2. Payment structures: flat vs. punctuated equilibrium

Payment structures across long-term storage offtake agreements typically contain a common thread of a fixed monthly charge for the actual storage capacity of the facility (measured in MW), regardless of the energy actually discharged in the period. This is as expected in a capacity-only arrangement, but is also common to energy-only offtake scenarios. In the latter case, there is a difference between the product delivered (MWh of energy) and the payment structure for the project ($/MW of capacity) that nonetheless is commercially workable provided the capacity charge is sized appropriately to cover O&M and financing costs.  In both cases, the periodic, committed capacity payments can support long-term limited recourse project financing for the storage project.  Additional variable charges, or adjustment to the fixed payments, may also be required to cover actual demand-related operational costs. 

These market norms for offtake agreements are, however, not the only payment structures present in the market.   Some utilities have proposed an alternative structure to long-term capacity payments that involves a large, up-front payment to the system owner upon achievement of commercial operation. This upfront payment would constitute, for example, 70% of an agreed net present value for the project, calculated by multiplying an agreed $/MW-of-capacity value by the project’s nameplate capacity. In this scenario, the remaining 30% of the project’s NPV would be paid out in equal periodic installments, ostensibly covering the O&M costs, any remaining debt service, and the owner’s return on investment. This structure seems almost too good to be true until factoring in two further details: first, in exchange for a 70% commercial operation payment, the owner is required to post performance security equivalent to the entire payment; and second, the offtaker places an absolute prohibition on liens on the asset, including as would secure project financing after the commercial operation date. Factoring these in, commercial lenders would be unlikely to lend to such a project on a long-term, unsecured basis, yet the large performance security would require some kind of collateralization or asset base. Combined, the owner would likely be forced to carry the cost of capital after commercial operation on its own balance sheet. The commercial viability of such an arrangement remains to be proven.

3. Pricing: How much is enough?

A further complication for developers and utilities to consider is how to value  any revenues the project might generate after the offtake term (e.g., merchant revenues or signing-up a replacement offtake contract), and the extent to which such value should be considered within the offtake agreement itself. An offtaker might suggest that such valuation be considered at the outset of the offtake contract if the term of the contract is shorter than the expected life of the project,  and on this basis push to reduce the price of monthly capacity payments. There are several key risks to this. First, there is residual, unproven technology risk, since utility-scale BESS projcts have not been in operation long enough to assure owners and their lenders of revenue flows as many as 15 years after commercial operation. Further, the current dynamics in the BESS storage market are so volatile, with evolving technologies, falling costs, fluctuating utility and state PUC standards and uncertain private demand that accurate predictions of merchant revenues at the end of any long-term agreement are extraordinarily difficult to model. Lenders, of course, would be reluctant to lend past the committed offtake term, but investors too may seek to limit their exposure.  Thus, accounting in present capacity pricing for NPV values of future revenues after the offtake term may be a non-starter in the utility-scale generation space. Developers will predictably push to have the pricing reflect the cost of building, owning and operating a storage facility only for the committed term of the agreement.

4. Capacity rating: How often is too often?

How frequently should a plant’s capacity be tested? The capacity rating of a project is its key revenue driver since payments and pricing are typically structured on a $/MW basis. However, as a matter of chemistry, BESS projects are in a constant state of degradation. Developers know how to work around this, through a mix of facility overbuild, augmentation, expansion, and replacement. But degradation patterns are not always stable and predictable in this evolving technical space, especially where the BESS project’s operational use can vary and be strained (even within agreed operating use limits).  With their payment obligations tied to capacity, offtakers will of course want to know as soon as they can if their payments no longer match up to the actual capacity of the system. At the same time, they of course want confidence that a minimum capacity level is always present, and in pursuit of this will seek firm capacity supply commitments, while assessing liquidated damages and imposing strict termination rights when capacity falls short. A key debatable point, therefore, is how to set, test, and reset the capacity rating of a plant over the term of the offtake agreement.

The capacity rating of a more traditional solar plant, for instance, is unlikely to be tested after passage of commissioning tests, since degradation patterns in PV modules are more predictable and well-proven and output capacity is highly variable because of the intermittence of solar energy. BESS project offtakers, however, typically seek far more frequent testing regimes, in some cases as often as monthly, and in others upon demand. Developers and offtakers—inversely to each other— should view this with both a sense of caution and opportunity. On the one hand, frequent capacity tests can, in addition to being administratively burdensome and costly, mean that short-term performance shortfalls will be promptly recorded, reducing monthly payments between tests or even triggering liquidated damages. On the flip side, frequent testing allows a plant to reset its rating after a temporary, curable shortfall or after a capacity-enhancing augmentation investment.

To illustrate, consider the following scenario: A 100 MW name-plate BESS project is obligated to maintain capacity at 98% of nameplate during the term; monthly storage payments are calculated on a $/MW of as-tested capacity basis up to a cap of 105% of nameplate; and monthly testing is mandated under its storage capacity offtake agreement. The system was overbuilt by the developer and regularly achieves 105 MW in its testing. Due to a risk event contractually allocated to the developer, however, the capacity was tested in a single month at 98% of nameplate, causing a reset of the monthly storage capacity payment down to the same 98% of nameplate (and further down from the 105 MW), but only for the outlier month. Now consider this scenario where testing occurs annually: the temporary drop in the instant month would reduce developer revenue for up to the next twelve months.

Thus, there will always be tension between the developer and the offtaker regarding the frequency of capacity testing.  Regardless of where the happy medium falls, it seems reasonable and in both parties’ interest for the developer always to have the opportunity to immediately cure and retest following a low or failed capacity test. In all events, the testing and curing terms must be carefully considered and clearly spelled out in the drafting of the offtake agreement.

5. LDs All Around: Substantial Completion vs. Commercial Operation Deadlines

An offtaker may sometimes seek to impose liquidated damages for delays beyond stated deadlines in a project’s achievement of each of “substantial completion” and “commercial operation”. Such a position is presumably based on the theory that substantial completion conditions are determined primarily by the underlying engineering, procurement and construction arrangement, and that commercial operation is typically defined independently, with both overlapping and sometimes distinct conditions, by either the offtaker or, in certain utility cases, a regulator. The doubling of these guaranteed milestones, however, should be considered in light of legal enforceability rules and commercial reasons. To be enforceable as a matter of law, liquidated damages must be a reasonable estimate of an offtaker’s actual damages. Substantial completion milestones in offtake agreements, however, may not assume achievement of a project’s actual commercial operability at all, meaning financial losses for an offtaker for failure to deliver product would not yet have materialized. Thus, liquidated damages for delayed substantial completion that are charged on a $/MW per day basis would only be a reasonable estimate of damages if the delay in achieving substantial completion caused a delay in achieving commercial operation beyond the commercial operation deadline. In this case, an offtaker would in fact be unable to timely receive MWs of contract capacity in the expected commercial operation period. However, if the commercial operation is in fact achieved by that deadline, then the offtaker will not have suffered a loss of available capacity, and any preceding delay in achieving substantial completion would have caused no actual damages. The application of liquidated damages in this instance would constitute a penalty that would be unenforceable as a matter of law.

An offtaker may still argue the commercial logic of imposing liquidated damages for delayed substantial completion on the basis that such delays forecast a commensurate delay to commercial operation and the ultimate materialization of financial loss. The liquidated damages, in this case, are intended to reflect heightened risk, rather than actual loss. A resolution of this tension between enforceability and commercial logic, therefore, may lie in adding to the agreement a mechanism that reduces daily delayed substantial completion liquidated damages to the number of days (if any) which commercial operation is actually delayed. For instance, if substantial completion is 10 days delayed, but commercial operation is achieved by its guaranteed date, then the owner should be refunded all of the delayed substantial completion liquidated damages. Correspondingly, if substantial completion is 10 days delayed yet commercial operation is only 7 days delayed, delayed substantial completion liquidated damages should be assessed only on 7 days of delay.

In the absence of this mechanism, project owners may be able to challenge the legality of substantial completion liquidated damages clauses, putting offtakers in the position of having to demonstrate actual damages arising from a delay in achieving substantial completion. That costly and time consuming “demonstration” (i.e. a dispute process) can be forestalled through careful foresight and drafting of the offtake’s liquidated damages clauses.

6. Charging costs, station load, and storage losses

Responsibility for charging costs and station load and storage losses may vary depending on the type of project and the technology deployed. Charging costs are operational costs directly tied to the periodic charging of the BESS, such as dispatch and distribution service charges passed through from a utility, and additional operational costs incurred in the process of charging, and may, depending on the structure of the offtake arrangement, include the per-unit cost of the charging energy itself.  Station load losses (aka station service) typically include day-to-day power draw required by the BESS in order to operate normally and apply to such functions as fans, climate control and HVAC systems, lighting, cooling tower functions, security, and other auxiliary systems of the facility. Storage losses refer to ordinary degradation of the state of charge of a BESS as typically occurs in electrochemical storage systems.

In a renewable generation-plus-storage project, the associated renewable generation station will typically commit to selling 100% of its energy to the offtaker, whether through the immediate sale of generated energy, or delayed sale of stored energy. This time delay causes both a delay in cash flow (stored energy is not monetized until sometime after the moment of generation) and a reduction in the overall quantum of energy sold due to station load losses and storage losses. If the associated generation project’s energy is not available, the owner may be required to make direct purchases of charging energy from the grid and should have the latitude to do so (subject to applicable grid considerations). This structure places full responsibility for charging energy costs (including potential arbitrage and savings) and storage losses in the hands of the project owner.

As mentioned above, a project that is fully dependent on the grid for its charging energy, however, would typically source its power from the utility offtaker itself through a tolling arrangement in which the offtaker/charging energy supplier retains title to all stored energy. How to account for station load and storage losses is a major consideration in the storage offtake agreement.

In the case of storage losses, the combination of delays between charging and discharging of the BESS, inevitable degradation in the BESS components which may reduce charging efficiency, and potential defects can add up to significant hits to a project’s RTE. These losses will typically be borne by the owner, subject to moderate allowances reflected in an RTE guarantee mechanism.

In the case of station load losses, the parasitic power consumption required to operate the BESS equipment, in particular the energy-intensive ventilation and cooling systems needed for maintaining safe facility operating temperatures, significantly move the needle – literally – of a battery’s state of charge (SOC). Offtakers often demand that this energy loss be metered and paid for separately from any charging energy supplied to the battery. While this provides simplicity and clarity around station load losses, not all BESS EPC contractors, including some of the major providers, allow for separate metering for station use. In these cases, sufficient allowance in the RTE guarantee of the offtake agreement will also need to be built-in to account for this substantial power draw. Setting the RTE allowance becomes more complicated in projects located in places with significant seasonal (and daily) temperature fluctuations – station use for cooling in summer heat (or daytime highs) will likely be significantly higher than in the cold of winter (or dead of night). Commercial and technical teams will have to work carefully through the RTE guarantee calculation to manage this weather-related station load risk. It could be that RTE guarantees should be structured to track seasonally-adjusted station load curves. Blending station load and storage loss metrics into a single RTE calculation has some other drawbacks. In times where station use is limited (either due to seasonal temperature fluctuation or operational efficiency), whatever RTE flexibility is afforded under the RTE guarantee can be used for ordinary storage losses caused by natural or operationally-caused capacity degradation. This favors project owners in some respects but masks critical performance shortfall warnings. It becomes difficult in these cases for offtakers and owners to hold project operators to efficiency standards within their control. BESS suppliers that are able to separately meter station load may therefore be a preferable option in projects where RTE is tightly measured.

Finally, commercial decisions must be made and documented concerning the cost (and eventual discharge) of charging energy prior to the commercial operation date. Since offtakers generally do not feel committed to an unproven project, they are reluctant to pay for any pre-COD charging energy, even if it is tolled through, in the same manner, it would be after commercial operation. A solution to this is for offtakers to bear the cost of charging energy but then have the right to receive the economic benefit of the sale of any discharged energy originating from charging energy received prior to commercial operation. In the absence of viable third-party sale options, offtakers would then be obligated to purchase the discharged energy at an agreed replacement price (typically linked to an acceptable market rate for power in the region of the project).

7. Availability guarantees: quality vs. quantity

The dynamics and pitfalls of BESS performance guarantees could fill a whole other article of 10 key issues. Here we highlight one of the subtlest and most severe that is often proposed and too easily overlooked in utility offtake arrangements: the role that actual capacity plays in measuring actual availability. Traditionally, availability is a measurement of a plant’s ability to discharge energy of any quantity at a given point in time. The focus of an availability test is not how much power, but if there is power at all, reflecting the quality of operation and basic technical durability of the facility.  Availability is thus an on/off ratio measurement for a plant, as measured over a specific period of time. Many offtakers, however, propose an availability calculation formula that incorporates a plant’s actual capacity as part of the measurement. This is often incorporated in addition to a separate capacity-specific calculation and guarantee. As such, a project with faltering capacity measurements would run the risk not only of tripping its capacity guarantee but also its availability guarantee, thus triggering double liquidated damage payments due to the same underlying issue.

Ideally, availability-applicable measurements can be fully divorced from capacity readings, in each case as expressed in the calculation formula. Establishing both short-term capacity tests that measure only MW capacity at a point in time, and period-capacity tests that measure capacity in MWh over several hours (or from full charge to zero charge) would allow for an availability test that does not also incorporate the variable of capacity. This will clarify the nature of any particular performance shortfall (i.e. only one key variable is measured per each test), and allow an offtaker to be appropriately compensated through reasonably assessed liquidate damages, as needed. Where a party makes a technical justification for incorporating capacity measurements into calculations of availability, we suggest including a clear prohibition on doubling liquidated damages assessments for the same capacity shortfall if it implicates both the capacity and availability guarantees.

8. Fair and legal: How to structure termination payments

Harsh termination-for-default remedies have worked their way into the storage offtake market such that defaulting owners may be required to accelerate and payout, as a sort of liquidated damage (without the use of such term) the full net present value of all remaining storage offtake capacity payments under the term. Furthermore, owners often are required to provide enormous performance assurances, which may tempt these more aggressive offtaker remedies at termination. But as discussed previously in respect of liquidated damage assessments at substantial completion, blanket termination payment provisions that have little-to-no bearing on actual losses or damages suffered by an offtaker due to an owner default may be unenforceable. Furthermore, in typical buy/sell contracts, a non-defaulting party is obligated to cover and mitigate its losses by seeking replacement sources for the products. Therefore, broad-brushed, over-reaching termination payments should not be the norm. Instead, termination remedy provisions should account for actual economic losses suffered by the offtaker as a result (after mitigation) of the termination, including actual third-party costs incurred in unwinding associated hedges or in entering into replacement arrangements.  

One metric for demonstrating economic loss is to reasonably calculate the difference (if positive) of the present value of a replacement storage offtake arrangement less the present value of all payments remaining under the term of the terminated offtake agreement. The economic loss calculation can be flipped for offtaker defaults, where the positive difference (if any) between the present value of payments under the terminated agreement and the present value of replacement arrangements should be paid out. One further contractual step that might reasonably settle termination remedies would be to net any amounts owing to a defaulting party at the time of default from any economic loss and costs of the non-defaulting party. Taken together, such provisions establish both a commercial balance between the parties and would survive review for unenforceability, thereby providing parties certainty and avoiding disputes.

9. Force majeure exceptions

Force majeure is a legal, commercial and operational thicket of issues. We highlight briefly here three core issues that often arise in the drafting and negotiation of storage offtake arrangements.

First, the form of storage offtake agreements (or their term sheets) often published in RFPs are notoriously devoid of specificity over which obligations are excusable by force majeure. Certain obligations are expressed so absolutely in their drafting that the legal intention of force majeure could be argued to be limited in that case, removing any relief for the obligated party. For instance, an RFP draft term sheet may establish certain guaranteed dates for key project milestones, without clarifying whether such dates may be extended due to events of force majeure. Is the guaranteed nature of the milestone intended to override Force Majeure protections? Or, where availability guarantees are set out in a contract, does the occurrence of a force majeure event relieve an owner from achieving the availability guaranty, and/or does the availability calculation formula factor in periods of force majeure caused outage? The ambiguity in these examples could be detrimental to an owner’s interest, and costly to both parties where the ambiguity leads to disputes.

Questions over the applicability of force majeure clauses can be substantially resolved by the use of careful and precise contract drafting. The force majeure clause itself should be drafted in such a way as to indicate the scope of a party’s obligations to which force majeure relief may be accorded; this scope often covers all obligations of a party other than payment obligations. The broad application of force majeure may also need to be accompanied by precise references to relief at various points in a contract and/or how relief will be accorded. Adding in specific reference to force majeure, however, may lead to ambiguity about why force majeure relief is explicitly referenced in respect of one obligation, but not another, even where the intention is for it to apply to both. Therefore, specific and precise drafting should be added to indicate that ad hoc references of force majeure relief do not prejudice the general application of force majeure relief to contract obligations, and are merely inserted for clarity or to add specific nuance to how force majeure relief is accorded in specific scenarios.

Second, utility offtakers commonly have control over facility charging and discharging as well as an influence (if not control) over curtailment decisions and obligations. These and other offtaker rights and responsibilities can be incorporated into force majeure clauses to the benefit of the owner, to the extent they prevent or hinder an owner’s operation of a facility. For instance, a utility may seek to press onto owners the risk of curtailment due to grid congestion when ordered by a transmission or system operator, even where the utility or its affiliate is the transmission or system operator and has discretion and an economic incentive to curtail some energy and capacity resources and not others. An Owner should be entitled to force majeure relief for such risks since they are entirely outside of its control.

In some cases, curtailment may not actually affect core owner obligations. For example, in a capacity-only contract, depending upon how actual capacity is measured, it may be possible for an owner to still measure and meet its capacity guarantees, even where the plant has been curtailed by the grid operator. This calls for contractually insulating the owner from grid risk by establishing in the contract performance standards and metering points that can be measured entirely through internal plant operation, to the exclusion of external grid availability.

And third, batteries present a known but misunderstood safety risk: fire. A recent high-profile Tesla megapack project in Australia caught on fire in July of 2021 during testing and pulled the entire system offline until early December of that year. More than 40 other such fires have occurred within large-scale lithium-ion BESS, the majority within the past 3 years. The intensity and longevity of lithium-ion battery fires can make such incidents highly risky for dry, fire-prone regions or dense urban environments. Therefore, force majeure provisions should be clear enough to manage and allocate fire risks as well as related regulatory risks if authorities deem certain BESS technologies too dangerous to operate in their respective jurisdictions. Now, force majeure clauses typically accord relief for government-ordered shutdowns or other regulatory changes that make project operation more expensive or impossible. But if regulatory orders are directed at BESS projects generally, or the type of system deployed by an owner particularly, it begs the question of who should bear the hindrance, change in safety regulation, or shutdown risk. Given their severity, careful force majeure drafting should address these scenarios and so allocate risk explicitly in advance of the occurrence of such incidents.

10. Data sharing obligations

Last, but not least, and though it may seem like a small piece of the overall operations of a BESS project, operational data can have enormous value for both owners and their utility offtakers. Both are seeking to navigate – and compete over – complex, unproven, and evolving technologies while riding a fluctuating and unpredictable market. Yet broad latitude in an offtake contract for offtakers to request – or absolute obligations to demand – facility operational and capital cost data can lead to disclosure of sensitive operating, proprietary, economic and financial information that could jeopardize an owner’s competitive edge. Nonetheless, language in offtake contracts setting out reporting and data sharing obligations are often set out as an on-demand, blanket handover task of any data related to the sale of the products or required to substantiate costs for the project. These requests should instead be carefully pared back to the specific data that is reasonably required by utilities’ safe and efficient monitoring of their energy and capacity suppliers. Often, utilities are obligated by local system operators, public utility commissions, and federal regulatory bodies to produce specific sets of data on generating assets like BESS projects. These requirements also should be enumerated as far as possible during the drafting and negotiation of the offtake agreement. The records sharing obligation should be tailored to those requirements. If regulatory reporting obligations change, they can make efforts to accommodate the information transfer, as required by law. We suggest spelling out the reporting obligations as precisely and reasonably as possible, therefore, in order to maintain owner business confidence.

Conclusion

The wild world of BESS project development and the proper commercialization of the relatively new and always evolving technologies deployed can catch many seasoned power-industry owners and offtakers off guard. We’ve attempted to help parties grasp only a few of the many unique features of these offtake arrangements, to help parties side-step some of the more well-known contractual gaps that may lead to unintended results or protracted disputes. More so than in well-established offtake arrangements such as renewable generation PPAs, offtake contracts for BESS projects still require significant, project-specific creative and critical thought to shape and maintain the intended deal for the life of the project. We hope this article kick-starts that process for parties assessing the core revenue contract for these projects.

About the author

Nathan Santamaria is a principal at the boutique energy transactions law firm Mercer Thompson LLC, based in New York. His practice focuses on project development and financing of renewables assets across the Americas, where he represents both blue chip companies and start-up developers, from mega projects to distributed generation portfolios. Nathan’s experience covers the spectrum of renewables technologies, including battery energy storage, wind, solar and emerging efficiency-oriented and low-carbon projects.