifies the provision accordingly. However, the commission disagrees with NRG's suggestion for contingency costs to be included because if a contingency occurs and must be covered by the TEF, it could result in the TEF loan funding more than 60 percent of project costs.
The commission agrees with Shell Energy and TCPA that costs for a PUN that will finance provision of service to the PUN and not to the ERCOT market should not be eligible for a TEF loan. The commission accordingly modifies (g)(1) to clarify that in the case of an electric generating facility that serves an industrial load or PUN, eligible costs will consist of no more than 60 percent of a percentage of total estimated facility costs equal to the percentage of the total capacity of the facility that is dedicated to ERCOT. However, the commission declines to specify in the rule that costs for affiliate transactions are not allowed because it is unnecessary.
The commission declines to modify the rule as suggested by TPPA because a financial forecast that includes an operating and maintenance budget is already required in (e)(5)(C)(xi).
The commission agrees with HEN that interest rate protection costs are not required as TEF loans will be fixed-rate loans and removes the provision. However, the commission disagrees with HEN's suggestion to require applicants to submit their dollars per MW costs. Consideration of total estimated costs is a statutory requirement. Applicants must provide, and the commission must evaluate, the total estimated costs of the facility.
Calpine recommended specifying acceptable documentation to adequately prove up each category of cost described in §25.510(e)(6) and suggested the rule include a process to confirm an applicant's projected costs within a margin of accuracy. Calpine proposed that applicants exceeding this margin must fund the excess through equity, or otherwise without reliance on TEF loan distributions. Calpine stated this would help ensure accountability and the exercise of due diligence by applicants to estimate total project costs. Calpine further recommended the commission be permitted to consider exigent circumstances resulting in increased project costs above the amounts disclosed in the application and should have discretion to continue an applicant's eligibility if an applicant or recipient exceeded the established margin of error.
Advanced Power recommended the provision be revised to clarify how the estimated project costs will be considered because project developers are unlikely to have executed agreements at the time the application is submitted. Advanced Power explained that project cost estimates may change significantly during the course of the application, which would make any estimates provided to the commission become outdated. Accordingly, Advanced Power suggested that the applicant provide the estimated project costs with the application, and that an opportunity to re-evaluate and potentially update those cost estimates prior to financial close be provided under the rule.
Commission Response
The commission declines to modify the rule as suggested by Calpine and Advanced Power because no additional clarification is warranted. The commission modifies the rule at (f)(3) to require an applicant to provide an independent engineer's report as a required project document during the due diligence phase of the application, and the TEF administrator will evaluate these documents to verify estimated project costs, including contingency costs. Additionally, the project costs provided by the applicant should align with the project cost inputs in its financial forecast model. Material changes in project cost estimates during the review of an application will be considered on a project-by-project basis and may result in the reduction of eligible loan proceeds or the rejection of a loan application amount because the material changes in project cost estimates could impact the feasibility of the project or the creditworthiness of the applicant or the sponsor.
Proposed §25.510(e)(6)(A)-Application Requirements and Process
Proposed §25.510(e)(6)(A) requires applicants to provide expenses related to development, construction, and capital commitments required for the project to reach completion.
Calpine recommended adding the term "contingency" as one type of commitment required to be provided in the application.
Commission Response
The commission confirms that the level of contingencies required will be determined during due diligence and must be funded by sources other than the TEF loan. For these reasons, the commission declines to modify the provision as requested by Calpine.
Proposed §25.510(f), §25.510(h)(1)(B)(iii), (h)(1)(G), and (i)(4)-Evaluation Criteria, Loan Term and Agreements, Deposits
Proposed §25.510(f) describes the evaluation criteria for a loan application. Proposed §25.510(h)(1)(B)(iii) establishes that the commission will review a borrower's construction drawdown certificate. Proposed §25.510(h)(1)(G) requires a borrower to register with the commission as a power generation company, unless the borrower is an MOU, cooperative, or river authority, and to register the project facility with ERCOT as a generation resource. Proposed §25.510(i)(4) establishes that the commission will evaluate notices of satisfaction to determine whether a borrower is entitled to withdraw its deposit.
NRG recommended the commission set a 90-day timeline for application evaluation because applications are not contested cases, and CBG applicants need to quickly begin construction of plants. NRG also stated that it would appreciate a document that outlines the process, including communications protocols.
TPPA recommended expanding §25.510(f) to include procedural details like discrete timelines for the commission review process, who will be conducting the review, whether evaluators will be permitted to contact an applicant directly or request additional information or modifications to an application, and whether applications would be processed in the order filed or under a prioritization process. TPPA recommended the same request in §25.510(h)(1)(B)(iii), (h)(1)(G), and (i)(4).
Sierra Club suggested a process where an applicant can fix a deficiency if it has been identified and recommended that there be parameters in place to prevent repeat deficiencies. Sierra Club also requested that applicants be walked through any deficiencies.
Commission Response
The commission declines to provide a specific timeline under which it will evaluate applications, as requested by NRG and TPPA. The timeline of the loan approval process will depend on the completeness of the application, complexity of the project, and preparedness of the applicant. However, the commission agrees with TPPA that additional details on the evaluation process would be helpful and adds (f)(3) to include such details.
The commission modifies the rule to add the completeness of an application as an evaluation criterion in new subsection (f)(1)(C). Should an application not contain sufficient information for the TEF administrator to conduct a thorough evaluation, the TEF administrator may notify the applicant through a web-based application system of such a deficiency.
Proposed §25.510(f)(1)-Evaluation Criteria
Proposed §25.510(f)(1) describes the criteria the commission will use to evaluate applications.
WattBridge suggested prioritizing funding for applicants based on resource attributes and project location with respect to demand in ERCOT. WattBridge recommended prioritizing projects using a weighted assessment of resource flexibility, fuel efficiency, historical availability, thermal derate, and water consumption. Further, WattBridge suggested prioritizing projects that have flexible fuel-efficient resources that derate marginally in extreme weather and can support dual or backup fuel for resilience.
LSP suggested the commission specify the minimum project requirements as evaluation criteria, place more emphasis on the developer's track record and reputation, and develop clear and concise guidance that assists project developers in evaluating tradeoffs and allows the applicant to propose highly responsive projects that serve the needs of the commission. LSP also requested the commission identify the characteristics or combination of characteristics it values the most and recommended the commission require project applicants state in their applications the minimum amount of TEF debt that would make their projects viable.
HEN commented that cost is a critical component of prioritization. HEN suggested the commission consider a diversity of resources and geographical locations as components in its evaluation criteria.
TPPA requested clarification on whether the criteria in §25.510(f)(1) are individual, nondiscretionary requirements or if the requirements are part of a holistic review. TPPA encouraged the commission to consider MOU applicants as eligible for funding.
Drax Group recommended that the commission evaluate generators that have successfully operated generation assets internationally, even if the applicant has not operated generators domestically.
TCPA recommended complete transparency on how the applications will be scored and that if there are any criteria beyond the statutory requirements, then those criteria should be communicated to the market very clearly prior to any NOI to apply is taken.
Calpine, LSP, NRG, LCRA, WattBridge, Vista, and HEN all agreed with the idea of a scoring rubric. HEN further supported a detailed application form with clarification on the specific pieces of evidence that the commission is seeking. HEN recommended that the rubric should strike a balance that allows for a variety of projects that meet the fundamental requirements of the statute while not being too specific.
NRG commented that it is important to understand what needs to be submitted as part of the application process.
LCRA recommended that the statutory requirements be the primary criteria that are evaluated. LCRA also requested clarification on what the weighting will be and what specific evidence the commission is looking for in each of the criteria.
Commission Response
The commission intends to evaluate the information requested of and provided by an applicant on a holistic basis, as explained above in Loan Application Evaluation Methodology, and so disagrees with commenters' requests that the commission declare preference for any particular project attribute or applicant profile that is not explicitly enumerated in §25.510(f). Instead, the commission seeks to encourage a broad range of applicants to submit viable proposals that address the goals of the TEF.
Similarly, it is unnecessary to specify minimum project requirements as evaluation criteria, as suggested by LSP, because the proposed rule already contains minimum eligibility criteria to apply, which all applicants and projects must meet. It is also unnecessary to require an applicant to state the minimum amount of a TEF loan that would make its project viable, as suggested by LSP, because the TEF administrator will determine during due diligence the amount of funding each proposed project and applicant merit. However, in response to TPPA's comments, the Commission notes in that the evaluation criteria are not independent requirements.
The commission agrees with TPPA that MOUs are eligible to apply for a TEF loan and modifies §25.510(g)(6) and (h)(1)(G) accordingly.
Regarding commenters' requests to clarify the TEF loan application evaluation process, §25.510(c), (e), and (f) together state the bases on which the commission will make its TEF funding decisions. Applications will be assessed against these criteria and against other applicants' responses to those criteria. Providing a predetermined weighting rubric may unnecessarily restrict the commission's ability to evaluate unique proposals. Additionally, providing a scoring rubric could lead to applicant gamesmanship, and therefore, the commission declines to accept the recommendations of Calpine, LSP, NRG, LCRA, WattBridge, Vista, and HEN to provide a scoring rubric.
Proposed §25.510(f)(1)-Evaluation Criteria
Proposed §25.510(f)(1) describes the criteria on which the commission will evaluate a project proposal.
Shell Energy recommended that priority be given to projects that have a robust hedge strategy with contracted revenues for the capacity and energy of the facility with a financially sound energy trading partner. Shell Energy suggested that this requirement would be superior to an evaluation based solely on the forecasted energy price and ensure certainty around contract revenues with credit-worthy counterparties.
NRG recommended that the commission not evaluate a project's hedging strategy as part of its prioritization criteria.
Commission Response
The commission will evaluate an application holistically based on its entire business plan, including market prices and hedging strategies, if any, to determine the feasibility of the project. To make this evaluation criterion clearer and align it more closely with the requested information in §25.510(e)(5)(C)(xi), the commission modifies §25.510(f)(1)(B) to include evaluation of total forecasted revenues generated by the project alongside the total estimated costs of the facility.
Proposed §25.510(f)(1)(A)(i) and (f)(1)(A)(iii)-Evaluation Criteria
Proposed §25.510(f)(1)(A)(i) lists as an evaluation criterion the quality of services and management, as shown by the applicant's prior history of electricity generation in this state and this country. Proposed §25.510(f)(1)(A)(iii) lists as an evaluation criterion the history of electricity generation in this state and country.
TPPA recommended that §25.510(f)(1)(A)(iii) not repeat the language of §25.510(f)(1)(A)(i). TPPA commented that the Legislature presumably intended for separate evaluation criteria to require separate analyses, and that the proposed rule appears to collapse these two criteria into one.
Commission Response
The commission agrees with TPPA's recommendation and amends the rule to remove the redundancy. However, to align more closely with PURA §34.0104(c)(1)(C), the commission removes the reference in §25.510(f)(1)(A)(i) rather than the reference in §25.510(f)(1)(A)(iii). Although "prior history of electricity generation in this state and this country" can be indicative of an applicant's quality of services and management, it is not the exclusive manner of demonstrating such quality. Accordingly, the commission modifies the rule to remove any such implication.
Proposed §25.510(f)(1)(A)(i), (f)(1)(A)(ii), and (f)(1)(A)(iii)-Applicant's Quality of Services and Management & Efficiency of Operations & History of Electricity Generation Operations
Proposed §25.510(f)(1)(A)(i), (f)(1)(A)(ii), and (f)(1)(A)(iii) evaluate the applicant's quality of services and management & efficiency of operation & history of electricity generation operations.
Calpine recommended the commission determine a minimum number of years' experience that an applicant must have in each of these categories, or establish a different objective threshold, for an applicant to make a sufficient showing to qualify for a TEF loan.
Commission Response
Although years of experience is a consideration in evaluating an application, the commission declines to impose a strict minimum that might exclude an otherwise acceptable application.
Proposed §25.510(f)(1)(A)(i) and (f)(1)(A)(ii)-Applicant's Quality of Services and Management & Efficiency of Operations
Proposed §25.510(f)(1)(A)(i) and (f)(1)(A)(ii) evaluate the applicant's quality of services and management and efficiency of operations.
Wartsila recommended the commission consider an applicant's experience in any Northern American country, instead of limiting it to Texas and the United States. Wartsila provided redlines consistent with its recommendations.
Commission Response
The commission will evaluate sponsors and applicants based on experience developing, owning, and operating relevant power generation assets in Texas and the United States. However, the commission will review applications holistically, and a lack of experience in Texas or the United States will not disqualify an applicant from receiving a TEF loan.
Proposed §25.510(f)(1)(A)(iv)-Applicant's Resource Operation Attributes
Proposed §25.510(f)(1)(A)(iv) evaluates the applicant's resource operation attributes, including fuel type and heat rate, seasonal net maximum sustainable rating, resource ramp rate, and capacity factor.
USA Compression recommended adding cold and hot temperature start times to the evaluation criteria to align with the application requirements.
Commission Response
The commission agrees with USA Compression's recommendation and modifies the rule to align more clearly the requested information in §25.510(e)(5)(C)(i) with evaluation criteria in §25.510(f)(1)(A)(iv).
Proposed §25.510(f)(1)(A)(v)-Ability to Address Regional and Reliability Needs
Proposed §25.510(f)(1)(A)(v) evaluates the applicant's ability to address regional and reliability needs.
TXOGA commented that there is a need for flexibility among resources available to help support the grid by having units throughout the state instead of in major generation pockets like the state currently has installed.
Commission Response
The commission confirms that proposed §25.510(f)(1)(A)(v) does include "ability to address regional and reliability needs" as a consideration, and no further changes to the proposed rule are needed to address siting diversity concerns.
The commission modifies subsection (e)(5)(A) of the rule to explicitly require resources availing the TEF funds to adhere to §25.55, Weather Emergency Preparedness.
Proposed §25.510(f)(1)(A)(vii)-Evidence of Creditworthiness
Proposed §25.510(f)(1)(A)(vii) evaluates the applicant's evidence of creditworthiness and ability to repay the loan on the terms established in the loan agreement.
Calpine recommended the commission review an applicant's other assets to determine creditworthiness and that an applicant should be required to show it has sufficient credit to operate in the ERCOT wholesale market and not just to obtain a loan. Calpine commented that, if a facility that has received loan proceeds should default on its obligations to ERCOT, the facility would also undoubtedly default on the terms of its loan.
TPPA suggested referencing text from PURA §34.0104(c)(1)(G) ("total assets, total liabilities, net worth, and credit ratings issued by major credit rating agencies").
Vistra recommended adding "access to capital" to this evaluation criteria.
Commission Response
The commission agrees with TPPA's suggestion and modifies the rule to include the examples listed in PURA §34.0104(c)(1)(G), which will be considered, if applicable. Although the commission will evaluate other evidence of creditworthiness, if provided, the commission declines to add additional requirements as proposed by Calpine and Vistra.
Proposed §25.510(f)(1)(B)-Nameplate Generation Capacity and Total Estimated Cost
Proposed §25.510(f)(1)(B) evaluates nameplate generation capacity and total estimated costs of the facility for which the loan is requested.
CPV recommended removing the total estimated cost from the evaluation criteria as the costs of dispatchable generation may vary from site to site but will predominantly fall within a predictable range of costs per kilowatt. CPV further stated that utilizing this measure as part of the evaluation tool promotes "gaming" in the application process and an applicant could artificially lower the project's total cost to receive a loan, only to increase those costs later.
Vistra recommended that loan applications should be evaluated primarily based on those statutory criteria in SB2627 and that statutory requirements should be prioritized.
Commission Response
The commission recognizes that an applicant's projected nameplate generation capacity and project costs are subject to error and gamesmanship. However, the commission's ability to provide loans using the TEF is limited in terms of MWs and dollars. Applicants are in the best position to provide accurate estimates for their projects. Therefore, the commission rejects CPV's recommendation. The commission further notes that PURA §34.0104(d) imposes a 10,000 MW limitation, and the amount of money held by TEF is finite. Accordingly, consideration of nameplate capacity and total estimated costs is effectively a statutory requirement. Applicants must provide the nameplate generation capacity and total estimated costs of the facility. Additional project costs beyond the TEF loan proceeds must be funded by the applicant.
Proposed §25.510(f)(1)(B) and §25.510(f)(2) - Multiple Evaluation Criteria
Proposed §25.510(f)(1)(B) evaluates nameplate generation capacity and total estimated costs of the facility for which the loan is requested. Proposed §25.510(f)(2) outlines additional considerations for evaluation criteria.
HEN recommended moving some criteria from the permissive evaluation provision in §25.510(f)(2) to the mandatory evaluation provision in §25.510(f)(1). HEN suggested that most of the evaluation criteria relating to the proposed generating facility itself are not mandatory, and nearly all the mandatory considerations relate to the applicant and not the project. HEN provided redlines consistent with its recommendations, including the addition of a new subparagraph, §25.510(f)(3), that states "As part of its evaluation process, the commission shall consider the portfolio of qualified loan applications and award loans to a diversity of generating facilities to enhance reliability and resiliency, including different geographical locations with ERCOT, differing fuel types and fuel supply sources and arrangements and a range of commercial operation dates. Final loan awards may not exceed the amount requested by the applicant in its application and evaluated by the commission in selecting among qualified loan applicants."
Drax Group recommended adding new subsections §25.510(f)(2)(K) and (f)(2)(L) for onsite fuel capabilities to enhance reliability by encouraging generation with onsite fuel storage capabilities. Drax Group provided redlines consistent with its recommendations.
NRG stated that neither the project technology nor the project costs should factor in as part of the prioritization to review.
Vistra commented that access to capital or liquidity is a reasonable addition, but additional evaluation criteria added by the commission should be prioritized as secondary features to the statutory criteria.
WattBridge commented that it is concerned about timing and recommended that some of the priorities be scored on a pass or fail basis.
Commission Response
The commission will evaluate applications holistically using the criteria and priorities described in the rule and this document. In response to commenters' suggestions to evaluate the operational attributes, including fuel types and project technology, the commission modifies the rule to clearly indicate that the information requested in (e)(5)(C)(i) will be part of the evaluation criteria in (f)(1)(A)(iv).
The commission declines to explicitly prioritize the diversity of resource type and geographic location of proposed projects because the applicant pool is unknown at this time, and such a restriction could unnecessarily limit the number of projects funded through the TEF.
Although onsite fuel storage capability may be beneficial, it is not a necessary attribute for an application. ERCOT currently procures firm fuel supply service (FFSS) for reliability purposes. The commission declines to further incentivize this program via additional priority in evaluation criteria. However, the expected ability to provide FFSS can be considered in other criteria where applicable (e.g., forecasted revenue).
The commission has already given more weight to statutory criteria, as suggested by Vistra, and no changes are needed as a result.
Proposed §25.510(f)(2)-Additional Considerations for Evaluation Criteria
Proposed §25.510(f)(2) outlines additional considerations that the commission may use to evaluate applications.
Calpine recommended prioritizing applications that do not need to draw on the loan after COD and applications that can demonstrate firm fuel supply capabilities as this will ensure that the first loan recipients have sufficient access to capital to cover the requisite 40 percent of anticipated construction costs, plus the three percent deposit, plus contingencies, while also providing an incentive to undertake construction of new dispatchable generation in line with the intent of SB 2627. Calpine suggested that this prioritization would also serve to protect taxpayers' interests by increasing the likelihood that the applicant will not default on its loan payment obligations. It also recommended that the commission prioritize loan applications that can ensure firm fuel procurement, such as through onsite storage or through firm fuel contracts, over those that cannot, as this is consistent with the goal of SB2627 to ensure increased reliable dispatchable generation in the ERCOT region. Calpine provided redlines consistent with its recommendations.
Shell Energy recommended giving preference to projects based on locational advantages to serve load, proximity to load centers, lower cost to interconnect, lower project cost per MW, and ability to reduce congestion.
Targa recommended adding a requirement specifying that a PUN that serves a critical gas supplier or critical customer is eligible for a loan due to the reliability function it serves, regardless of whether it provides excess energy to the ERCOT grid.
Commission Response
The commission intends to consider the complete financial picture associated with a proposed project and declines to place special emphasis on whether an applicant will need to utilize TEF proceeds after COD, as suggested by Calpine.
Although onsite fuel storage capability may be beneficial, such capability is already incentivized via the existence of FFSS. The commission declines to further incentivize this program via additional priority in evaluation criteria. However, the expected ability to provide FFSS can be considered in other criteria where applicable (e.g., forecasted revenue and the ability to address reliability needs).
In response to Shell Energy's comments, the commission notes that there are already programs in place to encourage siting GRs near load and declines to further incentivize it in the application evaluation process. Furthermore, the commission notes that the ability to address regional and reliability needs is already an evaluation criterion under §25.510(f)(1)(A)(v). The commission will review applications and their ability to meet the goals of the TEF holistically.
Regarding Targa's recommendation, PURA §34.0104(a) and §34.0106(b) collectively require that TEF loans explicitly prioritize the provision of power to the ERCOT power region over industrial loads or PUNs. It does not contain an exception for load attributable to critical gas suppliers or critical customers. Without a statutory basis for Targa's recommendation, the commission declines to modify the proposed rule as requested.
TPPA requested more details about considerations of the permissive criteria. TPPA stated that applicants must understand evaluation criteria and that, if the commission uses different set of criteria to evaluate one application versus another, it will be difficult to ensure applications were evaluated fairly and non-arbitrarily.
Commission Response
The commission declines to provide more detail about the permissive evaluation criteria because it is unnecessary. Both the mandatory and permissive sets of criteria are described in the rule, and all applicants will be evaluated by those same sets of criteria.
Proposed §25.510(f)(2)(H)-Sufficiency of the Applicant's Proposed Sources of Equity
Proposed §25.510(f)(2)(H) indicates that the commission may consider the sufficiency of the applicant's proposed sources of equity to cover the costs of the facility not funded through a loan provided under this section.
LCRA recommended including "debt" as a funding source that applicants can use for the non-TEF-funded project costs.
Commission Response
Consistent with LCRA's suggestion, the commission modifies (f)(2)(H) by adding "or other funding sources" to reflect alternative means of financing the facility costs not funded through a loan under this section.
Proposed §25.510(g)(1)-Loan to be no more than 60 percent of Estimated Cost
Proposed §25.510(g)(1) states that the approved loan will consist of no more than 60 percent of the estimated cost of the electric generating facility to be completed.
Sierra Club suggested allowing interconnection costs to be included in project cost information.
Wartsila requested clarification on whether the receipt of a loan entitles an applicant the full amount of the loan requested, and if not, what the criteria for awarding a partial loan would be.
Commission Response
§25.510(e)(6)(K) of the rule as proposed includes interconnection costs among estimated project costs, so the commission does not make any change in response to Sierra Club's comment.
The commission may elect to partially fund a project based on the relative creditworthiness of the applicant and feasibility of the project. However, the commission will prioritize TEF loan awards to projects that can be fully funded up to the requested loan amount, which cannot exceed 60 percent of the project estimated costs. Only after all applications have been submitted and initial evaluations are complete can the commission know the amount of funds that may be available for partial loan awards.
Proposed §25.510(g)(1), (g)(2), and (g)(5)-Multiple Loan Structure Requirements
Proposed §25.510(g)(2) and (g)(5) state that the approved loan will (2) be the senior debt secured by the electric generating facility to be completed; and (5) be structured as senior debt secured by a first lien security interest in the assets and revenues of the project.
LCRA recommended clarifying that all references of "senior debt" throughout this rule are meant to include the borrower's parity debt that is secured by a pledge of and lien on revenues. LCRA suggested for further protection that the commission add rule language to specify that "senior debt" includes debt secured by a lien on assets or other pledge of or lien on revenues, provided that in the case of debt secured solely by a pledge of or lien on revenues, the borrower has a credit rating no lower than investment grade as determined by Moody's Investors Service, Inc., Standard & Poor's Rating Group, or Fitch Ratings (or any successor to such respective credit rating agency).
CPV suggested modifying §25.510(g)(2) to allow applicants to rely on additional senior funded credit facilities to optimize capital sourcing and all-in cost of capital to fund the full cost of the project.
CPS Energy recommended changes to allow MOUs to participate in the loan program notwithstanding public debt obligations of municipal entities in Chapter 1502 of the Texas Government Code. CPS Energy also recommended that a loan secured by an MOU with existing revenue debt obligations should (i) be considered a priority lien pledged on system net revenues on parity with other outstanding priority lien debt; and (ii) be required to include a covenant not to issue additional debt secured by system net revenues except on parity with or subordinate to such priority lien debt.
Commission Response
PURA §34.0104(b)(3) specifies TEF loans to be the senior secured debt and does not specify any other senior level debt. However, CPS Energy and LCRA have identified other statutory restrictions on the ability of an MOU or river authority to grant lien interests in its utility assets. Under the proposed rule, these lien restrictions would effectively preclude their participation in the in-ERCOT Generation Loan Program. At the same time, PURA §34.0104(e) specifically contemplates the inclusion of river authorities as potential borrowers in the in-ERCOT Generation Loan Program. Reading PURA Chapter 34 in its entirety, the commission interprets the legislation to allow river authorities and MOUs to obtain a loan, but only when those entities secure repayment of the debt with the highest form of security permissible under governing law. This interpretation is consistent with the Texas Code Construction Act, which clarifies that, in enacting a statute, it is presumed that "a result feasible of execution is intended." Accordingly, the commission modifies (g)(6) and (h)(1)(G) to allow MOUs and river authorities to secure repayment of a TEF loan with a pledge of revenues of the applicant's utility system. The commission also adds subsections (g)(7) to reflect that a borrower that is an MOU or river authority may meet the loan structure terms through the issuance of a public security in accordance with governing Texas law. This form of securitization is only available to river authorities and MOUs.
The commission declines to modify the rule as recommended by CPV. All applicants must submit information related to their proposed financing structures, which the commission will evaluate as part of the project proposal. While applicants may propose project financing structures with various forms of subordinated debt, applications proposing to use other senior-level debt will not be considered for applicants that are not MOUs or river authorities.
Applicants who wish to use subordinated debt in place of equity are required to assume the cost of drafting intercreditor agreements. The commission modifies the rule to add new paragraph (h)(8) to reflect the necessity of one or more subordination agreements when a borrower intends to use subordinated debt in place of equity.
Proposed §25.510(g)(3)-Loan Repayment of 20 Years
Proposed §25.510(g)(3) states that the approved loan will have a repayment term of 20 years.
LCRA recommended the repayment term of the loan may be "up to" 20 years to ensure consistency between the language of §25.510(g) and the voluntary prepayment provisions in §25.510(h)(1)(E). LCRA provided redline language in line with the recommendation.
NRG recommended clarifying the repayment term. NRG commented that under PURA, the loan is to be for a term of 20 years with repayment starting on the third anniversary of COD and expressed confusion around whether this results in a total term of 23 years. NRG stated that this issue could be addressed in the rule, guidance documents, or loan agreements, but recommended removing "repayment" to preserve flexibility.
Commission Response
Under PURA §34.0104(f), loan repayment is coordinated with the project's respective estimated COD. The loan has an interest-only period during construction and for the first three years after the estimated COD. The entire tenor of the loan does not exceed 20 years, including the interest-only period. The commission modifies the rule to reflect this.
The commission declines to modify the rule as requested by LCRA because including the words "up to" in paragraph (g)(3) would create ambiguity as to whether some loans may be structured for a term shorter than 20 years. All loans will have a 20-year term, and in accordance with the loan agreement details provided in clause (h)(1)(E), all loan agreements will incorporate prepayment conditions.
Proposed §25.510(g)(4)-Loan to be Payable on a Pro Rata Basis
Proposed §25.510(g)(4) states that the approved loan will be payable on a pro rata basis starting on the third anniversary of the estimated COD of the electric generating facility as stated on the application.
LCRA suggested defining "pro rata basis" to mean level debt service.
WattBridge recommended making the repayment terms negotiable between the commission and the applicant. WattBridge also provided redlines in line with its recommendation.
Commission Response
For consistency with PURA §34.0104(f)(2), the commission modifies the rule by replacing "on a pro rata basis" with "ratably."
The commission modifies the rule to reflect WattBridge's recommendation to allow for negotiated repayment terms. The commission agrees that the repayment profile of a given loan should appropriately reflect the project's expected revenue stream. Accordingly, the commission declines LCRA's proposal for level debt service and modifies subsection (g)(5) to structure debt service on a negotiated basis correlated with the applicant's expected revenue.
Proposed §25.510(g)(5)-Loan to be Structured as Senior Debt
Proposed §25.510(g)(5) states that the approved loan will be structured as the senior debt secured by a first lien security interest in the assets and revenues of the project.
LCRA recommended that the pledge of a security interest in assets and revenues of a project should only be required to the extent permitted by law. LCRA noted that Texas law outside of PURA Chapter 34 limits some public entities' ability to grant a lien interest in physical assets. Similarly, CPS Energy stated that Chapter 1502 of the Texas Government Code does not allow a municipal utility to pledge a lien interest in assets of the utility system.
LCRA also recommended that the commission interpret senior debt to include a borrower's parity debt that is secured by a pledge of a lien on revenues. Under this approach, "senior debt" would mean debt having no senior rights to the security interest securing the loan, but which may be on parity secured status with the borrower's other senior debt.
Commission Response
PURA §34.0104(b)(3) requires any TEF loan to be the "senior debt secured by the facility," meaning the assets of the project. However, the commission recognizes that an MOU and a river authority are limited in their ability to provide a lien on utility assets. Therefore, the commission modifies subsection(g)(2) and (g)(6) to allow an MOU or river authority borrower to make a revenue pledge to secure its indebtedness.
Proposed §25.510(h)-Loan Terms and Agreements
Proposed §25.510(h) requires the borrower to enter into one or more agreements with the commission that includes the terms of this section.
LSP suggested allowing customary intercreditor arrangements among the providers of the TEF loan and such other secured indebtedness.
For MOUs, CPS Energy suggested that the terms and covenants to be embedded in these agreements should be in a debt authorization ordinance or resolution consistent with Chapter 1502 of the Texas Government Code, instead of a separate credit agreement. CPS Energy commented that it would be difficult to have a standardized loan agreement because MOUs have different statutory financing obligations than privately-owned entities. Further, CPS Energy recommended that the commission have a separate standard form for MOUs or carve-out provisions in a standard form agreement.
Calpine suggested the commission clarify whether the agreements listed will be developed and negotiated on an applicant-by-applicant basis or if standard form agreements will be developed.
LCRA noted that Texas Special District Local Laws Code Chapter 8503 prohibits LCRA from encumbering its property with a lien interest. Accordingly, LCRA suggested a change to reflect that a secured interest in TEF-funded assets should only be required "to the extent permitted by law."
LSP argued that a standard credit document would not be practical because credit agreements are typically tailored to specific projects. LSP acknowledged that some basic loan terms and conditions could be applicable to all borrowers. LSP recommended developing a term sheet that lists the basic loan tenets such as requirements for term, rate, payment terms, notice, cure, and default provisions, and circulating it for public comment.
NRG supported working towards a standardized form of a loan agreement for borrowers but proposed that certain elements of the credit agreement will need to be tailored for each individual project via exhibits and schedules. NRG recommended that the commission seek stakeholder feedback on the initial draft of the loan forms in a workshop session.
Vistra supported limited contested case proceedings that would allow for a standardized loan agreement while allowing parties to seek modification for good cause.
Commission Response
The commission notes that the first sentence of subsection (h) only reflects that the lending relationship between the commission and a borrower must be memorialized in one or more loan agreements. This means that an approved applicant must enter into a standardized, commercially typical loan agreement that includes terms described in the various paragraphs of subsection (h). In response to Calpine, LSP, and NRG, the commission acknowledges that each TEF-funded project will have specific attributes that call for individualized loan documentation for each borrower. Project-specific attributes will therefore be addressed in each loan agreement on a borrower-by-borrower basis. However, all loan agreements must incorporate the requirements described in the entirety of subsection (h).
The commission agrees with LSP that the loan agreement should allow various creditors to confirm their lien status with respect to facility assets. The commission adds paragraph (h)(8) to require the subordination of any other creditors with respect to the commission. Borrowers that require this arrangement will be responsible for the preparation and cost of any such subordination agreements.
The commission acknowledges the comments of CPS Energy and LCRA identifying laws specific to public power authorities that restrict the ability to provide a security interest in utility assets. The commission modifies subparagraph (h)(1)(F) to carve out an MOU or river authority from the requirement to grant a lien interest in utility assets in favor of the commission.
Proposed §25.510(h)(1)(A)-Performance Covenant
Proposed §25.510(h)(1)(A) requires an EAF performance of 50 for the electric generating facility financed by the loan during its term. The EAF indicates the fraction of an operating period where a generating unit is available to produce electricity, free of outages or equipment deratings.
ERCOT recommended revising the rule to state that ERCOT's availability data be used rather than using North American Electric Reliability Corporation (NERC) Generating Availability Data System (GADS). ERCOT stated that NERC GADS is confidential. ERCOT suggested it could provide a report on an annual basis (or other specified period) documenting the EAF for each unit that is the subject of a loan agreement and recommended that such a reporting obligation be specified in the rule. ERCOT stated if the telemetered status for the entirety of a given hour during the period of the loan is anything other than "OUT," "EMR," or "EMRSWGR," the unit would be considered available unless the telemetered HSL for the unit is less than the unit's seasonal net maximum sustainable rating by some defined margin established by ERCOT. (ERCOT Nodal Protocols §3.9.1). ERCOT also recommended that, if the commission expects ERCOT to calculate the EAF under this rule, the rule be revised to allow ERCOT to establish such a margin or the EAF calculation in §25.510(h)(1)(A) be revised to provide for a reduction in the EAF proportional to the magnitude of the derate, rather than considering any derate to mean the unit is entirely unavailable.
Advanced Power recommended adding clarity related to the measurement of EAF performance goals but did not provide an explanation of what required further clarification.
Calpine urged clarification on EAF performance and definition. Calpine recommended defining EAF as "the fraction of a given operating period in which a generating unit is available to produce electricity without any outages or equipment deratings."
WattBridge recommended that the EAF performance be evaluated annually on a site-wide basis, and, if the electric generating facility fails to meet the EAF, the facility should have a one-year cure period to meet the EAF performance requirement. WattBridge also recommended that the GADS calculation for EUOF be used, instead of EAF, to remove planned outages because "it is industry and prudent practice to take planned outages."
Sierra Club suggested 70 as an appropriate performance standard, while TIEC suggested increasing required EAF to 80.
TPPA proposed calculating overall EAF at regular intervals rather than applying EAF performance covenant to each operating hour during the term of the loan because requiring performance in each operating hour is too stringent.
NRG, WattBridge, TCPA, and LSP all recommended using NERC GADS EUOF to calculate availability. NRG further recommended excluding Outside Management Control events when calculating performance, and recommended calculating performance monthly as an annual average over a rolling 24-month period, instead of for each hour of the loan term. NRG believed the proposed performance covenant based on EAF is too strict and imposes unacceptable risk of default.
LSP and TCPA recommended calculating EAF on a 12-month rolling average as a single hour below 50 could trigger a breach. TCPA further suggested a proscriptive performance calculation methodology that does not allow the facility to allocate less equivalent outage hours to the portion of the facility serving ERCOT load.
Golden Spread suggested there is conflicting EAF information between §25.510(h)(1)(H) and (h)(1)(A) and requested clarification on whether EAF is measured annually or if EAF of 50 is measured for all hours during the term of the loan. Golden Spread recommended measuring EAF over the life of the loan instead of every year because consequences for default are severe and poor performance in a single year for an otherwise well-performing unit could result in loan default.
Vistra recommended the commission use a different performance metric or provide clarity on EAF performance standard. Vistra suggested using NERC EUOF definitions. Alternatively, Vistra suggested that the commission could adopt a phased-in approach to compliance where, in the first three years of operation, facilities are held to a lower performance standard that scales up over time.
HEN suggested that identifying the "given operating period" for EAF calculation as the time period over which the availability factor is calculated is essential to determine whether an EAF of 50 is a reasonable performance requirement. HEN recommended that the "given operating period" should be a calendar year.
Commission Response
The commission modifies the rule to use two performance standard metrics based on ERCOT real-time telemetered and COP data: the PAF and the Planned Outage Factor (POF). The EAF metric used in the proposed rule relies on confidential NERC GADS data that is not readily available to ERCOT or the commission, so the commission removes that metric from the rule.
The PAF will be calculated monthly to determine availability over the trailing 12 months, measured as the average of the ratio of real-time HSL to the available capacity expressed as a percentage, to avoid single-hour risk of default. Available capacity will be based on the adjusted seasonal net max sustainable rating, as registered with ERCOT. The available capacity for a GR associated with an industrial load or a PUN will use the net capacity that is allocated to primarily serve the ERCOT market. The PAF calculation will exclude intervals of planned maintenance that result in an outage of the entire resource, and projects will be required to maintain a PAF of 85 percent to reflect this consideration.
The second metric, the POF, is defined to evaluate the amount of time that a GR spends in planned outages during any evaluation period. POF will be calculated monthly to determine the percentage of time that a GR spent in planned outages during the trailing 12 months. A GR that is part of a facility financed by a TEF loan is required to maintain a POF no greater than 15 percent.
The PAF and POF will be incorporated into the performance covenant of the credit agreement, and so the commission modifies (b)(3), (b)(4), and (h)(1)(A) accordingly.
Additionally, the commission clarifies that the loan agreement will contain a cure provision that enables a borrower in breach of the performance covenant requirements, under §25.510(h)(6)(B), to cure its breach within a time specified in the loan agreement. If a borrower has not cured its breach within the specified time period, it will be considered in default of the loan agreement.
Proposed §25.510(h)(1)(B)-Construction and Term Loan Facility
Proposed §25.510(h)(1)(B) states that a senior secured first lien construction and term loan facility will advance to the borrower upon closing of the credit agreement. The construction loan converts to a term loan after project operation. Borrowers can request loan disbursements up to 60 percent of incurred costs and must fund a minimum of 40 percent equity during construction. Amounts repaid during construction cannot be re-borrowed after conversion to term loan.
CPS Energy suggested allowing for the deposit of the full amount of loan proceeds into an escrow account established under an escrow agreement because the Attorney General, which must approve all issuances of public securities by Texas municipalities, has previously expressed reluctance to approve certain draw-down loan structures. The escrow account and escrow agreement would allow for periodic draws to fund construction upon satisfaction of delineated conditions precedent.
Advanced Power recommended the term conversion to occur within a specified period after the project reaches the COD. Advanced Power suggested clarifying that debt-first draws are allowed when necessary to assist the equity model.
Commission Response
The commission declines CPS Energy's suggestion for the rule to specifically allow for a deposit of loan proceeds into an escrow account. However, the commission acknowledges the limitations faced by public power entities regarding drawdown loan structures. Accordingly, the commission adds new paragraph (h)(9) to allow an MOU to provide substitute documentation customarily associated with the issuance of a public security to meet all preceding requirements of subsection (h). Any such substitute documentation must be prepared by an MOU or river authority at that entity's expense and must be on terms satisfactory to the commission.
Regarding Advanced Power's comments concerning loan conversion, the commission clarifies that TEF loans do not have term conversion. Per PURA §34.0104(f)(2), the loans are structured with interest accruing during construction and with payments commencing three years after the estimated COD. As stated in §25.510(g)(4), payments start on the third anniversary of the commercial operations date. The commission modifies (h)(1)(D) to clarify that interest begins to accrue at disbursement.
Proposed §25.510(h)(1)(B), §25.510(h)(1)(B)(i), and (h)(1)(B)(ii)-Construction and Term Loan Facility, Borrower's Request for Loan Disbursement Upon Initial Closing, Borrower's Request for Loan Disbursements, and Equity Commitment During the Term of the Construction Loan
Proposed §25.510(h)(1)(B)(i) and (h)(1)(B)(ii) state that at the initial closing of a credit agreement, the borrower can request a loan disbursement of up to 60 percent of documented incurred expenses. During the loan term, the borrower may request disbursements up to 60 percent of project costs, while contributing agreed-upon equity.
TIEC suggested that, before allowing a borrower to receive TEF loan disbursements, the commission should require an applicant to demonstrate that the first 30 percent of anticipated construction costs have been funded. TIEC reasoned that the proposed rule creates a risk that a borrower could receive its TEF loan early in construction and then fail to achieve commercial operation. Calpine had a similar recommendation, but for 40 percent of anticipated construction costs, and that such funds should go into the project first, prior to the applicant receiving funds from the loan program to further ensure the applicant's creditworthiness.
Golden Spread recommended reducing the equity requirement from 40 percent to 20 percent in §25.510(h)(1)(B)(ii).
Vistra suggested that loan disbursements should not be limited to 60 percent of incurred costs.
Advanced Power stated that §25.510(h)(1)(B) does not address the issue of re-borrowing and requested clarification on whether TEF will include revolving facilities.
Commission Response
The commission agrees with suggestions by TIEC and Calpine that, prior to TEF loan distributions, a borrower should fund a portion of its equity or other sources of funding contribution to project costs. However, the commission declines to predetermine the percentage of project costs to be funded using the applicant's other sources of funding before releasing TEF loan funds, and instead modifies §25.510(h)(1)(B) to allow for pro-rata contributions of other sources of funding based on the applicant's or its corporate sponsor's creditworthiness and the discretion of the commission.
The commission has eliminated from the rule the minimum 40 percent equity requirement, and so the modification recommended by Golden Spread is unnecessary.
The commission declines Vistra's recommendation to not limit funding to 60 percent of incurred costs. PURA §34.0104(b)(2) limits loans to "an amount that does not exceed 60 percent of the estimated cost of the facility to be constructed."
Proposed §25.510(h)(1)(B)(iii)-Construction and Term Loan Facility: Drawdown Certificates
Proposed §25.510(h)(1)(B)(iii) requires borrowers to submit a construction drawdown certificate to request disbursement of loan funds.
Calpine recommended using an independent third-party subject matter expert, in the field of dispatchable generation project development engineering, to assist in developing a form drawdown certificate. Calpine stated the use of a subject matter expert will reduce administrative burden and facilitate a more expedient review of drawdown certificates, as the form should require certification by an industry expert.
Commission Response
The required content of drawdown certificates will be determined during due diligence. The commission declines to specify the precise contents of a drawdown certificate in the rule and will use industry best practices in its development.
Proposed §25.510(h)(1)(C)-Equity Capital Contributions
Proposed §25.510(h)(1)(C) states that the commission will verify the borrower's required equity capital contributions (40 percent of the estimated capital cost of the project).
LCRA recommended removing the word "equity" from this section. Golden Spread recommended similar language and proposed reducing the 40 percent capital cost requirement to 20 percent. Vistra recommended adding "at least" before "40 percent" and eliminating "estimated."
TIEC suggested that developers should be allowed to self-fund more than 40 percent and use debt for remaining non-TEF funding requirements, rather than being required to use equity.
Commission Response
The commission modifies the rule to reflect that there is no explicit requirement for 40 percent equity. An applicant may submit its anticipated financing structures, which will be evaluated during due diligence. While proposed structures with various forms of debt for the non-TEF portion of the funding will be considered, priority will be given to applications with equity at the project level. Moreover, projects with higher levels of equity contribution or with financing structures with corporate guarantees of TEF project debt may yield more favorable evaluation results. The commission also modifies the rule to add, at (h)(8), the requirement for applicants who wish to use subordinated debt in place of equity to assume the cost of drafting any required subordination agreements.
The commission agrees with Vistra on deleting "estimated," but will not add "at least," given the lack of an explicit equity requirement. The commission modifies §25.510(h)(1)(C) to remove the explicit requirement of 40 percent equity to align with other provisions related to equity.
Proposed §25.510(h)(1)(D)-Interest
Proposed §25.510(h)(1)(D) states that interest on the loan amounts disbursed under the credit agreement will accrue at a fixed annual rate of three percent.
WattBridge suggested postponing the accrual of interest until the project has been commercially operational for three years as that coincides with the start of loan repayment. WattBridge suggested interest accrual before that third anniversary should be incorporated as additional project cost.
Commission Response
PURA §34.0104(f)(3) states that a loan "must bear an interest rate of three percent." The statute does not provide for postponing the accrual of interest, as recommended by WattBridge. Interest accrues daily during construction and until the third anniversary of the project's estimated COD. This interest may be capitalized in certain circumstances, as determined during the due diligence process. Only the portion of interest capitalized during construction is considered a project cost--see (e)(6)(H), where the commission adds interest accrued and capitalized during construction as an allowable project cost.
Proposed §25.510(h)(1)(E)-Voluntary Prepayment
Proposed §25.510(h)(1)(E) allows the borrower to voluntarily prepay the total loan amount under the credit agreement in whole or in part at any time without premium or penalty.
Vistra pointed out a typographical correction recommending removing the word "total" from this section.
Commission Response
The commission agrees that "total" in §25.510(h)(1)(E) is not applicable and modifies the rule for clarity. Voluntary pre-payments, including partial pre-payments, are allowed without penalty except that the loan agreement may require that applicants cover TEF interest rate breakage costs. Additionally, the TEF administrator will negotiate with a borrower seeking to prepay part or all of the loan other conditions related to prepayment, which may include the continuation of the performance, compliance, or audit covenants for the entirety of the envisioned 20-year loan period.
Proposed §25.510(h)(1)(F) - Collateral
Proposed §25.510(h)(1)(F) states that to secure the indebtedness under the credit agreement, the borrower will grant the commission a first priority security interest in all of its existing and after-acquired real and personal property related to the facility and in all of the outstanding equity interests of the borrower in the facility.
Advanced Power recommended allowing the developer the flexibility to grant shared first priority security interests to other counterparties. NRG also proposed allowing shared first priority security interest with hedge counterparties, enhancing cash flow stability for generation projects, benefiting project lenders. NRG stated the change would comply with the statutory requirement for the loan to be the senior debt secured by the facility, because sharing a senior security interest does not detract from the seniority of the interest. NRG provided redlines consistent with its recommendations.
Calpine suggested specifying how the collateral requirement relates to eligibility for PUNs and industrial generators.
TPPA requested clarification on whether this includes intellectual property, including, for instance, software leased to the facility by OEMs or other contractors.
Vistra stated that any commission remedy other than what is described in SB 2627 is prohibited and the Legislature only allowed appointment of a receiver as the remedy for default. Vistra stated, per SB 2627, the commission is barred from owning the real and personal property of the facility applicant and a security interest facilitates state ownership of private property in a default. Vistra provided redlines consistent with the recommendations.
Commission Response
PURA §34.0104(b)(3) states that TEF loans will be secured by project facilities. The commission disagrees with recommendations from Advanced Power and NRG to permit shared first priority security interest because the TEF loan is to be the senior debt of the project. In keeping with the requirement that any other debt must be subordinate to the TEF loan, the non-TEF debt of facilities associated with industrial load or PUNs must also be subordinate to the TEF loan.
Regarding TPPA's request for clarification, collateral is required for all project assets and equity. If intellectual property is a project asset, that intellectual property needs to be included as collateral. If there is intellectual property, leased or otherwise, the intellectual property itself or the lease to it needs to be included as collateral, though the underlying intellectual property will be governed by the lease.
The commission disagrees with Vistra's assertion that the commission's remedy--appointment of a receiver--conflicts with the commission requiring a security interest. The commission can hold the lien and exercise its interests via a receiver without taking ownership of the underlying assets.
Proposed §25.510(h)(1)(G)-Change of Ownership and Control
Proposed §25.510(h)(1)(G) states that a change of ownership and control occurs if greater than 50 percent of the equity interest in the project is sold to a third party. The borrower and third party must apply for change of ownership approval from the commission.
Advanced Power stated that it would be atypical for a lender to have control over these types of decisions and suggested that commission approval for a sale of equity interests above the borrower's direct parent should not be required. Advanced Power suggested limiting change of control to direct ownership of the asset securing the loan, not ownership above direct control.
Calpine recommended eliminating §25.510(h)(1)(G), suggesting change of ownership and control should not need commission approval as this sort of approval would not otherwise be required for a generating facility's change in ownership outside of the TEF loan context. Calpine further stated that it is not administratively necessary, because, as a registered PGC, the generating facility would be required to apply to amend its PGC registration should a change of control result in a change of corporate parent. Calpine recommended that if the commission deems this additional approval necessary, the commission should establish an administrative approval process for such an application, including the use of a commission-approved form with a specified timeline for approval.
WattBridge proposed a 60-day review period for change of ownership and control. For non-rate regulated assets that generally do not require commission approval, the purchase and sale of an existing GR can be completed in 30 days between the signing of the agreement and actual transfer, subject to the Hart-Scott-Rodino Act. WattBridge stated that a lengthy regulatory review process will dampen investor interest and diminish the value of a plant with a TEF loan.
TIEC suggested using the standard for change of ownership and control from sale, transfer, and merger (STM) regulations. TIEC stated that PURA §39.915 requires approval for any transaction where 50 percent of stock is sold or where a controlling or operational control will be transferred. TIEC noted that the higher, more robust standard in §25.510(h)(1)(G) is appropriate and should be used for this program because the program is taxpayer support for subsidized loans.
NRG suggested adding language that consent will not be unreasonably withheld and allowing 90 days for commission approval.
Commission Response
Given the use of public funds for a TEF loan, the commission determines that review and approval of an application to change ownership and control for TEF loan recipients is appropriate to ensure that a TEF-funded facility continues to meet TEF objectives after acquisition. Therefore, the commission disagrees with Advanced Power and Calpine that there should be no review or approval of such changes. The commission modifies (h)(1)(H) to require a third party acquiring a TEF-funded facility to meet the performance covenant of the facility and the audit and compliance covenants for the remainder of the borrower's loan term. In addition, the commission adds a sentence to (h)(1)(H) to signify that the commission's determination on a change of ownership and control does not affect any person's obligations under PURA §39.158.
The commission does not seek to place an undue burden on potential changes in ownership and control, agrees with NRG's suggestion to clarify the rule to note that consent will not be unreasonably withheld, and modifies the rule to reflect this clarification. However, the commission declines the suggestions by WattBridge, TIEC, and NRG to impose specific timelines associated with change of ownership and control approval because some transactions may involve complex arrangements that necessitate extensive review. Additionally, the commission declines TIEC's proposal to adopt the standards in PURA §39.915 to govern a change of control evaluation because the public interest concerns in a transaction involving the sale of a TEF-funded facility are not the same as the sale of electric utility assets. PURA §39.915 protects retail customers when there is a sale of assets of a rate-regulated entity. But in this rule, the commission's primary concern is that a TEF facility continues to serve ERCOT in the manner described in the borrower's application and loan commitments.
Proposed §25.510(h)(1)(H)-Compliance and Audit Covenants
Proposed §25.510(h)(1)(H) states that credit agreements include covenants requiring borrowers to meet loan eligibility and submit annual audits. If serving an industrial load or PUN, borrowers must show that the majority of electric facility output served the ERCOT power system.
Calpine recommended including a confidentiality clause. Calpine recommended that annual financial audits, credit assessments, and electric generating performance assessments, as well as the annual accounting showing output of the electric generating facility, are confidential and not subject to disclosure under Chapter 552, Government Code.
Vistra recommended the commission prioritize facilities that will participate fully in the market. Vistra further suggests that if the PUNs are funded, then only a prorated percentage of the generator's cost should receive funding. Vistra recommended that the proration should account for the amount of generation participating in the market.
TPPA recommended strengthening the "primarily" language to support ERCOT more than PUNs. Vistra recommended modifying the language to clarify that if the borrower also serves an industrial load or PUN, the borrower must also submit an annual accounting showing that the output of the electric generating facility primarily served the ERCOT bulk power system during the performance year. Vistra provided specific redline language.
Drax Group also suggested aligning the audit requirement with definition of "primarily." Drax Group proposed a definition for "primarily" that excludes any facility that contributes no less than 100 MW of capacity to ERCOT, regardless of whether the facility is serving load behind the meter.
Commission Response
The commission agrees with Calpine that certain aspects of the information required for loan performance monitoring may be commercially sensitive and confidential. Therefore, the commission modifies the rule to maintain the confidentiality of financial audits, credit assessments, and electric generating facility performance assessments.
In response to Vistra's recommendation that only a prorated amount of a PUN generator's costs should be eligible for a TEF loan, the commission modifies (g)(1) to allow only those costs related to the percentage of a PUN generator's capacity dedicated to ERCOT to be eligible for a TEF loan. However, the commission declines to modify the rule to prioritize facilities that will participate fully in the market because the universe of applicants is not known at this time, and the commission will fully evaluate all applicants based on the strength of their applications.
In response to TPPA's comment, the commission modifies (c)(1)(C) to define the requirements that an electric generating facility serving an industrial load or PUN must meet. Regarding Vistra's recommendation for an annual accounting, the commission modifies the rule to add subsection (h)(1)(I), which requires an electric generating facility serving an industrial load or PUN to submit an annual accounting showing its net capacity made available to ERCOT in the prior year, as compared to its nameplate capacity and the NCP demand of the associated industrial load or PUN.
The commission agrees with the Drax Group that the annual audit should align with the definition of "primarily." The commission adds the annual accounting requirement so that it may confirm that an electric generating facility associated with a PUN or an industrial load continues to reserve the primary portion of its capacity for ERCOT. However, the commission disagrees with the Drax Group's suggested definition of "primarily" because this suggested definition ignores the comparison between capacity dedicated to an industrial load or PUN and capacity dedicated to ERCOT. This comparison is essential for the commission's interpretation of "primarily."
Proposed §25.510(h)(1) and (h)(2)-Definitions for Credit Agreement and Depository Agreement
Proposed §25.510(h)(1) and (h)(2) define the following loan terms: credit agreement and depository agreement.
CPS Energy recommended recognizing that, according to §1208.002 of the Texas Government Code, any security interest connected to public debt obligations of a municipal utility system is statutorily perfected.
Vistra contended that the requirements of §25.510(h)(2) are inconsistent with the SB 2627 and should, therefore, be removed or modified.
Commission Response
The commission acknowledges CPS Energy's comment that any security interest related to public debt obligations of a municipal utility system is statutorily perfected. Accordingly, the commission adds new paragraph (h)(9) to allow an MOU or river authority to provide substitute documentation customarily associated with the issuance of a public security to meet all preceding requirements of subsection (h), including any obligations of the MOU or river authority under other applicable statutes. Any such substitute documentation must be prepared by an MOU or river authority at that entity's expense and must be on terms satisfactory to the commission.
The commission declines Vistra's proposed modification to the rule. While PURA §34.0108 specifies certain remedies in the event of default, it does not prohibit the inclusion of additional loan requirements. The requirements of §25.510(h)(2) are appropriate.
Proposed §25.510(h)(3) and (h)(4)-Definitions for Security Agreement and Pledge Agreement
Proposed §25.510(h)(3) and (h)(4) define the following loan terms: security agreement and pledge agreement.
CPS Energy asserted that certain agreements are not applicable to MOUs applying to the TEF loan. CPS Energy recommended additional language which would state that the remedy to the debtholder, in the event of default by an MOU, would reside in a rate covenant to compel the borrower to impose a rate sufficient to satisfy the debt obligations.
Commission Response
The commission acknowledges CPS's position that a public power entity is not able to consent to certain activities described in PURA §34.0108. Accordingly, the commission adds new paragraph (h)(9) to allow an MOU or river authority to provide substitute documentation customarily associated with the issuance of a public security to meet all preceding requirements of subsection (h), including appropriate remedies upon borrower default. Any such substitute documentation must be prepared by an MOU or river authority at that entity's expense and must be on terms satisfactory to the commission.
Proposed §25.510(h)(3), (h)(4), and (h)(5)-Definitions for Security Agreement, Pledge Agreement, and Deposit Agreement
Proposed §25.510(h)(3), (h)(4), and (h)(5) define the following loan terms: security agreement, pledge agreement, and deposit agreement.
Vistra recommended using only a security agreement that recognizes PURA §34.0108(c) as the remedy for default. Vistra argued that the mandate for each borrower to execute a security agreement, pledge agreement, and depository agreement conflicts with SB 2627.
Shell Energy proposed expanding the security lien on the project to use project assets as collateral for hedge agreements, either through a capped lien amount or on a pari passu basis, ensuring stable cash flow. Shell recommended that if a hedge agreement is not required, any monthly gross margin above 125 percent of the project's pro forma should go into the Debt Service Reserve Fund. If the project is delayed by nine months or exceeds the budget by 40 percent, the commission should have step-in rights, including auctioning the project to other Market Participants.
Commission Response
The commission disagrees with Vistra that the commission's remedies for a default should be limited only to PURA §34.0108. While PURA §34.0108 specifies certain remedies in the event of default, it does not prohibit the inclusion of additional loan requirements. The requirements of §25.510(h)(2) are appropriate.
The commission disagrees with Shell Energy's proposed amendments. The existing protections in §25.510(h)(3) are sufficient to safeguard public funds consistent with the restrictions of PURA §34.0108 and the purpose of TEF.
Proposed §25.510(h)(6) and (h)(7)-Events of Default & Remedies
Proposed §25.510(h)(6) outlines the events of default to which the borrower must agree. Proposed §25.510(h)(7) requires the borrower to agree to the remedies described in PURA §34.0108 following an event of default.
TPPA recommended detailing the procedures for determining when an event of default has occurred, how a borrower can respond, and what process the borrower must follow in a default. TPPA commented that program participants need to be able to understand what constitutes default, who will make decisions on whether default has occurred, and what the process is. TPPA further recommended confirming that any defaults not sufficiently covered by collateral would result in a loss to the fund itself.
NRG proposed the inclusion of standard provisions related to potential default, such as notice and opportunity to cure, materiality thresholds, and force majeure provisions. NRG argued that the legislature did not prohibit these provisions and the provisions are necessary to safeguard against default. NRG provided redlines consistent with its recommendations.
TCPA advised using standard contract provisions to determine if a default has occurred. TCPA noted it is not beneficial for the state to seek receivership for all breaches. To prevent default, TCPA recommended including reasonable notice and cure provisions in the final rule.
Calpine proposed that events in §25.510(h)(6)(B) through §25.510(h)(6)(E) should only be considered a default if the events pose a material adverse effect to the project or its finances. Calpine also suggested that the commission should have the discretion to waive a breach or default without penalty to the borrower. If a default is declared, Calpine recommended mandatory arbitration with a third-party expert. Calpine argued that not all breaches that do not result in a material adverse effect should be considered a default. Calpine provided redlines consistent with its recommendations.
Vistra recommended revising the language in §25.510(h)(6)(B) to include "Material breach."
Commission Response
The commission declines to further detail the procedures determining an event of default. Subsection (h)(1) provides for a credit agreement, and (h)(6) identifies specific events of default. The rules have sufficient general guidance which, combined with the credit agreement executed between the borrower and the commission, will govern specific procedures.
The commission confirms that a default not covered by collateral or other credit support would result in a loss for the fund. PURA §34.0108 does not prescribe any other mechanisms to recover losses.
The commission declines the rule modifications proposed by NRG, TCPA, Calpine, and Vistra. PURA §34.0106(c) requires performance standards to be included in a debt covenant, and a recipient's failure to adhere to such requirements will constitute a breach of the covenant. The commission will develop appropriate cure periods along industry norms as part of the standard loan documentation.
Proposed §25.510(h)(6)-Events of Default
Proposed §25.510(h)(6) outlines the specified events of default to which the borrower must agree.
Shell Energy proposed that a delay of 12 months in reaching the projected COD should be considered a default event. In such a case, the commission should have the right to auction the project to other Market Participants. This comment also applies to §25.510(h)(7).
LSP recommended removing breach of performance covenant from the events of default and instead proposes to require the project sponsor to develop a plan acceptable to the commission to cure the performance breach.
Commission Response
The commission declines Shell Energy's proposed modification to the rule. Per PURA §34.0104(h) and (i), the failure to timely construct or upgrade a project facility may result in the borrower forfeiting the three percent deposit of its project costs. The commission declines to further penalize any such failure as an independent default event.
The commission declines LSP's proposed modification to the rule. PURA §34.0106(c) requires performance standards to be included in a debt covenant, and a recipient's failure to adhere to such requirements will constitute a breach of the covenant. The commission will develop appropriate cure periods along industry norms as part of the standard loan documentation.
Proposed §25.510(h)(7)-Remedies for Events of Default
Proposed §25.510(h)(7) requires the borrower to agree to the remedies described in PURA §34.0108 following an event of default.
LCRA commented that the proposed default remedies in PURA §34.0108 are not applicable to certain potential borrowers under state law. LCRA argued that certain legal constraints may prevent the commission from appointing a receiver, as PURA §34.0108 suggests. LCRA commented that borrowers should only comply with the default remedy if the default remedy does not contradict existing law.
Sierra Club suggested the commission clarify that the commission will not own defaulted projects but will instead transfer the defaulted projects to a court-established receivership.
Commission Response
The commission acknowledges LCRA's position that a public power entity is not able to consent to certain activities described in PURA §34.0108. Accordingly, the commission adds new paragraph (h)(9) to allow an MOU or river authority to provide substitute documentation customarily associated with the issuance of a public security to meet all preceding requirements of subsection (h), including appropriate remedies upon borrower default. Any such substitute documentation must be prepared by an MOU or river authority at that entity's expense and must be on terms satisfactory to the commission.
PURA §34.0108(b) prohibits the state, including the commission, from owning projects or facilities, and §34.0108(c), (d), (e), and (f) clearly establish the receivership process, authorities, and requirements. The commission declines Sierra Club's suggestion to revise the rule.
Proposed §25.510(i)(1)-Escrow Deposit Requirement for Loan Disbursement
Proposed §25.510(i)(1) requires the borrower to deposit three percent of the project's estimated cost in a Texas Comptroller-held escrow account before the initial loan disbursement.
WattBridge recommended using letters of credit as an alternative for cash deposits for commercial efficiency. WattBridge notes that letters of credit are regularly used in lieu of cash and are a more commercially efficient use of capital.
Commission Response
The commission agrees that it is suitable for a borrower to provide a standby letter of credit in lieu of a cash deposit. However, to protect the commission's interest in advancing TEF projects, the letter of credit must be supported by a financial institution acceptable to the commission. Accordingly, the commission revises §25.510(i)(1) to allow for a standby letter of credit, but also adds standards for the types of institutions that are acceptable to support a letter of credit.
Proposed §25.510(i)(2)-Requirements for Withdrawal of Escrow Deposit
Proposed §25.510(i)(2) outlines the requirements for escrow deposit withdrawal.
TPPA asked what would happen if a borrower failed to timely request the return of its deposit. TPPA also asked what happens if the commission does not provide authorization to withdraw a borrower's deposit.
Commission Response
PURA §34.0104 describes the requirements applicable to borrower deposits. Under that section, if the commission does not authorize withdrawal of a deposit, then the comptroller must deposit any escrow funds to the credit of the Texas Energy Fund. Accordingly, sections 25.510(i)(2) and 25.510(i)(3) describe how borrowers may withdraw deposit funds, and §25.510(i)(4) directs the commission to instruct the comptroller to transfer the deposit to the Texas Energy Fund if a withdrawal is not authorized. Failure of the borrower to meet withdrawal conditions including a timely request would result in the commission determining a withdrawal is not authorized. In response to TPPA, the commission modifies §25.510(i)(4) to reflect that failure to notify the commission of project completion will result in a return of the deposit to the Texas Energy Fund.
Proposed §25.510(i)(2)(C)-Definition of Interconnection in ERCOT Region
Proposed §25.510(i)(2)(C) explains that for the purpose of this subsection, interconnection occurs when the electric generating facility is physically connected and able to inject energy into the ERCOT region.
WattBridge proposed linking escrow funds' withdrawal to ERCOT's Part 2 approval during commissioning, which occurs when resources are able to enter the real-time market. WattBridge recommended adding "as outlined under the Part 2 process" to this proposed section.
Commission Response
The commission declines WattBridge's suggestion to use Part 2 in determining interconnection. For the purpose of this subsection, interconnection occurs on the resource commissioning date, as established in the ERCOT Nodal Protocols, of the last GR that is part of an electric generating facility financed by a loan under this rule. The commission modifies §25.510(i)(2)(C) to reflect this change.
Proposed §25.510(i)(4)-Evaluation & Decision Process for Deposit Withdrawals
Proposed §25.510(i)(4) states that the commission will evaluate each notice of satisfaction to determine whether the borrower is entitled to withdraw its deposit. If requirements are met, the deposit is returned. If not, the deposit is transferred to the TEF.
TPPA requested more details about the approval process for a withdrawal request.
Commission Response
The commission declines to modify the rule to provide further details of a withdrawal request because §25.510(i)(3) describes the process for filing a notice of satisfaction upon the occurrence of an event that entitles a borrower to a return of its deposit. Borrowers seeking authorization for withdrawal must file a notice with the commission that includes information required in (i)(3). The commission declines to make any changes in response to TPPA's request for clarification.
Proposed §25.510(j)-No Contested Case or Appeal
Proposed §25.510(j) states that neither an application for a loan nor a request for withdrawal of a deposit is a contested case. Commission decisions on a loan application or request for withdrawal of deposit are not subject to motions for rehearing or appeal.
Vistra suggested proceedings under this rule should be contested cases subject to judicial review. Vistra asserted that all commission actions are either contested cases or rulemakings governed by the Texas Administrative Procedure Act (APA). Accordingly, Vistra recommended delegating authority to the commission's administrative law judge under 16 TAC §22.32, and processing applications under 16 TAC §22.35. Vistra offered a proposal for streamlined contested cases, where intervention would be limited to the applicant and commission staff.
TPPA requested clarification on whether the rule would prohibit all forms of appeal, including judicial review.
Calpine suggested applicants should be allowed to supplement or refile denied or deficient loan applications without prejudice, avoiding the need for a contested case proceeding. Calpine added that if the commission does process applications through contested case procedures, the only parties should be the applicant and commission staff.
NRG opposed a contested case process for making determinations on applications. NRG commented that contested case procedures were not workable given the statutory timelines for application determinations and loan disbursements. NRG recommended that if the rule were to be revised to include a contested case process, the rule should be clear that the proceeding would only include the applicant and staff, and the contested case would be processed in an informal manner without hearing.
Commission Response
The commission declines Vistra's recommendation to modify the rule relating to contested case procedures. A contested case is a proceeding in which a state agency determines the legal rights, duties, or privileges of a party after an opportunity for an adjudicative hearing. No part of Chapter 34 of PURA provides an applicant the opportunity for an adjudicative hearing relating to a request for TEF funding. The commission interprets the absence of an opportunity for hearing to signify that contested case rights under the Texas APA do not apply to any application for a loan, change of ownership request, or request for withdrawal under this rule. Consequently, applicants do not have the opportunity to move for rehearing or seek judicial review under the Texas APA because those rights are exclusively associated with contested cases.
Commission determinations on loan applications are final. The limitation of an appeal mechanism reflects that the commission will not develop an internal appeal process. The commission is unable to provide further clarification in response to TPPA because it does not have the power to define the jurisdiction of Texas courts with respect to the various challenges that applicants may present in relation to this rule.
The commission agrees with Calpine, TPPA, and NRG that the absence of Texas APA contested case procedures does not prevent an applicant from supplementing or revising an application upon the request of the commission after initial application submission.
This new rule is adopted under the provisions of PURA §§14.002, which provides the commission with the authority to adopt and enforce rules reasonably required in the exercise of its powers and jurisdiction; 34.0104, which provides the framework to establish procedures for applying for a loan for construction of dispatchable electric generation facilities within the ERCOT region, evaluation criteria, and terms for repayment; 34.0106, which establishes restrictions on loans and requires the commission by rule to adopt performance standards based on reliability metrics appropriate for the types of facilities for which loans may be provided; and 34.0108, which establishes procedures in the event of a default.
Cross reference to statutes: Public Utility Regulatory Act §§14.002 and 34.0104, 34.0106, and 34.0108.
§25.510.Texas Energy Fund In-ERCOT Generation Loan Program.
(a) Purpose. The purpose of this section is to implement Public Utility Regulatory Act (PURA) §§34.0104, 34.0106, and 34.0108, which establish requirements and terms for loans to finance dispatchable electric generating facilities within the ERCOT region.
(b) Definitions. The following words and terms, when used in this section, have the following meanings unless the context indicates otherwise.
(1) Borrower--An applicant to the Texas Energy Fund who is successfully awarded a loan under this section and executes a loan agreement with the commission.
(2) Commercial operations date--The resource commissioning date, as defined in the ERCOT protocols, for the last generation resource that is part of an electric generating facility financed by a loan under this section.
(3) Generation resource--Has the same meaning as defined in the ERCOT protocols.
(4) 12-Month performance availability factor (PAF) --A metric calculated with ERCOT availability and real time (RT) telemetered data for each generation resource in an electric generating facility financed by a loan under this section. The PAF is computed as the average ratio of each generation resource's RT high sustainable limit (HSL) and its obligated capacity over a 12-month measurement period, expressed as a percentage. Intervals that occurred during an approved planned outage of a generation resource are excluded. The PAF is calculated as follows:
Figure: 16 TAC §25.510(b)(4) (.pdf)
(5) 12-Month planned outage factor (POF)--A metric calculated with ERCOT data for each generation resource in an electric generating facility financed by a loan under this section. The POF is computed as the percentage of time each generation resource spent in planned outages over a 12-month measurement period. The POF is calculated as follows:
Figure: 16 TAC §25.510(b)(5) (.pdf)
(c) Eligibility.
(1) A power generation company, municipally owned utility (MOU), electric cooperative, or river authority is eligible for a loan under this section. An electric utility other than a river authority is not eligible for a loan under this section.
(2) The following are eligible for a loan under this section:
(A) New construction of an electric generating facility having at least 100 megawatts (MW) of nameplate capacity with an output that can be controlled primarily by forces under human control. For purposes of this section, new construction of an electric generating facility means that the facility site has no existing point of interconnection to the ERCOT power region.
(B) An upgrade to an existing electric generating facility that results in a net increase of at least 100 MW of nameplate capacity for the facility with an output that can be controlled primarily by forces under human control. For purposes of this section, an existing electric generating facility already has a point of interconnection to the ERCOT power region, and the upgrade does not require an additional point of interconnection to enable delivery of energy from the increased capacity.
(C) A new or upgraded electric generating facility that is serving or will serve an industrial load or PUN, provided that the electric generating facility meets the following conditions: the portion of new nameplate capacity that will serve the industrial load or PUN must be less than 50 percent of the facility's total new nameplate capacity, and the remainder of new capacity serving the ERCOT market must be greater than 100 MW.
(3) In addition, to be eligible for a loan under this section, a proposed electric generating facility must:
(A) be designed to interconnect and provide power to the ERCOT region;
(B) be designed to participate in the ERCOT wholesale market;
(C) consist of one or more generation resources that interconnect to the ERCOT region through a single point of interconnection; and
(D) be eligible to interconnect to the ERCOT region based on the attributes of the owners of the facility, according to the requirements in the Lone Star Infrastructure Protection Act (codified at Texas Business and Commerce Code §117.002).
(4) The following activities are not eligible for a loan under this section:
(A) Construction or operation of an electric energy storage facility.
(B) Construction or operation of a natural gas transmission pipeline. For the purposes of this section, only the infrastructure necessary to connect an electric generating facility to a natural gas supply system may be considered part of the cost of the facility and eligible for a loan. Only those costs in support of new or upgraded capacity that is exclusively provided to the ERCOT region are eligible.
(C) Construction of an electric generating facility that met the planning model requirements necessary to be included in the capacity, demand, and reserves report issued by ERCOT before June 1, 2023.
(D) Construction or upgrade of an electric generating facility that will provide more than 50 percent of its nameplate capacity to an industrial load or PUN.
(E) Construction or upgrade of an electric generating facility that is capable of switching service at its point of interconnection between ERCOT and another power region.
(d) Notice of intent to apply.
(1) No earlier than May 1, 2024 and no later than May 31, 2024, an applicant must submit a notice of intent to apply in the manner prescribed by the commission. A corporate sponsor or parent may submit the notice of intent on behalf of a subsidiary applicant. Except as provided in paragraph (2) of this subsection, information submitted to the commission as part of the notice of intent to apply is confidential and not subject to disclosure under Chapter 552, Government Code. The notice of intent to apply must include:
(A) The applicant's legal name and the proposed name of the electric generating facility for which it seeks a loan;
(B) The anticipated nameplate capacity of each generation resource in an electric generating facility proposed to be financed with a loan under this section, and if the proposed facility will serve an industrial load or PUN, the net nameplate capacity of each generation resource that will be dedicated to ERCOT;
(C) The anticipated commercial operations date of each generation resource in the electric generating facility;
(D) The amount of the loan requested; and
(E) For each electric generating facility, if an applicant anticipates contributing equity in its application, a non-binding attestation demonstrating that the applicant, or a corporate sponsor or parent on the applicant's behalf, is capable of financing project-related costs not financed by a loan under this section.
(2) Concurrent with the notice of intent to apply, the applicant, or a corporate sponsor or parent of the applicant, must separately file a letter with the commission stating the applicant's legal name and the MW capacity that the requested loan amount will finance.
(e) Application requirements and process. A loan application must be submitted in the form and in the manner prescribed by the commission. The application portal will be open for an eight-week window, beginning on June 1, 2024, at 12:00 a.m., and closing on July 27, 2024, at 11:59 p.m. The executive director may extend the application window by providing public notice of the extension at least 30 days prior to the previously announced closing date. The executive director may also open additional application windows if necessary to achieve the objectives of this section. A corporate sponsor or parent may submit an application on behalf of a subsidiary applicant. Information submitted to the commission as part of the loan application process is confidential and not subject to disclosure under Chapter 552, Government Code. An application must include each of the requirements detailed in this subsection. An applicant may withdraw an application at any time while under commission review.
(1) The applicant's legal name and the proposed name of the electric generating facility for which it requests a loan.
(2) Amount of the loan requested.
(3) The anticipated nameplate capacity of each generation resource in an electric generating facility proposed to be financed with a loan under this section, and in the case of an electric generating facility that will serve an industrial load or PUN, the nameplate capacity of each generation resource that is proposed to be dedicated to ERCOT and the anticipated maximum non-coincident peak demand of the industrial load or PUN.
(4) Applicant information.
(A) A copy of any information submitted to ERCOT regarding the applicant's attestation of market participant citizenship, ownership, or headquarters, if submitted, or a direct attestation of market participant citizenship, ownership, or headquarters, if such information has not yet been submitted to ERCOT;
(B) Evidence of the applicant's experience with siting, permitting, financing, constructing, commissioning, operating, and maintaining electric generating facilities to provide reliable electric service in competitive energy markets;
(C) Evidence of the applicant's creditworthiness, including:
(i) A binding equity commitment letter, if the applicant proposes to fund any project costs using equity, or a binding letter with information regarding the applicant's other funding sources, demonstrating the ability to fund the balance of project costs separate from the loan under this section plus the required three percent construction escrow deposit amount; and
(ii) Audited financial statements for each of the previous five fiscal years of the applicant's operations, or if not available, audited financial statements of the applicant's corporate sponsor or parent company. Statements must include total assets, total liabilities, and net worth; and, if available for the applicant, its corporate sponsor or parent, or both, credit ratings issued by major credit rating agencies.
(5) Project information.
(A) A narrative explanation that details how the facility will contribute to reliably meeting peak winter and summer load in the ERCOT region, including the project's plans for ensuring adequate fuel supplies and preparations for compliance with §25.55 of this title (relating to Weather Emergency Preparedness);
(B) Demonstration of the project's eligibility under subsection (c) of this section, including a statement indicating whether any generation resource in the electric generating facility will serve an industrial load or PUN;
(C) Project-specific information that will allow the TEF administrator to evaluate the viability and attributes of the electric generating facility, and each individual generation resource, including:
(i) A table with the resource operation attributes, including nameplate capacity, heat rate, seasonal net maximum sustainable ratings during winter and summer, cold and hot temperature start times, resource ramp rate, and the original equipment manufacturer's estimated equivalent availability factor (EAF) calculation.
(ii) If any generation resource in the electric generating facility will serve an industrial load or PUN, an attestation of the net nameplate capacity of each generation resource that will be dedicated to ERCOT and nameplate capacity that will serve the industrial load or PUN, a description of how the electric generating facility will primarily serve and benefit the ERCOT bulk power system given its relationship to an industrial load or PUN, including details of all obligations or commitments of the electric generating facility to provide energy or capacity to the industrial load or PUN, and whether the proposed electric generating facility's generation capacity would be available to the ERCOT bulk power system during any Energy Emergency Alert, and a copy of any information submitted to ERCOT regarding PUN net generation capacity availability;
(iii) One-line diagrams of the proposed project for both transmission planning and the facility;
(iv) Evidence of site control, consistent with applicable ERCOT planning guide requirements;
(v) An up-to-date phase I environmental site assessment, conducted in accordance with standards identified in 40 C.F.R. Part 312;
(vi) A description of the electrical interconnection plan, including evidence that the proposed project is in the interconnection queue with ERCOT; a copy of the ERCOT screening study, if completed; and a copy of the full interconnection study with the interconnecting transmission service provider, if completed;
(vii) A description of the fuel and water supply arrangements, including copies of applicable fuel and water supply agreements, if available, and evidence of receipt of necessary water rights and applicable permits;
(viii) A description of the operations and maintenance staffing plan, organizational structure, and operating programs and procedures for the proposed project, including copies of operations and maintenance agreements, if available, and organizational charts;
(ix) A list of all required environmental, construction, and operating permits with current approval status;
(x) A description of the air emissions compliance plan, including evidence of receipt of any required air emissions credits;
(xi) A detailed financial forecast of cash available for debt service, covering a period equal to the repayment period of the loan, including sources of revenue, capital, and an annual operating and maintenance budget; and
(xii) A proposed project schedule with anticipated dates for major project milestones, such as the start date for project engineering, construction start date, submission of available interconnection documents with ERCOT, completion date of the ERCOT screening study, completion date of the full interconnection study, execution of the standard generation interconnection agreement, if applicable, submission of applicable registration documents with ERCOT and the commission, and commercial operations date.
(6) Estimated costs. A description of estimated project costs, which includes:
(A) Development, construction, and capital commitments required for the project to reach completion;
(B) Permitting-related costs;
(C) Development fees;
(D) Land acquisition and lease costs;
(E) Legal fees;
(F) Up-front fees;
(G) Commitment fees;
(H) Interest accrued and capitalized during construction;
(I) Ancillary credit facility fees, if applicable;
(J) Title insurance; and
(K) Interconnection costs.
(f) Evaluation Criteria. The commission will approve or deny an application based on the criteria and TEF administrator evaluations outlined in this subsection. Evaluations and other recommendations provided by the TEF administrator are advisory only. All final decisions on whether to approve or deny each application will be made by the commission.
(1) The TEF administrator will evaluate an application under this section based on:
(A) The applicant's or its corporate sponsor or parent's:
(i) Quality of services and management and proposed organizational structure for the project for which the applicant seeks a loan;
(ii) Efficiency of operations, as shown by the applicant's existing generation resources and asset management practices;
(iii) History of electricity generation operations in this state and this country;
(iv) Resource operation attributes, including fuel type and heat rate, seasonal net maximum sustainable ratings for winter and summer, cold and hot temperature start times, resource ramp rate, and the original equipment manufacturer's estimated EAF;
(v) Ability to address regional and reliability needs;
(vi) Access to resources essential for operating the facility for which the loan is requested, such as land, water, and reliable infrastructure, as applicable;
(vii) Evidence of creditworthiness and ability to repay the loan on the terms established in the loan agreement, including the applicant's total assets, total liabilities, net worth, and credit ratings issued by major credit rating agencies;
(B) The nameplate capacity, total forecasted revenues, and total estimated costs of the facility for which the loan is requested; and
(C) The completeness of the application.
(2) The TEF administrator may also consider the following criteria:
(A) The suitability of the facility site to support the construction, operation, and maintenance of the proposed facility and to provide sufficient access to utilities;
(B) The sufficiency of the various construction and equipment supply contracts necessary to construct the facility;
(C) Whether and to what extent the proposed facility will serve an industrial load or PUN;
(D) The commercial feasibility of the facility's construction schedule, including the projected commercial operations date;
(E) The facility's proposed environmental permits and commitments;
(F) The reasonableness of the applicant's forecast of non-fuel operating and maintenance costs;
(G) The methodology used to construct the facility's financial forecast of projected net revenues, expenses, and cash flows;
(H) The sufficiency of the applicant's proposed sources of equity or other funding sources to cover the costs of the facility not funded through a loan provided under this section;
(I) Whether the facility can achieve the applicant's EAF and capacity projections over the life of the loan agreement; and
(J) The basis for the total projected construction costs, including project contingencies.
(3) The TEF administrator will conduct due diligence on each application to gauge the feasibility of the project. Each applicant must submit an independent engineer's report, signed and sealed by a professional engineer licensed in the state of Texas, at the applicant's own expense, that assesses the feasibility of the project, its location, and all supporting commercial agreements relating to fuel, water, site control, and interconnection. The TEF administrator may request that an applicant provide additional information it determines necessary to conduct a complete evaluation of the project proposal.
(g) Loan Structure. An approved loan will have the following characteristics:
(1) Consist of no more than 60 percent of the estimated cost of the electric generating facility to be completed, or in the case of an electric generating facility that serves an industrial load or PUN, consist of no more than 60 percent of a percentage of total estimated facility costs equal to the percentage of the total capacity of the facility that is dedicated to ERCOT;
(2) Be the senior debt secured by:
(A) the electric generating facility to be completed; or
(B) with regard to an MOU or river authority, the revenues of the applicant's utility system into which the electric generating facility will be incorporated and made a part of;
(3) Have a term of 20 years;
(4) Be payable starting on the third anniversary of the estimated commercial operations date of the electric generating facility as stated in the application;
(5) Be payable ratably on terms on which the TEF administrator and the applicant have agreed, based on the applicant's expectation of cash flows from the project and the TEF administrator's assessment of the applicant's cash flows; and
(6) With respect to a borrower other than an MOU or river authority, be structured as senior debt secured by a first lien security interest in the assets and revenues of the project.
(7) Notwithstanding paragraph (1) through (6) of this subsection, a loan accepted by a borrower that is an MOU or river authority may be in the form of a public security, as defined in Chapter 1201, Government Code, issued under Texas laws governing MOU or river authority financing, provided that the MOU or river authority, at its own expense, presents documentation of indebtedness satisfactory to the commission.
(h) Loan Terms and Agreements. A borrower must enter into one or more agreements with the commission that include the terms of this section.
(1) Credit agreement--the primary agreement between the borrower and the commission that will govern the terms and conditions under which the commission will loan funds to the borrower. The credit agreement will include the following key terms:
(A) Performance covenant--each generation resource in an electric generating facility that is financed by a loan under this section must maintain a PAF of at least 85 percent and a POF no greater than 15 percent, evaluated monthly, over the trailing 12-month period, throughout the term of the loan.
(B) Loan facility--a senior secured first lien loan facility will be advanced to the borrower in one or more drawdowns after the closing date of the credit agreement and upon satisfaction of any conditions precedent, and may continue until the project achieves commercial operation. Amortization schedules for the loan facilities will be determined during due diligence and specified in the credit agreement.
(i) Upon initial closing of the credit agreement and after the borrower has met the conditions precedent outlined in the loan agreement, the borrower may request an initial loan disbursement for up to 60 percent of qualifying and documented incurred expenses that are part of the total estimated cost of construction for the project, as verified by the TEF administrator. Equity may be funded pro rata with TEF debt or may be required in its entirety prior to funding of TEF debt, based on the credit quality of the application and discretion of the commission and as outlined in the loan agreement.
(ii) During the period of construction, the borrower may request loan disbursements for up to 60 percent of the documented project construction and commissioning costs.
(iii) For all loan disbursements, the borrower must submit a construction drawdown certificate in the form specified by the commission. The TEF administrator will review the construction drawdown certificate and, upon the TEF administrator's approval, will instruct the Texas Treasury Safekeeping Trust Company to disburse funds.
(C) Other capital contributions. The TEF administrator will verify the borrower's ability, or the ability of the borrower's corporate sponsor, to fund the required commitment of the balance of no less than 40 percent of the construction and commissioning costs.
(D) Interest on the loan amounts disbursed under the credit agreement will accrue daily at a fixed annual rate of three percent, starting at initial disbursement and continuing throughout the term of the loan.
(E) Voluntary prepayment--the borrower may voluntarily prepay the loan amount under the credit agreement in whole or in part at any time without premium or penalty, except that the loan agreement may require that borrowers pay any breakage costs associated with the loan, and the borrower must agree to adhere to the terms of the performance covenant for the duration of the 20-year term.
(F) Collateral--to secure the indebtedness under the credit agreement, the borrower, other than an MOU or river authority, will grant the commission a first priority security interest in all of its existing and after-acquired real and personal property related to the facility and in all of the outstanding equity interests of the borrower in the facility.
(G) Registration--prior to the initial loan disbursement, the borrower must register with the commission as a power generation company, unless the borrower is an MOU, electric cooperative, or river authority. The borrower must also agree to register each generation resource in the electric generating facility with ERCOT, according to ERCOT's registration requirements in its protocols for generation resources.
(H) A change of ownership and control occurs if greater than 50 percent of the equity interest in the project is sold to a third party. The borrower and the third party must submit an application for change of ownership and control commission, that meets the eligibility requirements of subsections (c) and (e) of this section. The acquiring third party must agree to adhere to the terms of the performance covenant in paragraph (1)(A) of this subsection and compliance and audit covenant in paragraph (1)(I) of this subsection for the remainder of the 20-year term of the borrower's loan. A change of ownership and control will require the commission's approval, and such approval will not be unreasonably withheld. Upon approval of a change of ownership and control, the acquiring third party must update the power generation company registration and the generation resource registration to reflect the change of ownership and control. The commission's determination on a change of ownership does not impact any person's obligations under PURA §39.158.
(I) Compliance and audit covenants--the credit agreement will include debt covenants requiring the borrower to meet all statutory requirements for loan application eligibility and a debt covenant requiring that the borrower submit annual financial audits and credit assessments throughout the term of the loan. If the borrower's electric generating facility serves an industrial load or PUN, the borrower must also submit an annual accounting, at the generation resource level, showing the capacity made available exclusively to the ERCOT bulk power system during the performance year. The annual accounting must consist of a comparison between the sum of the nameplate capacity of each generation resource in the electric generating facility and the maximum non-coincident peak demand of the associated industrial load or PUN. Annual financial audits, credit assessments, and electric generating facility performance assessments submitted under this section are confidential and not subject to disclosure under Chapter 552, Government Code.
(2) Depositary agreement--an agreement between the borrower and commission that will give the commission, as lender, control over the borrower's deposit accounts and securities accounts to perfect the commission's security interest in those accounts.
(3) Security agreement--an agreement between the borrower and the commission that will authorize the commission, as lender, to take control of and transfer all material project assets in the event of a default on the credit agreement, subject to the applicable procedures and approvals identified in PURA §34.0108.
(4) Pledge agreement--an agreement between the borrower and the commission that will create a security interest in the equity interests of the project in favor of the commission as the senior secured party.
(5) Deposit agreement--an agreement between the borrower and the commission in which the borrower will agree to a deposit described in subsection (i) of this section.
(6) Events of default--the borrower must agree to specified events of default, which include:
(A) Failure to pay principal, interest, or other amounts due;
(B) Breach of a covenant in any agreement that has not been remedied within the time prescribed by the loan agreement;
(C) Inaccuracy of representations in any agreement;
(D) Bankruptcy or insolvency of the borrower; and
(E) Abandonment.
(7) Remedies for events of default--the borrower must agree to the remedies described in PURA §34.0108 following an event of default.
(8) Subordination and other agreements--to the extent that the project is to be financed by debt other than a loan under this section, each other creditor must agree that a loan under this section will be the senior debt secured by the facility. The borrower will be responsible for the preparation and costs associated with any agreement necessary to maintain the senior position of the loan under this section.
(9) With respect to a borrower that is an MOU or river authority, the forms by which the requirements of paragraph (1) through (8) of this subsection are accomplished can be substituted by documentation satisfactory to the commission that is customarily used in connection with the issuance of public securities that are subject to approval by the Office of the Texas Attorney General or satisfied by reference to applicable Texas law. An MOU or river authority that presents documentation in accordance with this paragraph will be responsible for the preparation and costs of that documentation.
(i) Deposits.
(1) The borrower must deposit in an escrow account held by the Texas Comptroller of Public Accounts or provide in a standby letter of credit an amount equal to three percent of the estimated cost of the project for which the loan is provided. The terms of a standby letter of credit must permit a draw in full upon a commission determination that withdrawal of a borrower's deposit is not authorized under paragraph (4) of this subsection. The borrower must deposit the required funds or provide the standby letter of credit before the initial loan amount is disbursed.
(A) Standby letters of credit provided under paragraph (1) of this subsection must use the standard form standby letter of credit template approved by the commission. The original document of the standby letter of credit must be provided in a manner established by the commission.
(B) The standby letter of credit must be issued by a financial institution that is supervised by the Board of Governors of the Federal Reserve system, the Office of the Comptroller of the Currency, or a state banking department and is a:
(i) U.S. domestic bank with an investment-grade credit rating; or
(ii) U.S. domestic office of a foreign bank with an investment-grade credit rating.
(2) The borrower may not withdraw the deposit from the escrow account or terminate its standby letter of credit unless authorized by the commission.
(A) For deposits related to the construction of new facilities, the commission will authorize the borrower's withdrawal of its deposit funds or the release of the borrower's standby letter of credit, as applicable, if the facility for which the loan was provided is interconnected in the ERCOT region:
(i) before the fourth anniversary of the date the initial loan funds were disbursed; or
(ii) after the fourth anniversary but before the fifth anniversary of the date the initial loan funds were disbursed, if the commission finds that extenuating circumstances caused the delay.
(B) For deposits related to upgrades to existing facilities, the commission will authorize the borrower's withdrawal of its deposit funds or the release of the borrower's standby letter of credit, as applicable, if the facility for which the loan was provided is completed:
(i) before the third anniversary of the date the initial loan funds were disbursed; or
(ii) after the third anniversary but before the fourth anniversary of the date the initial loan funds were disbursed, if the commission finds that extenuating circumstances caused a delay in the completion of the project.
(C) For the purpose of this subsection, interconnection occurs when the last generation resource that is part of an electric generating facility financed by a loan under this section is issued a resource commissioning date, as defined in the ERCOT protocols.
(3) Upon the occurrence of an event that entitles the borrower to withdraw its deposit or request termination of its standby letter of credit--interconnection or completion of its project--the borrower will file a notice of satisfaction with the commission stating that the borrower requests the return of the deposit. The notice must state:
(A) A description of the event that the borrower asserts as justification for withdrawal of the deposit or termination of the standby letter of credit, including the date on which the event occurred and any relevant evidence required to support the assertion;
(B) The date of initial loan disbursement; and
(C) A detailed statement of extenuating circumstances, if any, that support the borrower's request for a late withdrawal of the deposit resulting from a delayed interconnection or completion of the project, as described in paragraph (2)(A)(ii) or (B)(ii) of this subsection.
(4) The commission will evaluate each notice of satisfaction to determine whether the borrower is entitled to withdrawal of its deposit or release of its standby letter of credit. If the borrower demonstrates that it has satisfied the requirements for withdrawal, then the commission will instruct the comptroller to return the deposit to the borrower or will release the borrower's standby letter of credit. If the commission determines that withdrawal is not authorized, including if the borrower fails to file a timely notice of satisfaction, then it will instruct the comptroller to transfer the deposit to the Texas Energy Fund or will direct a draw on the borrower's standby letter of credit and deposit the funds in the Texas Energy Fund.
(j) No Contested Case or Appeal. None of an application for a loan, a request for withdrawal of a deposit, or a request for approval of a change of ownership is a contested case. Commission decisions on a loan application or request for withdrawal of deposit are not subject to motions for rehearing or appeal under the commission's procedural rules.
(k) Expiration. This section expires September 1, 2050.
The agency certifies that legal counsel has reviewed the adoption and found it to be a valid exercise of the agency's legal authority.
Filed with the Office of the Secretary of State on April 3, 2024.
TRD-202401400
Adriana Gonzales
Rules Coordinator
Public Utility Commission of Texas
Effective date: April 23, 2024
Proposal publication date: December 15, 2023
For further information, please call: (512) 936-7322