Archive for April, 2017

Massachusetts SREC-II Update – April 2017

Posted April 21st, 2017 by SRECTrade.

In the last month we have two new and important pieces of information. On March 13, the Department of Energy Resources (DOER) updated the list of projects with a Statement of Qualification (SQA) and NEPOOL-GIS published the 2016 year-end SREC supply figures. Since our last update in SREC-II, the DOER announced that projects lacking an extension from DOER would lose their SQA. However, such projects are allowed to re-apply for an SQA with the understanding of the lower SREC factors. Please see the full presentation of data and analysis here.

Based on the latest information, we see the total installed & operational capacity in SREC-II is 812 MW, with an additional 1,076 MW qualified but not yet operational:

MA SREC-II qualified-capacity-over-time

With the year-end figures on SREC-II supply coming in at 556,510 we can better estimate the extent of over-supply for the year. Note that while the supply figures are out for the year, we won’t see the aggregate demand figures for a few weeks still. Using 2015 figures as a proxy, we estimate an oversupply of 282,802 MA16 SREC-IIs:

MA16 SREC-II srec-oversupply

With such a large surplus of SRECs, we’re certain to see a Solar Credit Clearinghouse Auction (SCCA) this summer. Recall that the DOER will accept SRECs until June 15 before initiating the Clearinghouse Auction towards the end of July. During that interval, the DOER will announce the 2018 Minimum Standard, which may increase if the SCCA does not clear by Round 2:


Source: DOER

RPS Evolving: States Take On U.S. Climate Goals

Posted April 19th, 2017 by SRECTrade.

This article by Allyson Browne was originally published in the American Bar Association’s Natural Resources & Environment Spring 2017 Issue: Science & The Law. It provides an in-depth look into how states across the U.S. are carrying the country’s torch towards Paris pledges with impactful RPS programs. In addition, the article breaks down the Clean Power Plan to illustrate how states could evaluate and implement similar obligations in harmony with existing RPS policies. These state actions will be increasingly important as the EPA endeavors to review the Clean Power Plan under President Trump’s recent Executive Order

As the Clean Power Plan (CPP) undergoes judicial review and faces a likely unsupportive Trump administration on the federal stage, states across the country are bringing their renewable portfolio standards (RPS) back to the top of their legislative agendas. Although the CPP is not the primary driver of today’s RPS reformation, its future will undoubtedly impact the future of RPS policies across the country, if not cause an RPS revolution—one way or the other. Historically, federal policies, including the federal production tax credit and the investment tax credit, have served primarily to support RPS programs and renewables deployment. Moreover, the Federal Energy Regulatory Commission’s (FERC) regulation of the wholesale electricity market has increased competition in the renewables sector by reducing barriers to project development and market participation, particularly with respect to requirements placed upon electricity suppliers and utility companies for renewables integration. Examples of such regulation are FERC Order 2003, Standardization of Generator Interconnection Agreements and Procedures (issued July 24, 2003), and FERC Order 764, Integration of Variable Energy Resources (issued June 22, 2012). As states look beyond their RPS target years and goals, the CPP has the ability to influence RPS program design much more heavily than did its federal predecessors. The CPP could prompt states to more closely align renewable energy goals with emissions reduction goals, thereby minimizing legislative and regulatory overlap and enabling states—and the nation as a whole—to recognize the maximum benefits of these broader climate change policies. But this is not to say that RPS programs will weaken if the CPP is struck down. Conceivably, the rejection of the CPP could lead to a great awakening of state leadership in our clean energy and climate future.

Renewables technology has progressed significantly since the first RPS was enacted in Iowa in 1983. Iowa Code § 476.41, et seq. And RPS programs, which require retail electricity suppliers to supply a minimum percentage or amount of their retail load with eligible sources of renewable energy, are constantly playing catch-up to these ever-evolving market dynamics. Technological innovations and the diversification of financial products have driven down project costs and broadened accessibility. States have provided incentives such as rebates or net metering credits. Project developers and service providers have adapted to meet the varied conditions of their markets. The result is a diverse portfolio of U.S. RPS policies, as states across the country have designed, implemented, revised, frozen, annulled, or otherwise modified their individual RPS programs as the renewables sector has matured over the course of the past 33 years.

Today, 29 states and the District of Columbia have compliance RPS programs. Altogether, the obligations apply to 55 percent of total U.S. retail electricity sales. See Galen L. Barbose, U.S. Renewables Portfolio Standards: 2016 Annual Status Report, Lawrence Berkeley National Laboratory No. 1005057 (April 2016). And these figures do not include states with voluntary renewable energy goals, such as North Dakota, Utah, and Virginia. See Jocelyn Durkay, State Renewable Portfolio Standards and Goals, Nat’l Conf. of State Legislatures (Dec. 28, 2016).

Although most RPS programs share common elements (such as imposing penalties for lack of compliance and utilizing some form of tradable renewable energy credit (REC) to track compliance), no two states share an identical RPS. States differentiate their RPS policies with unique targets and time frames, entities obligated and exemptions, eligibility rules and definitions, carve-outs, contracting or procurement requirements, and the use of cost caps and floors. Barbose, supra. This differentiation has empowered states to design programs that best fit their needs, market dynamics, and renewables goals. Modifications can be made when and where the barrier to entry is too high, or if the RPS imposes exorbitant costs on ratepayers. Consequently, the majority of states with RPS have hit their targets, with 94 percent achievement in 2013 and 95 percent achievement in 2014. Id.

While few new RPS policies have been enacted in recent years, states continue to modify existing policies in response to changing market conditions, program success and end-dates, and federal policies. As states begin to approach their target years or achieve (or exceed) target goals, states are evaluating whether and how to extend targets into the future. Under currently enacted laws, 20 states will reach the terminal year of their RPS by 2026. Id.

Recent legislative activity evidences this period of reformation. State legislatures have introduced and enacted more than 200 RPS-related bills since the beginning of 2015. See EQ Research, available at Most notable are the five jurisdictions (California, Oregon, New York, Vermont, and D.C.) that have adopted policies requiring at least 50 percent renewables, and Hawaii—the first U.S. state to establish a 100 percent RPS goal. Id. In addition to extending and expanding RPS time frames and goals, states have modified RPS programs by introducing resource-specific or distributed generation carve-outs, refining resource eligibility rules and definitions, and relaxing geographic preferences or restrictions. Barbose, supra.

As we approach common terminal years in 2020 and 2025, we are likely to see continued legislative and gubernatorial action on RPS programs and renewables goals. But approaching targets are not the only reason why states are revisiting and revising their RPS policies. Endogenous factors, including compliance costs, legal challenges, and other state- and local-level market and policy conditions are the primary internal drivers of RPS reevaluation. On the federal front, continued FERC regulation and the impending decision on CPP are making states rethink—and redesign—RPS policies to ensure continued compliance with federal law. Even before CPP leaves the bench, some states are planning ahead to ensure that their RPS programs will support their CPP-compliance programs. Pennsylvania, for instance, is already designing its CPP state plan, undeterred by the U.S. Supreme Court’s February 2016 decision granting a stay on the CPP pending the resolution of legal challenges. See Susan Phillips, Wolf says PA will move forward on Clean Power Plan, StateImpact Pennsylvania (Feb. 10, 2016); and Chamber of Commerce v. EPA, 136 S. Ct. 999 (2016) (order in pending case).

The CPP is the first-ever national standard aimed toward reducing carbon pollution from power plants, the nation’s largest source of emissions. See EPA, Fact Sheet: Overview of the Clean Power Plan (2015). Recognizing that fossil fuels will “continue to be a critical component of America’s energy future,” the EPA put forth the CPP to ensure that fossil fuel-fired power plants operate “more cleanly and efficiently, while expanding the capacity for zero- and low-emitting power sources.” Id. The CPP establishes interim and final carbon dioxide (CO2) emission performance rates for two subcategories of fossil-fuel-fired electric generating units (EGUs): fossil fuel-fired electric steam generating units (i.e., coal- and oil-fired power plants) and natural gas-fired combined cycle generating units. Id.

Under the CPP, states and utilities can implement the standards and meet these goals through one of three methods: a rate-based state goal measured in pounds per megawatt hour (MWh), a mass-based state goal measured in total short tons of CO2, or a mass-based state goal with a new source complement measured in total short tons of CO2, also known as a state measures plan. States need to develop and implement plans which, when combined with other state or regional initiatives, will ensure compliance with the CO2 emissions performance rates over the 2022–2029 compliance period, and with the final CO2 emissions performance rates, rate-based goals or mass-based goals by 2030 (or later, if the CPP is further delayed). The EPA estimates that the pollution reductions required by the CPP will yield climate benefits of $20 billion, health benefits of $14–34 billion, and net benefits of $26–45 billion. Id. Complementary or additive RPS programs will amplify these benefits by incentivizing additional renewable deployment, implementing stronger energy efficiency standards, and more.

Under any of the three methods, compliance will be tracked via emissions trading. See Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units, 80 Fed. Reg. 64,662 (Oct. 23, 2015) (to be codified at 40 C.F.R. Part 60). How an existing RPS and its tracking mechanism will interplay with a state’s CPP plan and its emissions trading will depend on the state’s CPP compliance path. Under a rate-based state goal, renewable energy facilities, energy efficiency units, new nuclear facilities, or performance upgrades at existing nuclear, hydro, and natural gas combined cycle power plants will produce emission rate credits (ERCs), which represent one MWh of zero-emission generation. These ERCs will be added to the denominator of the pounds per MWh until the EGU (either individually or on a state average basis) satisfies the required rate.

A state with an existing RPS that uses RECs to track compliance will need to decide whether and how ERCs and RECs will be issued, tracked, and retired together or separately. In its guidelines, the EPA clarifies that ERCs were intended to be unique and separate from RECs, and that a single generating unit could produce both an ERC and a REC for each MWh generated where eligibility overlap exists. But in practice, managing ERCs and RECs in the same compliance universe will be no easy undertaking—there will be issues with double-counting, existing forward contracts, and whether a facility can still claim its renewable attributes if it keeps its RECs, but trades away its ERCs. Id.

Emissions trading under a mass-based state goal is much more straightforward—states will be issued emissions allowances, which can be auctioned (traded) or given away. Compliance will be determined solely on total tons of CO2 emitted. As designed, there is no direct relationship between a state’s CPP plan and its RPS; rather, the two plans would exist contemporaneously. Id.

States with RPS, energy efficiency standards, and other related programs are best suited for a mass-based state measures plan. The state measures plan allows a state to leverage its existing policies, programs, and compliance mechanisms to meet the standards imposed by the CPP. And, rather than being the primary enforcement mechanism, the mass-based emissions standard acts as a federally enforceable backstop that only kicks in if the state measures fail to achieve the required reductions. There are no ERCs under this plan, and states can continue to utilize RECs to track RPS compliance, focusing CPP compliance efforts on bolstering their existing RPS and other programs instead of establishing entirely new programs and tracking tools. Id.

It is evident that the EPA carefully crafted the CPP to exist in harmony with state RPS programs and to provide a path for all states to reduce overall emissions while incentivizing renewable energy development—including those already on the right track. And although the CPP or similar federal policies would be instrumental in accelerating America’s timetable for achieving its Paris Agreement goals, states have proven willing to push for progress on their own. Now more than ever, it is imperative that states renew their commitments to renewable energy, promoting a sustainable renewables industry that supports continued job creation, grid resiliency efforts, and energy independence. As we enter into the era of Trump—and with it, an uncertain federal position on climate policy—states will take hold of the power to determine and define the nation’s stance for renewable energy and against the threat of climate change. Will we stand united?

Allyson Browne, Director of Regulatory Affairs & General Counsel

© 2017. Published in Natural Resources & Environment, Vol. 31, No. 4, Spring 2017, by the American Bar Association. Reproduced with permission. All rights reserved. This information or any portion thereof may not be copied or disseminated in any form or by any means or stored in an electronic database or retrieval system without the express written consent of the American Bar Association or the copyright holder.

Scaling up Solar Finance: Standards to Reduce Soft Costs

Posted April 18th, 2017 by SRECTrade.

On Thursday March 30th, SRECTrade participated in the annual SunSpec Alliance meeting, presenting as part of a panel on reducing soft costs in solar. The panel explored factors contributing to high costs and specifically how open data standards can reduce these costs across the solar value chain. SRECTrade has long been a proponent of open data standards as we focus on building products and services that increase the efficiency of portfolio management and provide access to the REC markets. To derive these and other benefits, standard adoption needs to be considered and applied in both a technology and service orientated approach.

Currently, the two technology factors with the largest potential positive influence on the market are providing open and equitable access to underlying registries and the development of software solutions that institutionalize portfolio management. Over the last 2 years, SRECTrade has campaigned to open up the underlying REC registries, resulting in the development of the first Application Programming Interface (API) for NEPOOL GIS and an improved API interface for PJM GATS. Open and equitable access to the underlying REC management platforms is fundamental to the continued growth and prosperity of renewable energy adoption. Failing to provide access has increased asset management costs as organizations build bloated teams to manage complex portfolios. Our analysis shows in 2017 the SREC market alone is estimated to exceed $2b in transactions, exposing many organizations to possible costly operational mistakes and strategic risk as it fails to capture institutional knowledge.

Despite the new APIs, adoption of open data standards at the registry level remains a challenge. Most of the national registries still do not have open APIs and even for those that do, are often limited and heavily restricted. The benefits derived from the open communication and exchange of data continues to challenge those that stand to gain most from the existing barriers to entry. Additionally, decision makers are often apathetic and resistant to change, particularly where bureaucracy and legacy software makes the process for change painful. The benefits however are clear. Monopolistic access to data increases costs to participants and stifles innovation that would otherwise lead to reduced costs in the market. Open and equitable access places the cost of innovation on the market and reduces the ability for a central authority to decide market winners. The advent of blockchain technology that promotes decentralized distributed communication has, and continues to, disrupted many industries where data managed by a central authority restricts access and transparency. It is both a sign that modern technology can replace centralized autocratic processes and that consumers are demanding greater access and control of their data.

To reduce portfolio management costs and mitigate operational risk, the ability for organizations to either buy or build software is critical. Unfortunately, to date, in both cases choice is limited or often completely lacking. The absence of APIs prevents organizations from building comprehensive tools and in many markets the ability to procure services. SRECTrade is seeking to solve these problems by lobbying for new public APIs and providing comprehensive portfolio management services through our new SRECTrade-X platform.

Coupled with these technology changes, standardization of business services will also contribute to reduced costs and a greater variety of financial services. Our efforts on this front are focused on unlocking liquidity in the market by establishing standardized processes for creating derivative products and the securitization of REC contracts. Last April, SolarCity announced that it closed the first SREC securitization round, unlocking $40m of residential and commercial solar funding, part of which was originated by SRECTrade. Ron Klein, VP, Capital Markets at SolarCity said at the time that it was “evidence of the maturity of the SREC market”. To unlock similar value for other organizations, SRECTrade has been working to create clear data and reporting structures, backed by our technology platforms, to establish a methodology for financiers to price risk appropriately and provide securitization as a turn key solution.

In summary, a lack of standards and access to underlying data fuels complexity and in turn, increases risk and ultimately the cost of doing business. To reduce soft costs and the burden to REC portfolio managers, the industry needs to continue to drive towards free and open data communication and exchange platforms. Achieving this will unlock innovation, investment and value across the market.

Maryland SREC Update – April 2017

Posted April 18th, 2017 by SRECTrade.

After the recent move lower in Maryland spot SREC prices, we decided to refresh our capacity models and market projections with the latest data available from PJM GATS.  You can find our updated presentation here.

The Maryland SREC market remains significantly oversupplied after a record breaking 2016.  Through the 2016 calendar year the Maryland solar market installed an average of 23MW/month for a grand total of 278MW over the course of the year.  Comparatively, in CY 2015 the monthly build rate was just under 14MW/month for a total of 164MW.  That 70% increase in installed capacity had a pronounced impact on market pricing for MD SRECs, with MD16 SRECs declining in value from $150 in late 2015 to $20 in late 2016.  In recent weeks, as the market continued  to digest the true scale of oversupply, the price for spot MD SRECs has declined to between $10 and $15.



                         Source: SRECTrade Market Insights


Turning our focus to calendar year 2017, the current market is still reflective of the significant supply of SRECs generated in previous years which is still eligible to be brought to market for 2017 compliance obligations.  The available supply of MD15 and MD16 SRECs is just shy of 400,000 SRECs, representing a full 56% of the 2017 SREC compliance obligation.  An additional 70,000 SRECs were issued through Q1 of 2017, and using the current trailing twelve month average (TTM) build rate in MD, we project that another 730,722 SRECs will be produced over the balance of the 2017 calendar year.


This adds up to a 2017 oversupply of roughly 490,700 SRECs, or 69% of the 2017 compliance obligation.  One important point to consider, however, is the sustainability of the current 17.5MW/month TTM build rate in the current SREC environment. We have seen a marked deceleration in the addition of new capacity as many projects – mostly those who would receive the wholesale rate of power as opposed to the retail rate – no longer pencil economically with $10 to $20 SRECs.  Given this reality, we chose to present our projections below with the current TTM representing the “bull case” for future build, while significantly lower monthly capacity additions of 8.8MW/month and 13.1MW/month make up the bear and base cases, respectively.



As we can see by looking out along the timeline, the expected slow down in build will result in the market eventually rebalancing itself, with supply beginning to match demand in 2020.  However, even in this “best case” scenario, the Maryland market will still be a difficult place for developers unable to source PPAs with robust power pricing to successfully build new solar assets. The persistent oversupply will continue to keep SREC pricing depressed through the short to medium term.  However, hope is not lost entirely. This trend could quickly be reversed by any sustained effort to support and pass an expanded RPS schedule with more aggressive percentage targets for solar’s share of the state energy mix.  Expect markets to quickly turn should a viable legislative plan be proposed and adopted over the coming months or years.

As always, we will continue to monitor the state of the Maryland SREC market and offer our opinions when we believe they will be useful.  Feel free to reach out to the SRECTrade brokerage team to request the data used to build our models or to inquire about our projections for the Maryland SREC market.  Additionally, feel free to consult the Markets section of our webpage for quick facts regarding the current RPS framework and specifics about the SREC program.


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