Clean Peak Energy Standard (CPS) 101

Maybe you’ve heard about the CPS, but never really got around to cracking open the regulations to understand how it really works. We get it – there’s a lot to keep up in the clean energy sector! In this post, we’ll give a quick intro to the CPS, including what it is, how it works, and what kinds of resources can participate. To go a bit deeper, fill out the form at the bottom of this post to receive a free copy of our CPS 101 slide deck.

Origins of the CPS

In 2018, Massachusetts passed legislation requiring the establishment of the Clean Peak Energy Standard (CPS). The primary goals of the policy are to reduce peak electricity demand, cut emissions, and lower ratepayer cost, by incentivizing generation/discharge/load curtailment during periods of high demand. The CPS is intended to be a key component of Massachusetts’ broader energy strategy, promoting storage, dispatchable clean resources, and flexible loads to more effectively integrate increasing quantities of energy from renewable resources with variable outputs.

Understanding the CPS Policy

The CPS introduces a novel approach, incentivizing the generation of clean energy precisely when it’s needed the most. The overall design is akin to a Renewable Portfolio Standard (RPS), but with a focus on periods of peak demand. Eligible resources that operate during specified periods produce Clean Peak Energy Certificates (CPECs), a tradeable commodity. Load serving entities (LSEs also known as power suppliers) are subject to a minimum standard, a percent of their total load that must be met with CPECs, creating demand for these certificates. LSEs that fail to procure the required number of certificates must pay an Alternative Compliance Payment (ACP), which sets an effective ceiling on the price of a CPEC. This yields a market-driven approach to boosting clean energy use when the grid is under the most stress.  

CPS Windows

At the core of the policy is the establishment of Seasonal Peak Periods (or windows), defined hours of the day (that changes by season) during which eligible resources can produce CPECs.  These windows, which are four hours long, are defined in the CPS regulations, enabling market participants to design the operations of their resources based on these windows. We would expect that, over time, as increasing electrification and deployment of distributed generation shift periods of highest net demand (and emissions), the Seasonal Peak Periods in the regulations will be updated.

Eligible Projects

Eligibility for producing CPECs extends to a range of technologies, including new renewables, existing renewables paired with storage, standalone storage, and demand response resources (which can include traditional load curtailment, electric vehicles, and other types of projects). This broad set of eligible resources aims to tap into a variety of clean energy sources and technologies to meet the policy’s goals at the lowest possible cost. While the policy is intended to be largely technology agnostic, it uses multipliers (see below) to adjust the volume of CPECs produced by different project types, primarily to reflect the availability of other sources of revenue for projects (e.g., SMART solar plus storage or contracted offshore wind projects). It also makes analyzing the market complex and challenging.

CPEC Multipliers

As a starting point, one MWh of discharge/generation/curtailment during a CPS window yields one CPEC. To keep things interesting, the CPS also includes multipliers that impact the volume of CPECs produced, sometimes increasing production (multipliers above 1), other times reducing production (multipliers below 1). Some multipliers are time-based, increasing production during certain seasons or peak hours. Other multipliers are resource-specific, such as those that apply to “contracted” resources or that provide an incentive for resources that can provide resilience. Most recently, DOER finalized Guidelines for the Distribution Circuit Multiplier, designed to drive deployment of CPS resources on load-constrained portions of the distribution system.

ACP and Minimum Standard Over Time

Like most Renewable Portfolio Standards, the percent of load that LSEs must meet with CPECs increases over time, increasing total market demand. Unlike most RPS policies, however, the ACP decreases over time, reducing the price ceiling for CPECs. Another twist: the pace with which the ACP and minimum standard change depends on supply and demand for CPECs. We know from experience – it’s a lot to wrap your head around and to analyze.

2024 Program Review

Change for the CPS is baked into the regulations themselves. Starting in 2024, and every four years thereafter, DOER will conduct a program review, considering, at a minimum, the ACP, the minimum standard, and the multipliers. To kick off the review, DOER issued a series of questions, seeking feedback from stakeholders by May 9. As discussed in the first post in this 2024 series, there are a lot of reasons to believe that we may see significant changes to the CPS in 2024, presenting a unique opportunity to influence and strategically engage in the market.

Learn More and Stay in the Loop

For additional information about the policy, fill out the form below to receive our CPS 101 slide deck. You’ll also receive future posts in this series, including any updates on changes that occur through the 2024 Program Review. For those who plan to participate in the CPS market, learn more about how a becoming a Clean Peak Market Outlook subscriber will give you unparalleled market insights and a competitive edge.

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Introducing Our 2024 Clean Peak Standard Blog Series: Navigating Changes and Shaping the Future

Chances are, 2024 will be a pivotal year for the Massachusetts Clean Peak Energy Standard (CPS). With nearly all of the policy’s elements implemented (with the notable exception of long-term contracting), there’s an opportunity (and a requirement) for the Department of Energy Resources (DOER) to conduct a comprehensive review of the program. The Clean Peak Market Outlook (CPMO) team will be here throughout, to help you navigate the shifting terrain and to provide analysis that enables you to advocate for change.

Why 2024 Matters for CPS Stakeholders

DOER’s 2024 program review is likely not just a routine check-in. Recommendations from the Charging Forward energy storage study and report and questions posed to stakeholders by DOER hint at the potential for a more strategic reevaluation, designed to enhance its effectiveness, mitigate ratepayer impacts, and ensure alignment with the Commonwealth’s climate commitments and existing clean energy programs. At a minimum, the CPS regulations require DOER to review the minimum standard, the alternative compliance payment, and the multipliers, which, together, are the very heart of the policy.

It’s no secret that the market is currently dramatically undersupplied. DOER’s 2021 RPS Compliance Report showed $35 million in CPS alternative compliance payments were collected for compliance year 2021, and we estimate this figure will be around $100m for 2023. For perspective, the highest ACP collections for Class I of the RPS (including solar carve-outs) ever was in 2021, at $37m. Furthermore, developers have expressed concerns with various elements of CPS (for example, through comments submitted through the Charging Forward study), particularly the challenge of financing storage on the basis of uncertain CPEC prices. [Shameless aside – addressing and mitigating this uncertainty is a large part of what CPMO is all about.]

Put these things together, and a reasonable person (which we could generally consider ourselves) would expect at least the consideration of significant changes to the policy. This potential for substantial change underscores the urgency for stakeholders to understand the evolving CPS landscape fully.

Our Blog Series: A Guide to Impactful Advocacy and Understanding

To navigate this pivotal year, we’re launching a blog series dedicated to unpacking the complexities of the CPS program and its implications for the future. Our series aims to equip developers, operators, investors, load serving entities ,and others with the knowledge they need to be more effective in their roles. Here’s what you can expect:

  • Intro to CPS: We get it. CPS may not be front of mind for you. We’ll help you get back up the curve.
  • Deep Dives into DOER’s 2024 Review: We’ll explore the nuances of the program review, highlighting changes, challenges, and opportunities for stakeholders to engage.
  • Analysis of Relevant Studies: We expect additional studies (such as a value of distributed energy resources study from the Clean Energy Center) to be released this year. We’ll highlight them and discuss interactions with CPS.
  • Review of Individual CPS Components: We’ll examine individual components of the program (e.g., long-term contracting, the ACP, etc.), discussing how they work, how they might change, and how they influence the overall market.
  • Projections and Market Outlook: For our subscribers, we’ll provide analysis and projections of supply, demand, and prices that help stakeholders understand and prepare for potential changes.

Stay Tuned and Sign Up

We’re excited to embark on this journey with you. Keep an eye out for our next post (CPS 101) in the series. Keep an eye on our blog for the next post (CPS 101) in the series. In the meantime, you can learn more about CPMO here and use the form below to get other posts in this series delivered directly to your inbox. We hope you join us as we navigate the changes, challenges, and opportunities of 2024 together.

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MA DOER Issues Final Clean Peak Standard Distribution Circuit Multiplier – early present is a mixed bag for storage

It’s here! On December 5, 2023, the Massachusetts Department of Energy Resources (DOER) released its Clean Peak Standard’s long-awaited Distribution Circuit Multiplier (DCM) Guideline which went immediately into effect. This followed an initial proposal in 2021, a February 2022 straw proposal, and an October 2022 Draft DCM Guideline, which we discussed in a previous blog post.  The DCM, you may recall, is intended to provide extra incentive (more Clean Peak Energy Certificates) for Clean Peak Resources interconnected on specified parts on the state’s distribution systems.

We’ll be providing detailed modeling of the impacts of the final Guideline in our next Clean Peak Market Outlook (CPMO) briefings, on December 19 (Market Briefing) and 22 (CPR Briefing), 2023 (there’s still time to sign up!). In the meantime, here are our initial key takeaways:

  1. Available MW way up. Perhaps the most impactful change relative to the October 2022 draft is an increase in the amount of capacity that could qualify for the DCM. While the October draft proposed a limit of 1 MW of DCM capacity per circuit, the Final Guideline allow up to 5 MW of DCM capacity per circuit for circuits of 15 kV class or larger, and up to 2 MW per circuit for smaller circuits (Demand Response resources do not count towards these caps). Based on the initial list of DCM eligible circuits, this results in potential added revenue for more than 1 GW of DCM capacity, 440 MW in National Grid territory, 615 MW in Eversource territory, and 25 MW in Unitil territory. For perspective, as outlined in October 2022 draft, total initially-eligible (read on for clarification) capacity would have been limited to approximately 320 MW.
  2. DCM value down. The October draft considered a multiplier of 2X for ten years following a unit’s effective date and 1.5X for years 11 through 15. The Final Guideline retain the 2X multiplier for the first ten years, but drop the 1.5X for subsequent five years. This change could reflect DOER’s understanding of the financial needs of DCM-eligible projects, recognition of the likelihood that the needs of a given circuit will change over a 15 year period, or other considerations – they have not yet explained their rationale. While this reduced duration of additional CPEC creation will certainly impact project economics, the declining alternative compliance payment (ACP) for Clean Peak Energy Certificates (CPECs) and the falling price for these certificates implied by this falling ACP will somewhat minimize the actual financial impact of eliminating the multiplier in years 11 through 15.
  3. Circuit eligibility largely unchanged. The methodology for establishing eligible circuits is largely unchanged from the draft. Eligibility will be based on a circuit’s three-year average Peak to Normal Percentage (effectively, peak demand on a circuit as a percent of its rated capacity). Ten percentage of each EDC’s circuits will be designated as DCM circuits, starting with the circuit with an 85% Peak to Normal Percentage, and descending from there. This approach excludes from DCM eligibility circuits with high saturations of solar, as outlined in DOER’s original straw proposal. Clean energy advocates had pushed for solar saturated circuits to be included in the final guideline; their exclusion will change the types of sites available for DCM resources, potentially slowing the pace with which DCM capacity is claimed. We note that the 1 GW of eligible capacity is based on the set of initially eligible circuits. As evaluated during our November 2022 Clean Peak Resource Module Briefing, because the circuit selection criteria will be applied annually, new circuits could become eligible, which over time, would increase the total volume of DCM-qualified projects. This turnover rate (quantified in the briefing noted above and updated in our upcoming December 2023 briefings) has critical implications for the availability of DCM capacity.
  4. Higher threshold for reserving DCM. The overall process for applying for the DCM is largely consistent with the October draft. The Final Guideline, however, introduces new and higher threshold requirements for projects seeking to reserve DCM capacity, including executing an interconnection service agreement (ISA), providing right to construct documentation, and securing non-ministerial permits.
  5. December 19th deadline for initial applications. The Final Guideline states that “all DCM applications received within the first ten business days of the application being available [by our interpretation, through 12/19/23] will be sequenced by ISA date to determine allocation of reservations.” Thereafter, projects will be evaluated on a first come, first served basis. The introduction of new application requirements (discussed above) may frustrate the intentions of some developers hoping to quickly secure DCM capacity. Completed ISAs will likely serve as the rate limiting factor as developers seek DCM eligibility. The CPMO team will closely monitor the volume of applications submitted by within the initial open period.

Of course, the DCM Guideline comes on the heels of proposed wholesale distribution tariffs (outlined in DPU dockets 23-115, 23-126, and 23-117),  that would govern the charging costs of distribution-connected resources participating in wholesale markets. The CPMO team has been tracking both developments closely, and is quantifying the cumulative impacts of these critical changes projections of total CPEC supply, demand, and price. Taken together, for those who participate (or plan to) in the CPS marketplace, quantifying the specific impacts of the Final Guideline is critical. Luckily, the CPMO team has done this. To make sure you have the benefit of the latest and most accurate market intel, contact us to become a subscriber.

MA ConnectedSolutions Changes: What They Mean for Project Revenue

Current CPMO subscribers – click here to log in for the subscriber version of this post, including additional details.

Developing energy storage can be complicated. For behind-the-meter (BTM) storage in Massachusetts, a successful project has a lot of potential benefit streams to consider, including:

  • SMART storage adder
  • Clean Peak Standard
  • Demand charge management
  • ICAP tag management
  • Retail rate arbitrage
  • ConnectedSolutions

Optimizing the configuration and operation of BTM storage to take advantage of the above has always been challenging. For those looking to take advantage of (or maybe even already participating in) the ConnectedSolutions program in Massachusetts, things are likely to get a little bit more complicated.

ConnectedSolutions Background

ConnectedSolutions is the branded name for demand response (DR) programs offered by energy efficiency/demand response (EE/DR) program administrators (PAs) in Massachusetts, Connecticut, Rhode Island, and New Hampshire. While it was originally designed for load curtailment, in 2019, the Massachusetts electric PAs (the Cape Light Compact, Eversource, National Grid, and Until), began allowing storage to participate in the program. Part of the appeal of the program is its relative simplicity: PAs call events, usually 2-3 hours long, the night before, approximately 30-60 times per summer season (for the Daily Dispatch option, which is designed primarily for storage). Participants are compensated by averaging their kW delivered across all event hours for the season, multiplied by a specified $/kW incentive (currently $200/kW). This incentive rate is locked in for a minimum of five years. So, a commercial & industrial (C&I) battery that averages 1 MW (i.e., 1000 kW) during all ConnectedSolutions hours of a given summer season (June-September), would receive 1000 kW*$200/kW-season = $200,000. To be eligible, the battery must be sited behind a retail meter with some non-parasitic load (more on this later).

Status and Proposed Changes

C&I storage participation in ConnectedSolutions has been modest. Results from the 2022 Massachusetts ConnectedSolutions season are included below. Statewide, the PAs planned for 14.5 MW of C&I storage, including Daily Dispatch and Targeted Dispatch (Targeted Dispatch provides a lower incentive and includes fewer events per season). Just over 11 MW enrolled, of which approximately 7 MW performed. The enrolled numbers suggest an average C&I storage commitment of 370 kW per participant (again – some mild foreshadowing happening here).

Source: February 8, 2023 presentation by Program Administrators to Massachusetts Energy Efficiency Advisory Council

On December 5, 2022, the PAs presented a ConnectedSolutions 2022 Year End Update. In the update, the PAs discussed two critical items for storage participating in ConnectedSolutions. First, the PAs stated that “sites that are net exporters of power during ConnectedSolutions events will have their performance capped at 150% of the site’s annual peak load less the nameplate capacity of the battery.” Second, the PAs highlighted an evaluation of the ConnectedSolutions program performed by DNV that recommended applying a baseline to C&I storage participating in Connected Solutions.

Unsurprisingly, industry stakeholders were not enthused about either announcement. On December 20 2022, CPower, EnelX, and Convergent Energy and Power (the “industry group”) submitted a letter to the Massachusetts Energy Efficiency Advisory Council (EEAC) expressing their concerns and proposing alternatives to the PAs’ plans.

We delve into more detail on the two changes below.

Size-to-load Restriction

The June 2022 (which appear to be current) ConnectedSolution program materials state that, in order for a customer to be eligible, they must “pay into the energy efficiency fund on their electric bill where the demand response savings will be implemented” and that the storage system “must be considered behind-the-meter,” meaning that the facility “serves an on-site load other than parasitic load or station load.” The program materials do not include any other language limiting the size of the battery.

Industry rumblings had suggested that numerous developers had identified that the program materials would allow for very large batteries to be sited behind small existing loads, and still be paid the full ConnectedSolutions incentive. This strategy, while limiting demand charge management potential given the relatively small load, would allow a larger battery to take advantage of economies of scale without needing to identify a customer with a large load and without compromising ConnectedSolutions, Clean Peak Standard, or most wholesale market revenues.

In the December 5 presentation, the PAs stated that they had received ConnectedSolutions applications “for battery projects in excess of 100x site peak load.” There are a number of reasons that the PAs may have objected to this trend, including providing an incentive for potentially more challenging interconnections, not maximizing reductions to onsite load, and creating challenges to the PAs’ ConnectedSolutions budget. In response, the PAs stated their intent to cap ConnectedSolutions performance to 150% of the site’s annual peak load, less the nameplate capacity of the battery. This would, in theory, allow large batteries to be installed and pursue CPS and other revenues, but ConnnectedSolutions compensation would be limited based on the customer’s peak demand.

Available interconnection data doesn’t provide enough information to identify how many projects that are already in the interconnection queue may be affected by this change (for some distribution companies, standalone storage cannot be distinguished from SMART storage projects and there’s no information on the magnitude of onsite load). That said, as of the writing of this post, more than 60 projects with a nameplate capacity of greater than 2 MW were included in the interconnection queue data, which may provide a rough sense of scale.

Industry Response

In its December 20 letter, the industry group acknowledged that projects sized at or “anything close” to 100 times a customer’s load may not be “necessary or appropriate.” Still, they argued that the proposed 150% cap would challenge project economics and limit the ability of customers to use their batteries to enhance resilience. The group suggested that the PAs adopt a kW cap equal to customer average load multiplied by 18 hours divided by battery duration. They argued that this formulation would allow customers to install and receive ConnectedSolutions incentives for batteries that provide approximately 18 hours of backup power. Alternatively, the industry group argued that the PAs could adopt a cap based on 8 times the customer’s gross peak load (that is, excluding reductions in peak load attributable to BTM distributed energy resources).  Further, the group argued that the cap should only apply to projects that have not submitted an interconnection application by May 31, 2023.

Energy Storage Performance Baseline

Currently, ConnectedSolutions performance payments are based on metered battery discharge during event hours, without the application of a baseline.  By “baseline,” we mean a comparison of activity during the Connected Solutions event hours to the same hours in similar, preceding days, which allows the PAs to estimate the load reduction attributable to ConnectedSolutions. For context, load curtailment resources in ConnectedSolutions do have a baseline applied to calculate their performance. When the PAs originally rolled out plans to add storage resources to ConnectedSolutions, they initially planned to use a baseline, but backtracked in the face of considerable pushback.

The October 26, 2022 Active Demand Reduction Initiative evaluation resurfaced this issue. The evaluation stated that “based on a survey of battery participants, it was concluded that [ConnectedSolutions] is not the sole motivator for the purchase and operation of the battery.” Based on this, the evaluation recommends that a baseline be applied to storage projects, so that participants would only “get credit for the marginal discharge above typical operation.” The evaluation includes additional recommendations about the specific implementation of the baseline, including how to design it to preclude “gaming” by charging the battery during peak hours of non-event days.

Industry Response

The industry group was similarly concerned about the possibility of a baseline, arguing that it would “almost certainly dampen, if not completely extinguish, interest in installing [presumably BTM] batteries.” The group’s letter called out that Connecticut’s Energy Storage Solutions program does not include a baseline. Citing impacts on the market, the group argued that, should the PAs introduce a baseline, they must first review the program in its entirety, apparently suggesting that the incentive design would need to be revisited if a baseline were to be applied. Finally, mirroring their arguments on sizing restrictions, the group argued that, if the PAs do decide to implement a baseline, it again should only apply to projects that have not submitted an interconnection application by May 31, 2023.

Impact on Connected Solutions and/or Clean Peak Standard revenue

A review of ConnectedSolutions event data shows a nearly perfect overlap between Clean Peak Standard (CPS) hours and ConnectedSolutions events. Given the similar objectives of the two programs, this makes sense.  The image below shows a representative set of days from the summer of 2021, illustrating program overlap.

If a baseline is implemented as recommended, this significant overlap means that ConnectedSolutions revenue would be significantly degraded if a project is dispatched during every CPS window. We will analyze and share in future Clean Peak Market Outlook (CPMO) briefings on how a ConnectedSolutions baseline would impact battery dispatch and revenue.


While the specifics have not yet been finalized, it’s safe to say significant changes are ahead for projects hoping to benefit (or maybe already benefiting from) ConnectedSolutions revenue. We will continue to follow updates and incorporate the latest into modeling conducted for our CPMO service. This will include showing impacts to individual resources, as well as modeling impacts to the CPS market as a whole.

A version of this blog post with additional analysis is available to CPMO subscribers. As noted above, we’ll also share our modeling results exploring the impacts of proposed changes in our next briefing, which will be held in late March 2023. To sign up for CPMO or for support evaluating likely changes and how to model impacts to your projects, please contact Stephan Wollenburg or Vinayak Walimbe.

DOER issues simplified draft Distribution Circuit Multiplier Guideline

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More than a year after DOER released its initial Distribution Circuit Multiplier (DCM) proposed structure and held a series of stakeholder sessions, and more than 8 months after it received comments on a subsequent straw proposal, DOER has issued a draft DCM Guideline, accompanied by a proposed set of eligible circuits. The deadline for submitting comments on the draft Guideline is Friday, November 18, 2022 by 5pm. Written comments should be submitted to [email protected] with “DCM Guideline Comments” in the subject line.

In contrast to the complexity of the Clean Peak Energy Standard (CPS) as a whole, the draft Guideline represents a substantial simplification in design relative to previous proposals issued by DOER. Some key changes relative to previous guidance include:

  • Resource eligibility. The draft Guideline does not include any eligibility limitations for participating resources, other than being a CPS-eligible resource. Previous guidelines had considered different eligible technologies depending on whether a circuit was load- or DG (Distributed Generation)-constrained.
  • Circuit eligibility. Criteria for determining eligible circuits is remarkably simplified. Circuits are evaluated based on a three-year average of their Peak to Normal Percent rating (peak demand divided by rated capacity). In descending order, eligible circuits for a given electric distribution company (EDC) start with the first circuit with a three-year Peak to Normal Percentage of 85% and include the following set of circuits that comprise 10% of the EDC’s total circuits. Resources that trigger a capacity upgrade on a circuit would be ineligible for the DCM, and the total capacity eligible for the DCM per circuit would be 1 MW (DC vs. AC not specified, though we assume AC). This change may exclude projects that might have hoped or planned to secure the DCM. Previous DOER proposals had contemplated criteria including number of customers served, circuit capacity, environmental justice criteria, and trends in Peak to Normal Percent ratings. Furthermore, DOER had considered including some circuits based on Peak to Normal Percent ratings (demand-based) and others based on connected PV MW relative to a circuit’s rating (solar-saturated).
  • Multiplier.  The draft Guideline sets the DCM multiplier to 2X for the 10 years following a unit’s effective date, and 1.5X for years 11 through 15. Previous proposals had contemplated various multipliers, with effective periods from 8 years to the resource’s full life.
  • Securing the DCM. The draft Guideline allows resources to apply and reserve capacity on a circuit before submitting a CPS Statement of Qualifications Application (SQA). These resources would have up to one year following their DCM application to file their SQA. DOER would maintain a waiting list should some resources fail to meet the one-year deadline. If a circuit that had been eligible for the DCM becomes ineligible, DOER would honor the DCM for resources that had already reserved capacity on that circuit, although no waitlist reservations would be honored. DOER had explored various approaches to reserving DCM capacity in previous discussions.

Taken together, DOER’s draft DCM Guideline could be construed as effectively a pilot. Our take is that while a more nuanced DCM design may have made it somewhat more effective in achieving its policy goal (to defer or avoid T&D upgrades), finalizing and implementing such a design would likely have significantly delayed the implementation of the DCM. Introducing a streamlined DCM approach will yield a (modest) increase in overall CPEC supply relative to a market without access to the DCM (whether by increasing CPEC production by incentivizing more directed development activities or by increasing the output from resources that are already operating or would have been developed anyway) in a market that has been consistently undersupplied since its inception.

The issuance of the draft DCM Guideline provides an opportunity for CPS market participants, current and future. For those already operating or developing dispatchable resources on eligible circuits, the 2X DCM multiplier could influence how their resource is operated.  For others still making decisions about where to develop certain types of projects, the DCM could lead to focusing development activities in specified areas.

Additional analysis is available to CPMO subscribers in the subscriber-only blog post and in the upcoming briefings on November 10th and 15th.  These briefings will also incorporate updated assumptions based on the passage of the Inflation Reduction Act and the Massachusetts Energy Omnibus Bill (H. 5060), all of which have critical implications for CPS market participants. To sign up, please contact Stephan Wollenburg or Vinayak Walimbe.

MA Energy and Climate Bills Shake things up for Clean Peak Standard Market

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The last few weeks have been exciting for those working in the clean energy space!  On August 11, Massachusetts Governor Baker Signed HB 5060, An Act driving clean energy and offshore wind into law, following some speculation that he might not sign it over the inclusion of provisions he had requested be excluded from the bill.  On August 16, President Biden signed H.R.5376 – the Inflation Reduction Act of 2022 into law, enacting climate provisions whose prospects seemed to have dimmed prior to announcements of a deal reached between Senators Manchin and Schumer.  Both statutes have important ramifications for the Massachusetts Clean Peak Energy Standard (CPS) market, some direct, some indirect, which will lead to updates to the Clean Peak Market Outlook (CPMO) team’s modeling of the CPS market.  In this post, we focus on the Massachusetts energy omnibus bill.

Storage-specific provisions

Section 72: Storage tariffs

The omnibus bill directs each of the EDCs to file with the DPU a notice of intent to “promptly” file with FERC a wholesale distribution service rate schedule to apply to distribution-connected standalone energy storage participating in wholesale markets.  This requirement reflects a lack of clarity both in Massachusetts and across New England in the rate treatment of these types of resources.  Anecdotally, many EDCs, including those in MA, have been applying general commercial retail tariffs to these systems, which include prohibitively high non-coincident demand charges that effectively kill the economics of many storage projects. 

The legislation further directs the EDCs, in developing these wholesale distribution tariffs, to “identify the costs to the distribution network not recouped through project sponsor-funded interconnection upgrades or otherwise paid directly by the project sponsor and design rates to recoup the distribution company’s net costs in a manner similar to how they are incurred by the distribution company, without unduly impeding the participation of energy storage systems in power markets and other uses of such systems that provide benefits to the grid.”

There is, to say the least, a lot to unpack in this sentence.  An oft-cited, FERC-approved wholesale distribution charge precedent applied to similar storage resources in Commonwealth Edison territory applies a carrying charge to system upgrade costs directly attributable to the interconnecting storage resources, an approach that yields a fixed, annual charge specific to each interconnecting resource.  The statutory language, by specifying that the tariff should consider “costs to the distribution network not recouped through project sponsor-funded interconnection upgrades,” appears to allow for a design different from the Commonwealth Edison tariff, which might include kWh- and kW-denominated charges.  Still, the final clause requires that the tariff not “unduly imped[e] the participation of energy storage systems in power markets,” which storage stakeholders may cite in opposing demand charges.  It’s not clear that the Massachusetts legislature has the authority to dictate the specifics of FERC-jurisdictional tariffs, so some of these specifics may end up being rendered moot.  Regardless, Section 72 prompts action that should resolve a lack of clarity that has challenged distribution-connected standalone storage resources in MA.  Given that these resources, unlike their larger, transmission-connected brethren, will be eligible for EDC solicitations of CPECs, this greater clarity (especially if accompanied by favorable rate treatment) could stimulate more of this resource type being deployed.

Section 72 also directs the EDCs to file at least one tariff “which addresses operational parameters, to apply to energy storage systems interconnected to [the EDC’s] distribution network.”  This would appear to apply to resources not participating in wholesale markets, that would be subject to the DPU’s authority.  Specific direction for how the tariffs should be developed, cited above, would appear to apply to these state-jurisdictional tariffs as well.  While the state-jurisdictional storage tariff could yield more favorable rate treatment, we anticipate that the impact of the state-jurisdictional tariff will be small relative to the FERC-jurisdictional tariff.

Section 80: Storage study

Section 80 directs DOER, in consultation with the Massachusetts Clean Energy Center, to conduct a study of storage, and submit a report and recommendations to the legislature by the end of 2023, considering, among other things:

  • The potential to require the EDCs to procure up to 4,800 GWh of storage
  • The current uses (location, usage patterns, etc.) of storage
  • Various means to further promote the deployment of storage, including tax incentives and funding from alternative compliance payments and energy efficiency programs
  • The benefits of storage, including contributions to meeting climate goals, integration of renewables including offshore wind, resiliency benefits, ratepayer benefits

DOER must also make recommendations for mid- and long- duration storage (defined as having 4 to 10 and greater than 10 hour durations, respectively) deployment targets.  Subject to several requirements, Section 80 also directs DOER to “require solicitations and procurements in accordance with the study recommendations” and grants DOER the authority to “promulgate regulations to implement this section consistent with the study recommendations,” including establishing an EDC procurement methodology.  The statutory language does not directly address how these provisions might interact with CPS.  Legislation resulting from recommendations from the storage study could be designed to leverage CPS, or make storage supported through new mechanisms ineligible for CPS.  Under existing regulations, however, energy storage solicited through this new authority granted to DOER would not be subjected to the 1% contracted multiplier.  The result is that the section, in addition to requiring an energy storage study which might lead to future legislation, also provides DOER with the authority to initiate storage solicitations.  We do note, however, that while there are deadlines for completing the study and delivering recommendations, there are no deadlines for DOER to initiate EDC storage solicitations.  Still, the new authority granted to DOER to conduct storage solicitations could become a significant driver of CPS supply in the future.

CPS-specific provisions: Anaerobic digestor procurement

While the bill is largely silent on CPS itself, Section 39 includes a rather odd new requirement for the Department of Energy Resources (DOER) to conduct a one-time procurement of “Class 1 renewable energy certificates” from existing anaerobic digestion facilities through the CPS, with a “floor price sufficient to stimulate the development of anaerobic digestion facilities.”  We note that this section likely includes a few drafting errors (e.g., referring to Class 1 RECs instead of Clean Peak Energy Certificates) which may need to be rectified in future legislation.  While the volume of procured CPECs may not, in and of itself, materially alter the market in the long-term, by including a deadline of January 1, 2023, the provision could lead to action on the electric distribution company (EDC) solicitation of CPECs through long-term tariffs, which have still not been filed with the Department of Public Utilities (DPU).  The required focus on solicitations could even lead to reconsideration of the solicitation methodology proposed in DOER’s final straw proposal. That said, because the anaerobic digestion and long-term tariff solicitations obligations fall on different parties (DOER and the EDCs, respectively), there may not be any direct impacts from one on the other. The CPMO team will continue discussions with relevant stakeholders to probe for potential impacts of this strange provision on CPEC solicitations.

Other provisions with CPS implications

While most sections of the bill have the potential for at least tangential impacts on the CPS market, the following sections are particularly notable.

Section 62: Offshore wind solicitations

Modifications to the Commonwealth’s offshore wind policies were one of the primary drivers of the omnibus bill.  While not the most salient changes, the law directs DOER to prioritize bids that include benefits from paired energy storage and firm energy delivery.  This language increases the likelihood that future OSW procurements may be altered to reduce or remove current disincentive for offshore wind bidders to include storage (since they would receive little or no benefit from incurring the incremental cost), and thus increase the likelihood that future offshore wind bids will include storage (potentially remote or co-located, pending specifics included in regulation).  While current CPS regulations apply a 1% multiplier to resources that have a Section 83 contract (including offshore wind solicitations), it’s possible that future OSW solicitations may enable bids that could be structured such that CPECs produced by paired energy storage would not be subject to this multiplier.  Importantly, Section 72 transferred the responsibility for running offshore wind solicitations from the EDCs to DOER. Given DOER’s interest in achieving a CPS market in greater supply/demand balance, it is plausible that DOER could enable bids that allowed for storage paired with offshore wind to avoid the 1% multiplier.

Section 60: Grid modernization

Section 60 directs the EDCs to develop grid modernization plans, emphasizing reliability and resiliency, enabling the achievement of climate goals (by integrating more renewables and accommodating building and transportation electrification), and mitigating ratepayer impacts.  While there is some overlap between the requirements of this section and grid modernization plans that the EDCs first filed in 2018, Section 60 emphasizes storage as a means to “decarbonize the environment and economy” and to “improve renewable energy utilization and avoid curtailment.”  Impacts from this provision on the CPS market are not likely to be realized in the next few years.  We anticipate that this provision could be cited by EDCs advocating for increased EDC ownership of storage resources.

Provisions related to electric vehicles

The bill includes a number of provisions encouraging the adoption of electric vehicles, including the establishment of the Electric Vehicle Adoption Incentive Trust Fund, expanding incentives to medium and heavy duty electric vehicles (EVs), and requiring the MBTA to purchase only zero-emission passenger buses after December 31, 2030.  We note that while, to date, EVs have not participated in CPS, their future participation represents a major wildcard for CPEC supply.  Rapid adoption and participation of EVs could lead to them generating a substantial portion of overall CPEC market supply in future years, especially if EVs are used to supply building loads or feed back into the grid.

Putting it all together

In sum, the MA energy omnibus bill is a sprawling piece of legislation, with provisions with the direct and indirect, near-term, and long-term implications for the CPS market.  The CPMO team will include updates to our modeling in our 2022 #3 briefings, scheduled for late October or early November of this year, to help you understand the various components of this new law will translate into CPEC supply, demand, and pricing.

If you’re interested in learning more about the Massachusetts CPS market, including benefitting from detailed supply/demand and pricing projections that incorporate all of the latest developments, including the MA energy omnibus bill, you can see our sample content and learn more about subscription options.  We’d also love to hear from you!  You can reach out to us here.

CPS: A New(ish) Market Means Unique Opportunities

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While it still feels like a new policy, the Massachusetts Clean Peak Energy Standard (CPS) dates back to 2018 enabling legislation.  Following an extensive regulation development and stakeholder process, the Department of Energy Resources (DOER) filed Final Regulations in July 2020, leading to obligations that applied to compliance year 2020. 

Still, in some ways, the market seems new to many participants.  Even after the promulgation of the Final Regulations, DOER has worked with stakeholders to clarify and introduce additional elements of CPS, issuing and updating various CPS guidelines governing resource participation, multipliers, and applicability of CPS to retail sales, drafting and releasing a Final Straw Proposal for long-term procurement of Clean Peak Energy Certificates (CPECs) by the electric distribution companies (EDCs), and working with stakeholders as DOER developed the design of the Distribution Circuit Multiplier, among other things.  Some entities seeking to qualify resources have had to work through critical details with DOER, such as exactly how CPEC volumes will be calculated for demand response resources.  More generally, many market actors on both the supply and demand side have struggled to internalize and master the nuanced and complex policy that is CPS.

Certain critical components of the policy have yet to be implemented.  DOER’s Final Straw Proposal for long-term CPEC procurements anticipated that the EDCs would file the relevant tariff with the Department of Public Utilities (DPU) in 2021.  As of the date of this post, this has not occurred.  Furthermore, recent experience shows that the DPU has struggled with its caseload, delaying action on dockets that don’t have legislatively-mandated timeframes. This creates uncertainty when the first procurement might be issued, potentially delaying the development of resources that will rely on CPEC price certainty in order to be deployed.  The Distribution Circuit Multiplier, which could play a critical role for some resources, has also not yet been implemented. 

CPEC Supply – Opportunities Not Yet Realized

The qualification of supply also reflects a market that is slow to ramp up, even among eligible resources that are already operating.  For example, the 12/3/2021 SMART Solar Tariff Generation Units report indicates a total of approximately 145 MW of storage capacity that has reached commercial operation and has an Approved or Qualified status.  However, only 32.7 MW of storage was included in the 1/8/2022 update to the CPS Qualified Resource report, which could include some storage that is not SMART storage.  The same report shows a total of 90 MW of qualified CPS resources. 

Source: DOER CPS Qualified Units Report.  Data as of January 8, 2022 update.

For resources that have not yet qualified, this represents a real opportunity.  A 1.6 MW, 4-hour SMART energy storage system could expect to produce approximately 1,300 CPECs per year.  At the current ACP of $45, this represents lost revenue of almost $60,000 per year.  Based on the numbers cited above, many market actors are not capturing these revenues. 

Uncertainty = Potential for Competitive Edge

While some might consider the current (im)maturity of the market and the speed with which it’s developing reasons to delay serious study of it, the reality is that the CPS’s current status provides unique benefits to those with the insights provided by CPMO.  Understanding when the market is likely to mature and supply will catch up with demand, and how supply-demand dynamics might drive the dynamic targets, ACP and CPEC price, is particularly important for those on both the supply and demand sides of the market to understand. 

CPMO’s next briefing, anticipated in late February 2022, will explore these CPMO’s next briefing, anticipated in late February 2022, will explore these questions and how they translate into future price scenarios.  If you’re interested in gaining access to CPMO’s market intelligence to guide your decision-making during a critical phase of the CPS market, email us at [email protected], or call Stephan Wollenburg at 508-834-3050 or Vinayak Walimbe at 781-338-5505.