United States: Orrick Collaborates With ACORE On Defense Logistics Agency Energy Army OEI And Air Force OEA Request

1. Have you worked with the federal government before? If so, have you completed any energy projects with an energy security component with the Federal government? What roadblocks did you encounter during that process, especially those related to energy storage projects? How could the Government streamline the process?

Many of our members have successfully completed and financed renewable energy and storage projects that involve contracts with the Federal Government. The Army and Air Force's energy programs have resulted in several projects that our members have participated in.

Doing business with the Federal Government is unlike doing business with the private sector. In many ways that is a very positive thing. The credit of a long term power supply or similar contract with the Government is, all other things being equal, sufficient to attract reasonably priced capital to renewable energy projects being financed. Also, in many ways, the Services and the procurement specialists, especially DLA, have done a great deal to improve processes and outcomes in this area. Repeat deal-making and "lessons learned" have further refined both the industry's understanding of the Government's constraints and the Government's understanding of the constraints faced by the renewable energy industry, especially on the financing side. That said, challenges still remain in developing these projects and further improvements are necessary to continue forward momentum. The following are some brief thoughts regarding some of those challenges:

  1. Timing for Contract Execution. The Government and the renewable energy sector act and do business on very different timelines. From the renewable energy sector's perspective, the time it takes for the Government to (i) conceptualize a project, (ii) issue an RFI or other informal outreach, (iii) issue an RFP, (iv) make a selection under the RFP, (v) deliver a notice of intent to award and negotiate a financeable contract, (vi) obtain project approvals from the Office of Secretary of Defense (OSD), if applicable, or other relevant Department of Defense (DOD) sections and, finally, (vii) execute the final contract, is still too long. ACORE and its members note that this process has been significantly shortened over the last several years through processes such as involving OSD earlier in the process, using precedent from prior deals that have been financed by third parties on a project finance (and not only a balance sheet) basis, and a willingness to work with private parties to come to an agreement on financeable solutions. In spite of this progress, additional Government innovation is needed to shorten this process significantly to encourage additional industry participation.
  2. Timing for New Project Opportunities. The Army and the Air Force have made significant commitments to develop renewable energy projects; however, the slow pace at which new project opportunities are announced reduces interest and inhibits wider participation by the renewable energy industry in these project opportunities.
  3. Competition and Renewable Projects. Issuing a competitive solicitation for bundled renewable energy and storage appears to be an effective approach for potential project sites located on installations with no existing renewable energy resource. A single renewable energy company (or a team of companies) can provide a package that works for the specific needs of the installations.
  4. New Storage Capability on Existing Project Sites. Implementing new storage projects on installations where renewable projects are already located, especially those renewable projects that are owned by third parties and where financing has already occurred, may present some challenges. First, the relevant Service and DLA will need to work with the existing renewable project owner to determine if the addition of a new storage project will create challenges for the technical configuration of the existing renewable project facility. Second, if the renewable project is subject to a power purchase agreement with the Government the Government should determine the impact of a new storage project with respect to those obligations under the power purchase agreement. In cases where existing contractual relations could be substantially disturbed, a sole-source procurement with the original project owner may be a solution when there is "substantial duplication of cost to the Federal Government that is not expected to be recovered through competition." See 41 U.S.C. § 3304(b)(1)(A). As a first step, the Government should be prepared to engage in preliminary discussions with the existing project owners to determine the feasibility of adding a new storage project to the existing renewable energy facility.
  5. Authority. There are two primary ways that storage projects are supported by power supply contracts to which the Government can be a party to. The first, when a storage project is paired with power generation, is a power purchase agreement (or "PPA"). The second method, for a stand-alone storage project, is a tolling agreement. Please see the response to Question 3 below for a more robust discussion on these two types of agreements.

10 U.S.C. 2922a provides generally that the Services can enter into contracts for up to 30 years "for the provision and operation of energy production facilities" on DOD real property or private property. "Energy production facilities" are not defined in the statute, but historically this statute has offered justification for the Service to enter into long-term PPAs with developers. The better view of the statute, from ACORE's perspective, is that renewable energy facilities that have storage components as part of their offering should broadly qualify, collectively, as an energy production facility under this statute. In addition, to the extent that storage projects are supporting existing generation on the site, Section 2922a should also extend to a long-term agreement related to the storage project, whether a traditional tolling agreement or PPA.1

2. What information about an installation should be included in a future Request for Proposal (RFP) to allow a potential bidder to accurately estimate the size, configuration and cost of Energy Storage projects?

A request for proposals for energy storage projects should solicit the following information to elicit the most comprehensive responses:

  1. The type of energy storage technology(ies) permitted and the project's required technical and operating capabilities (for example, the ability of the project to discharge at its maximum capacity for a required number of continuous hours). In addition, any requirement that either the bidder or the storage technology have successfully completed one or more prior commercial deployments.
  2. A description of whether the energy storage project will be utilized as a stand-alone charging, storage and discharging resource, or instead whether it will be co-located with existing or new generation assets (and, if so, what type of generation assets).
  3. A description of the expected interconnection status of the energy storage project and any co-located generation assets. For instance, will the storage project be interconnected to a regulated distribution or transmission grid with the capability of the storage project selling its services in an ISO or RTO marketplace?
  4. A description of what products and services the energy storage project will be expected to provide. For instance, will the energy storage project be used to provide capacity, energy or ancillary services, or rather only to provide backup power in case of outages?
  5. Expected pricing for the energy storage project's products and services. As a related matter, the performance requirements and guarantees, and any associated damages for shortfalls, including for capacity, availability and efficiency of the energy storage project.
  6. Details regarding the project site, and anticipated contract structure and terms for the seller's use of the project site.
  7. Requirements regarding the bidder's experience and financial creditworthiness.
  8. The expectations for the project and the project site after the expiration of the contract term (e.g., government purchase option, or seller right to sell services into the grid, etc.).

3. Provide recommendations on contracting and, or, financing mechanisms that could support an energy storage project. Is there a minimum acceptable contract term length necessary for third party financed storage projects?

A utility-scale size energy storage project will in many cases need to be supported by third party financing. Third party financing sources, including commercial banks and tax equity parties, will typically require that the project be supported by a power sales contract similar to a firm power sales contract for generation assets supported by third party non-recourse debt. The structure and nature of these agreements in today's market depends on a variety of factors, including whether the battery storage project is stand-alone or co-located with generation assets, whether the project is interconnected into a regulated marketplace, and whether the project is "behind-the-meter" or "front-of-meter".

For large, stand-alone, utility-scale size battery storage projects interconnected in front of the meter, the more commonly used contracting method used is a tolling agreement, structured similarly to tolling agreements commonly found for sales of power from gas-fired generation facilities. The seller is paid a fixed capacity charge for the right of the buyer to use the project, as well as a variable energy or O&M charge for the actual charge, storage and dispatch usage of the project. Under such an arrangement, the battery is required to satisfy certain performance criteria for capacity, efficiency and availability, and the price paid to the seller is reduced in the case of performance shortfalls. This structure (and variants of the structure) has been employed widely and successfully in the recent California investor-owned utility requests for offers undertaken in light of California Assembly Bill 2514 (which requires the California IOUs to contract approximately 1.3 GW of energy storage by 2020).

For energy storage projects which are co-located with on-site generation assets, such as solar, wind or gas-generation assets, the contractual structure often employed takes the form of a PPA. The main differentiating factor between this type of PPA and those found in the market for as available renewable energy projects is that the PPA for a co-located project expressly contemplates the integration and use of the storage project with the generation assets. These PPAs will address important issues such as which party has the right to charge and discharge the battery and at what times, whether use of the storage project affects pricing, and what the performance requirements are for both the generation and storage projects.

There are a few key issues in both PPAs and tolling agreements that the Government should address that could impact financing:

  1. Termination and Events of Default. Beyond typical termination rights for true contractor events of default and termination for convenience (discussed below), the Government should limit additional rights to terminate the contract during the term, as adding additional termination rights or events could reduce the pool of available capital for a project. Before an event of default is triggered under either type of contract, reasonable cure periods should be allowed to the contractor. ACORE members understand that federal contracts must contain a termination for convenience right for the Government. Termination for convenience clauses should be tailored by the Contracting Officer to include a termination value schedule that provides for certainty of recovery to debt and tax equity providers upon a termination for convenience.
  2. Performance Security. Many energy storage projects utilize project-financing with a special purpose vehicle project company ultimately entering into the applicable contract with the Government. In order to facilitate financing and quantify exposure to the ultimate project sponsor, the Government should be prepared to accept reasonable performance security (in the form of a performance bond or letter of credit) in lieu of an unlimited parent guaranty of the project. In recent renewable projects, there have been extensive discussions with the Government about what constitutes a reasonable performance security amount and what is "market". ACORE does not have an official position about the market for performance security, but does encourage the Government to look to the private sector (including both the corporate PPA and utility PPA market) to assess a reasonable range.
  3. Commercial Contracting. If available, the Government should utilize the FAR Part 12 commercial items contracting regime when conducting procurements of this type, and should look closely at incorporated FAR clauses to make sure that additional obligations are not being placed on the contractor that are not required to be incorporated by reference or mandated by applicable law. Commercial items contracting tends to be the most flexible for all parties involved and the easiest regime for financing parties to understand, especially for items such as contract changes (which should be bilateral).

8. What types of state and local incentives state tax credits, rebates, etc. could be utilized to reduce the costs for storage, considering the systems are being installed on Federal property?

Projects that incorporate structures that allow the federal Investment Tax Credit (ITC) to be applied to the project's energy storage equipment capital cost may prove more competitive than storage projects that are not ITC eligible. Below is a summary of a few of the key tax issues applicable to energy storage projects:

  1. General ITC Eligibility for Solar Energy Storage Facilities. ITC for an energy storage component of a solar project is generally available if the non-solar energy (if any) used to charge the storage over the one-year period beginning with the project's placed-in-service date does not exceed 25 percent of its total energy inputs during that period. Moreover, the tax basis of the storage related equipment eligible for ITC includes only the cost of the total equipment that is proportionate to the solar energy inputs. For example, a $100 storage facility where 90% of the electricity it stores during the first year of operation is from solar sources would be eligible for ITC (as 75% or more of the inputs are from solar), but the amount of tax basis eligible for ITC would be limited to $90. If the percentage of input from renewable energy falls below the one-year amount in subsequent years, all or a portion of the ITC may be "recaptured" (required to be repaid to the government), as provided below.
  2. Location and Ownership of Solar Energy Storage Facilities. The location and ownership arrangements of a solar energy storage facility may impact its eligibility for ITC as follows:

    1. A storage facility owned by the owner of solar generation assets and located on the same site as the generation assets would qualify for ITC as a part of the solar generation assets, assuming the 75% threshold is satisfied.
    2. A storage facility that is not located at the same site as the generation assets or that is owned by a different taxpayer than the taxpayer that owns the generation assets, but that is "integral" to the operation of specific generation assets, may qualify for ITC, assuming the 75% threshold is satisfied. The "integral" to operation requirement may mean that placing the generation asset into service is dependent on placing the storage component into service. However, federal tax guidelines are not clear regarding whether a particular facility would be regarded as integral to the operation of a solar project, and it may be advisable to obtain a private letter ruling from the IRS for such a structure. Developers should expect that it will take anywhere from 6 months to a year to obtain such a ruling, even if the IRS agrees to issue one.
    3. A stand-alone storage facility that is not dedicated to a particular solar generation asset could possibly qualify for ITC, but this situation presents unique issues and may require the tracing of solar-generated electricity to the particular facility. In practice, it may be very difficult to pursue such a project without further IRS guidance. The IRS has indicated that it will provide additional guidance on these issues in the form of future proposed regulations.
  1. ITC Recapture. ITC "vests" at a rate of 20% per year over a 5-year recapture period. If there is a disposition or disqualifying use of ITC property in the first year of operation, there is 100% recapture; dispositions or disqualifying use in the second year result in 80% recapture; and so on through the recapture period. These same rules apply in the storage context with an additional special rule. ITC recapture would apply if, during any year of the 5-year period after the in-service date, solar energy inputs as a percentage of total inputs drop below the percentage determined during the first year of operation. If the solar energy inputs for a year drop below 75%, full recapture of the unvested amount applies. For example, if solar energy inputs on a $100 storage facility were 100% in year one but drop below 75% in year two, 80% of the $30 of ITC would be recaptured. If the drop below 75% in solar energy inputs occurs in year three, 60% of the $30 of ITC would be recaptured. If there is a reduction in the percentage of solar energy inputs below the first year's percentage of solar inputs (but still at least 75% solar inputs), there would be proportionate recapture. For example, if a $100 storage facility qualifies for $30 of ITC based on 100% solar inputs in the first year after the in-service date, but the percentage of solar inputs in year two drops to 75%, then there would be $6 of recapture (25% of 80% of $30).
  2. Depreciation Period. If energy storage assets are eligible for ITC, they would also be eligible for 5-year MACRS depreciation. If they are not eligible for ITC, they would appear to be depreciated over 7 years for federal income tax purposes.

10. What are the best states for energy storage projects, based on current markets, available incentives etc.?

The answer to this question depends largely on whether the storage facility is going to operate solely as a behind-the-meter system or participate in wholesale energy markets in some way. For behind-the-meter systems that are not offering output or capacity to an organized wholesale market, storage resources can function as load centers by charging from the grid or an on-site generation facility to reduce system load. Accordingly, having a storage system on site could provide an installation with peak-shaving capability, thereby enabling the installation to participate in retail or wholesale demand response programs.

For storage systems that are participating in organized wholesale markets, U.S. regional transmission organizations (RTOs) have developed a variety of approaches to facilitate storage facility participation in the wholesale markets. Currently, storage resources can participate as demand response resources and providers of ancillary services in each of the major RTO markets. RTO policies differ, however, with respect to the ability of storage resources to participate in wholesale energy and capacity markets. The Federal Energy Regulatory Commission (FERC) is currently evaluating ways in which it can encourage integration of energy storage resources into wholesale markets. A pending FERC rulemaking could standardize energy storage participation in wholesale markets.

Currently, the California Independent System Operator Corp. (CAISO) has been a leader among the RTOs with respect to integration of storage resources in wholesale electric markets. CAISO's successes are due in large part to a state mandate for California's three investor-owned utilities to procure a total of 1,325 MW of energy storage capacity by 2024. CAISO's market rules do not explicitly distinguish among resource types, but, in order to participate in CAISO markets, resources must have a minimum capacity of 0.5 MW, or 0.1 MW if participating as demand response, and they must provide this capacity for a minimum of 30 minutes in the real-time market, or 60 minutes in the day-ahead market. If an energy storage project can satisfy these eligibility requirements, it can participate in CAISO's energy and ancillary service markets as generators, "Non-Generator Resources," pumped-storage hydroelectric or demand response resources, or as part of an aggregation of distributed energy resources. Non-Generator Resources are defined under the CAISO tariff as "[r]esources that operate as either Generation or Load and that ... are ... constrained by a [MW hour] limit to (1) generate Energy, (2) curtail the consumption of Energy in the case of demand response, or (3) consume Energy.

Regulated markets offer far fewer opportunities for participation of energy storage resources that are owned independently from franchised electric utilities. Unless located in one of 15 states that have retail electric choice, or the District of Columbia, owners of energy storage resources are not permitted to make retail sales of electricity to third parties. Even among the 15 states that have retail choice programs, there exist limitations that could effectively prohibit owners and operators of storage resources from engaging in retail sales. Accordingly, unless participating exclusively in wholesale markets, energy storage facilities are typically located behind-the-meter, where they can be used to support both retail electric service reliability and participation in demand response programs. However, opportunities may arise within regulated markets for independent developers to install energy storage facilities beyond the retail meter in response to utility-specific requests for proposals for energy storage capacity. It is currently unclear if or how state public utility commissions would allow regulated utilities to pass through costs of energy storage services to retail electric customers.

12. What information would a bidder need regarding National Environmental Policy Act (NEPA) actions, such as an environmental assessment or environmental impact statement, at a particular Government site, to be able to respond to a RFP?

With regard to the NEPA review for utility-scale storage projects on military installations, it would be most helpful to bidders if, in the RFP, DLA provided the NEPA approvals that convey DLA's relevant findings about the project impacts, mitigation requirements or other constraints on project development, and any other guidelines or policies that DLA anticipates will be applicable to the proposed project.

The clearer and more detailed the NEPA approvals are, the better the bids will be. If a condition imposed on a proposed project through the NEPA process is clear (such as "restore any graded area to substantially the condition existing prior to grading"), then the bid can be made as precise and accurate as possible. If the conditions are unclear or contingent (such as "if protected species are observed in the vicinity of the project, the contractor will take appropriate action to avoid adverse impacts"), the bid will be less clear. Some of these less clear or contingent conditions may be unavoidable (e.g., monitoring for protected species), but to the extent possible DLA should avoid imposing conditions that are misleading, vague, or allow for wide variation in interpretation. At the same time, DLA should provide some flexibility to bidders in complying with conditions to account for unknown circumstances, potential technical and economic infeasibility, and new technologies.

Ideally, DLA will have completed the NEPA process when it issues the RFP. In that situation, DLA should provide bidders the final NEPA documentation. If there are assumptions, conditions or commitments in the Finding of No Significant Impact (or the related Environmental Assessment) or in a Notice of Determination with respect to an Environmental Impact Statement, then those conditions, assumptions and commitments would be taken into account in making a bid. If the NEPA review is ongoing, but the DLA has proposed draft documents, then it would be helpful for DLA to indicate its anticipated timeline for completing the NEPA review and direct bidders to the draft NEPA documentation. The draft documentation would provide a bidder with insight to the scope of the project, the potential impacts of the project that DLA has identified, and how DLA is proposing to mitigate those impacts. If DLA determines that the project is determined to be exempt from NEPA review or should be subject to an Environmental Assessment rather than and Environmental Impact Statement, then DLA should provide any relevant programmatic assessments and any decisions specific to the proposed project.

In the event that DLA has not begun the NEPA process or has not yet issued draft documentation, then DLA should provide bidders with the underlying factual information about the project and project site and any preliminary surveys or studies to aid the bidder in assessing whether there will be material conditions or limitations imposed on the project. For example, in the example regarding protected species above, the bidders may need to assess the likelihood of finding protected species on the project site, and the mitigation actions that would be required (which could vary by species). Therefore, it would be useful to have surveys of the sites in order to assess those probabilities and possible costs. Also, DLA may want to consider referencing final NEPA documentation for similar projects at military installations.

In the absence of a NEPA approval document, the following minimum information would be needed in order for the bidders to make an assessment of the NEPA-related risks and timeline. Providing the information below to bidders even when DLA has issued final NEPA approvals may be helpful because it will help bidders understand the origin and significance of any conditions or limitations set forth in the NEPA approvals, including such items as indicated in the following list.

  • The location, size and topography of the sites subject to the RFP.
  • The current use of such sites, and current status of any buildings, equipment, pipelines or other improvements on or under the sites, and any planned demolition to be required by the project.
  • The locations, size and value of wetlands, water bodies or protected habitat on or crossing the project site(s).
  • The frequency, type and uses of the project site by protected species that are known to the DOD or available in studies or surveys.
  • The degree of access available to third parties (or level of security), and timeline of such access, including the history of ownership and/or control by the DOD.
  • Former uses of the site by DOD, especially including field training, use of munitions (risk of ordnance), and possible releases of hazardous substances.
  • Availability of utilities for on-site work, including electricity, water and wastewater management or disposal if applicable.
  • A description of the requirements for the project, including any roads, buildings or utilities known to be required, and their locations, in connection with project construction and operation.
  • The location, condition and limitations on the use of laydown areas for construction materials.
  • The location of "sensitive receptors," if any, near the project site for purposes of noise control, glare control or other controls required to avoid health and safety issues, or property damage, to neighboring properties.
  • Any known restrictions upon excavation, boring, pile driving or other necessary construction activities.
  • A list of any known permits or approvals required to complete the project, including approvals of plans or activities on DOD property that would be subject to a base commander or other military control and oversight.
  • A list and description of project alternatives (if not covered in the NEPA approvals), so that the project developers can assess the relative impacts of the proposed project and anticipate environmental mitigation requirements.

Finally, DLA should inform bidders whether any governmental entity will retain or assume responsibility for any particular issues or activities of the proposed project, including those imposed as a result of the NEPA review. For example, if there are wetland impacts, and wetland mitigation is required, it will streamline the bid process to indicate whether or not the DOD will be implementing the mitigation requirements.

15. Do you have any other suggestions or comments that may help configure procurements, e.g. Government risk reduction, innovative procurement / finance, alternative deal structure models, industry trends, third party financing for storage? Do not be limited by these examples.

  1. Portfolio Considerations. It appears that the Army and Air Force may be considering aggregating multiple energy storage projects to serve multiple installations. Aggregating projects does create portfolio-associated risk for the project sponsor, which the sponsor and its financing parties will seek to mitigate. Financing parties will seek comfort that multiple projects are sufficiently isolated such that a problem or delay involving one energy project does not jeopardize the revenue from the contract as a whole. Thus, if considering an aggregated procurement, the Government should pay careful attention to the structure of the contract, especially considering events of default and provisions related to single-project terminations (as opposed to overall contract termination).

    One portfolio risk-reducing method is a contractor right to "off-ramp" or "shelve" a project if there is a significant development delay or hurdle to allow the rest of the projects to proceed while parties continue to seek to resolve challenges associated with the shelved project. This allows the contractor to continue to develop the additional storage projects while not placing the entire contract at risk.

  2. Leasing Considerations. On the real estate documents specifically, careful consideration should be given at the outset on the form of lease that is to be utilized. Leases that have accompanied recent solicitations have needed significant modifications in order to be financeable. Addressing these issues at the outside will save time and money for both the developer and the Government.

The content of this article is intended to provide a general guide to the subject matter. Specialist advice should be sought about your specific circumstances.

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These Terms shall be governed by and construed in accordance with the laws of England and Wales and you irrevocably submit to the exclusive jurisdiction of the courts of England and Wales to settle any dispute which may arise out of or in connection with these Terms. If you live outside the United Kingdom, English law shall apply only to the extent that English law shall not deprive you of any legal protection accorded in accordance with the law of the place where you are habitually resident ("Local Law"). In the event English law deprives you of any legal protection which is accorded to you under Local Law, then these terms shall be governed by Local Law and any dispute or claim arising out of or in connection with these Terms shall be subject to the non-exclusive jurisdiction of the courts where you are habitually resident.

You may print and keep a copy of these Terms, which form the entire agreement between you and Mondaq and supersede any other communications or advertising in respect of the Service and/or the Website.

No delay in exercising or non-exercise by you and/or Mondaq of any of its rights under or in connection with these Terms shall operate as a waiver or release of each of your or Mondaq’s right. Rather, any such waiver or release must be specifically granted in writing signed by the party granting it.

If any part of these Terms is held unenforceable, that part shall be enforced to the maximum extent permissible so as to give effect to the intent of the parties, and the Terms shall continue in full force and effect.

Mondaq shall not incur any liability to you on account of any loss or damage resulting from any delay or failure to perform all or any part of these Terms if such delay or failure is caused, in whole or in part, by events, occurrences, or causes beyond the control of Mondaq. Such events, occurrences or causes will include, without limitation, acts of God, strikes, lockouts, server and network failure, riots, acts of war, earthquakes, fire and explosions.

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