MA SREC II Update: The RECs Are Too Damn High

Its been awhile since we've provided an update on the rule making process in Massachusetts (MA) for the successor solar program to the Solar Carve Out (SREC I). The successor program under development is referred to as SREC II. Before we begin, a little background may be helpful. In early 2013, it became clear that the SREC I program was going to reach its program goal of 400 MW ahead of schedule. The MA Department of Energy Resources (DOER) began a public stakeholder process to create a successor program which is nearing its conclusion. There have been several proposals submitted for public comment and DOER issued draft regulations approximately six weeks ago. DOER will now take the input received from stakeholders in the most recent comment period and incorporate select comments into the final regulations. These final regulations will then be sent to the MA Joint Committee on Telecommunications, Utilities, and Energy for comment. The Joint Committee will then provide comments to DOER which will be incorporated into the final promulgated regulations that will take effect. DOER has made a webpage available where they have provided information on the process and regular updates.

Instead of ETE recapping the latest version of proposed regulations for the SREC II program, I'd recommend you read this summary on It captures most of the important points of the new program design and ETE will use this blog post to focus on the process used by DOER in this rule making and our expectations regarding likely outcomes. 

In order to inform the process for creating the SREC II program, DOER hired a consulting team (Sustainable Energy Advantage, Meister Consultants, La Capra, and Cadmus) to produce several reports. The purpose of these reports were to provide an informed basis for the SREC II policy design and also to justify the levels of incentives required for various types of solar installations. You can download these reports from this DOER webpage. Although ETE is going to present information from various intervenors that are critical of these reports, ETE's feeling is that they were well done with the exception of report 3b. The shortcomings in report 3b, entitled "Analysis of Economic Costs and Benefits of Solar Program", in ETE's opinion, are largely due to a pre-determined outcome requested by the client (DOER) and a scope that wasn't sufficient to perform a fully comprehensive benefit to cost ratio for MA ratepayers. Although its easy to blame the consultants, the process wasn't designed to deeply vet the costs of solar. More on this later.

Although utility, ratepayer, and environmental groups have been voicing concerns about the expected costs and issues with the SREC II program, they became quite vocal during the January 2014 public comment period (download the zip file 1/3 of the way down the page). A quick summary of each type of intervenor and the nature of their comments are listed below.

Environmental Groups - Groups such as the MA Audubon Society, various municipal conservation commissioners, and clean water groups are very worried about forests and wetlands being cleared for ground mounted solar arrays. The restrictions and discounting via SREC factors of ground mounted solar arrays largely stem from environmentalists who are upset (rightly so) that many large ground mounted arrays have been built on sensitive ecosystems over the last four years, often exploiting agricultural zoning to build structures that would otherwise be prohibited.

Solar Developers - Although their comments were wide ranging, an important theme focused on the restrictions on managed growth. In late spring 2013, large scale solar development in MA came to a screeching halt when the SREC I program became oversubscribed. By many estimates, there are nearly 100 MW of shovel ready solar developments waiting to move forward and most of these would fall into DOER's managed growth category (500 kW ground mounted). The regulations state, in 14.05(9)(m)(1) that the managed growth category will accept 26 MW in 2014 and 80 MW in 2015. Stakeholders are concerned, and rightly so, that this is not enough capacity to accommodate the existing development pipeline for larger systems and will unnecessarily put a brake on solar industry growth.

Retail Energy Suppliers - The Retail Energy Supply Association (RESA), TransCanada, and ConEd Solutions all had critical comments. TransCanada provided a strongly worded, yet well-reasoned, take-down of DOER's 3b study regarding benefits of solar to ratepayers. ConEd Solutions argued that the SREC factors result in wasted RECs, arguing that a managed growth system receiving an SREC factor of 0.7 results in the wastage of the remaining 0.3 MWh that should be credited as a Class I REC. RESA focused on the uncertainty regarding future SREC forecasts, petitioned for more transparent forward looking SREC compliance forecasts, and highlighted the risk premiums borne by ratepayers as a result of the uncertainty regarding SREC purchase obligations for retail suppliers in future years. They also highlighted DOER's recent activities that have heightened uncertainty and risk premiums for retail suppliers in the marketplace, such as the June 2013 "emergency" regulations to deal with the over subscription of SREC I. They aren't the only ones berserk over DOER's perceived abuse of "emergency" regulation making.

Utilities - Northeast Utilities (NU) and National Grid both weighed in with several comments on the proposed SREC II framework. National Grid has been vocal in airing its concerns regarding the costs of the program and used the December 2013 Raab Roundtable to propose an alternative approach where the utility would have a tariff based solicitation that would ensure stable and predictable revenues to a solar installation for a period of ~ 15 years and align the payment rates with the revenues required to secure financing. National Grid has been using this model with success in Rhode Island and has been able to procure solar at much lower costs than those envisioned in the SREC II program. NU goes further than National Grid and states that the SREC II program is not a market for RECs, but instead a contrived construct that will keep SREC costs artificially high. They shred DOER's 3b report regarding the cost benefits of solar. Specifically, NU states that the estimated avoided transmission cost benefits from solar development are inaccurate because they are lifted out of a study regarding avoided transmission and distribution costs associated with energy efficiency (EE), which is inappropriate for solar since EE resources tend to be coincident with system peak loads and solar is less so. NU also correctly notes that many systems installed in places without onsite load (e.g., ground mount) result in increased transmission and distribution costs associated with interconnection. NU explained that their experience in Connecticut with the LREC/ZREC program illustrates that a long term REC contracting regime lowers the cost to acquire solar resources relative to the proposed SREC II framework. 

Our thoughts - It appears likely that the regulations will be implemented in something very close to their current form. There are a number of key takeaways regarding the future of solar in MA.

  • There will be a knockdown drag out fight over net metering later this year as the statutory net metering caps for each utility will be reached soon. The National Grid presentation at the Raab Roundtable in Dec. 2013 hints at this, but the utilities are adamant that distribution generation be sized according to the on-site load. In addition, any expansion of Virtual Net Metering credits for ground mount systems will be less generous that the current regime. Expect some very solar friendly legislation that expands the net metering caps in the MA Legislature that quickly becomes contentious.
  • SREC II will be limited in its ability to build out new MWs of PV if the net metering issue isn't resolved quickly
  • The Solar Clearinghouse Auction is a price support mechanism, NOT a floor price, how in the world don't people understand this???
  • The SREC Factor approach discards a portion of the REC that would otherwise qualify as a Class I REC. The dual minting approach was included in prior iterations of DOER's SREC II proposal and our guess is that it was discarded due to complexities in implementation in the NEPOOL GIS attributes tracking system used to mint and retire RECs.
  • The current MA approach to solar is very customer friendly in that anyone can go solar. Your average customer can look in the Yellow Pages for solar installers, get multiple quotes, and then move forward based on their own purchasing process and timeline. In the auction procurement methods proposed by National Grid and NU, the customer needs to partner with a developer in order to submit a bid to the utility. In the MA model, the customer is in the driver's seat whereas in the auction model the customer is captive to the solar developer unless they are highly sophisticated. 
  • New Jersey and Maryland are both seeing new solar PV builds with SREC prices below $200/MWh. What are they doing differently and why shouldn't MA copy them?
  • The MA DOER has a lever to reduce costs three years into the program in that they can reduce the SREC factors per section 14.05(9)(l)(4) of the proposed regulations. 

What will this cost you?

2015 Forecast RPS Costs.png

The SREC II will look very similar to SREC I in that it is a carve-out of the Class I Renewable Portfolio Standard (RPS). By 2015, SREC I compliance costs will have stabilized and SREC II compliance costs will be starting to creep into the supply portion of your electricity bill. Section 14.07(3)(d) states that the 2015 SREC II compliance obligation for electricity suppliers will be 161,958 SRECs which translates to 8/10 of a mil per kWh in extra supply charges. This isn't a big deal for the average residential ratepayer, but if you are a hospital, data center, or large industrial this will be a noticeable cost. In the table to the right, we've broken down the expected cost impact of the MA RPS in 2015 when SREC II will begin to show up in consumer supply charges. Although SREC II doesn't seem all that bad, it will continue to grow and the overall RPS charges will be near a penny per kWh by 2015.

In recent weeks, there have been several articles in the MA press that have been critical of the costs associated with expansion of solar. Commonwealth Magazine ran a story regarding how certain prominent politicians are ducking the issue and even the Globe ran an article that aired the cost concerns of many stakeholders. So far, the debate hasn't devolved into an emotional screaming match........yet.

In summary, we like the decentralized approach to solar taken by MA as opposed to the more centralized programs in RI, CT, and NY, but the costs of SREC II seem higher than warranted. New Jersey is a similar state in many respects (at least from a cost perspective) and they are building out solar at a steady rate at lower costs. Most of DOER's market design is thoughtful, but we think they need to exert more cost pressure on the industry. As we've stated in the past, renewable energy costs money and MA's decision to transition to a more renewable generation mix is a policy choice, endorsed by MA voters, and embraced by politicians that has associated costs and benefits. The benefits are cleaner air, the costs are buried in your electric bill. The only way to dodge these costs is to go solar yourself and get on the receiving end of these programs. 

Net Metering in Massachusetts

At Energy Tariff Experts, we've found that Net Metering (NM) and Virtual Net Metering (VNM) are a source of confusion for end use customers and energy professionals. The rules can be confusing and the variety among calculation methodologies for different utilities and rates can be hard to keep track of. In this blog post, we are going to walk through NM for larger customers in the Massachusetts (MA) National Grid service territory.

First, a little background. NM is not new. Its been around since 1978 when the Public Utility Regulatory Policy Act (PURPA) required utilities to allow customers to install self generation equipment and obligated the utility to purchase excess power. Most PURPA projects consisted of cogeneration and many were net metered. Over the last several years, NM has become a big deal due to its importance to the solar industry. The vast majority of new NM has been driven by solar and in some utilities, the tariffs are still trying to catch up with industry developments.

The current solar NM regime in MA has its genesis in the Green Communities Act of 2008. This act mandated that Investor Owned Utilities (IOUs) (e.g., NStar, NGrid, WMECO, and Unitil) credit customers for NM solar output at the retail $/kWh rate instead of the wholesale rate (set by ISO-NE). It created separate credit calculations for private and public sector customers as well as caps on the amount of capacity eligible for NM. These caps filled up pretty quickly and in August 2012, MA Senate Bill 2395 (note the ironic title) was passed which raised the caps to 3% of each IOU's peak load for both public and private sector owned systems. You can view the amount of capacity remaining under each NM cap at the MA System of Assurance website. NM is critical for the economics of many solar installations and the fact that the NM capacity caps will be fully subscribed in 2014 will be an issue. The future of NM in MA has been a back burner issue over the last few months while the details of the SREC II program have been in development.

One item that many have trouble gasping is the difference between NM credits and VNM credits. The graphic below helps to illustrate the difference between the two. VNM credits represent the financial value of each kWh that is pushed back onto the grid and these credits, in dollars, can be transferred to other accounts. 

For an end use customer, the avoided cost of electricity via displacement of electricity from the grid with electricity generated from solar panels is worth more than the value of NM or VNM credits. For the end user who wants to keep it simple, it often makes sense to size a solar array based on the captive load onsite as the value proposition associated with avoided costs via displacement of electricity is more certain (presuming load is constant). The table below illustrates the billing line items for the G-3 and G-1 rates that are part of the NM and VMN credit calculation. Remember, if there is excess generation in a billing cycle, these credits can be applied to future billings or transferred to other accounts. The avoided costs are simply the summation of all kWh charges and represent the $/kWh value of a kWh generated from a solar array that displaced a kWh from the grid.

The tricky thing with NM or VNM credits is that their value changes on a monthly basis. The Basic Service Charge represents the cost of supply and it varies based on conditions in the ISO-NE wholesale power market. Check out this previous post on the variability of default supply rates for various utilities. As a result, there is inherent uncertainty in the future value of NM and VNM credits in the same way that future power costs are uncertain. 

The graphic below shows a MA NGrid G-3 invoice for customers without and with NM. Note that the non-kWh line items are still present. When on-site generation exceeds on-site load, the resulting surplus is credited to the invoice in dollars as shown below.

VNM is where things can really get tricky. The Host customer will designate one or more accounts to receive the financial value of all of the kWhs exported to the grid. In MA, the accounts designated to receive VNM credits are listed on a Schedule Z form. The graphic below illustrates the process.

Schedule Z designation.png

Currently, VNM credits are allocated to the recipient accounts manually each billing cycle. All of the MA IOUs voiced this as a major issue in MA DPU Docket 11-11. Any manual process is likely to have more errors than bills that are generated through an automated billing system. In addition, due to the fact that billing cycle dates for Host and recipient accounts will likely be mismatched, its possible to have a lag of up to two invoices before VMN credits appear on the recipient account's invoice. The graphic below shows where end users can find their VNM credit amount on their bills.

VNM Transfer Process.png

At Energy Tariff Experts, we audit NM and VNM invoices to ensure proper allocation and credits. We also work as an owners agent to evaluate the financial opportunity associated with proposed solar systems. In MA, an opaque secondary market for VNM credits has developed and we have advised several potential purchasers of the marketplace and transaction structures and contract language.

If you are struggling to understand any aspect of NM or VNM in MA or anywhere else, give us a call. We can do small engagements focused on customer education for a few hundred dollars or devise a bespoke Scope of Work to meet your needs.  

Solar Net Metering and Deregulated Electricity Contracts

As many of you know, Massachusetts has a very aggressive Net Metering policy to help spur the development of renewable energy. This policy has been so successful (or overly generous) that the 3% cap for private systems, based on historical peak IOU system load, will be reached sometime in 2013 for NStar, NGrid, and WMECO. For most private sector customers, the economics of solar in MA are currently strong. Between the 30% ITC, 50% bonus depreciation, MA income tax deduction, SRECs, and virtual net metering, there is a lot of support behind solar.

Unfortunately, many large customers get an unwelcome surprise when their solar facility goes live. They find that it blows up their third party deregulated electricity supply contract. The reason for this is due to the way that net metering works at the retail level. Large interval metered customers that qualify for solar net metering are given a two channel meter that records facility consumption and solar production simultaneously which is then netted to determine the customer's billed usage. The hourly consumption is reported to ISO-NE and that is what an energy supplier must deliver to ISO-NE to serve the customer's load. The third party energy supplier can't "see" any solar production that is exported to the grid because it is handled at the retail level between the customer and the utility. Therefore, the electricity supplier can't credit the customer for output "pushed back" onto the grid because they only get data from the ISO for intervals where net consumption is positive and that is what they must generate their bills upon.

During MA DPU Docket 11-11, TransCanada presciently raised this issue in Sept. 2011, but it seems that it wasn't a problem that could be resolved within the framework of the Docket. This issue does not represent a barrier to solar adoption for large interval metered customers, but it is an often overlooked constraint during the solar system design and scoping process. Interval metered customers need to decide whether to go big with their solar system and commit themselves to the utility's default basic service commodity price or size their system such that intervals of export to the grid are few and far between. Chances are the person trying to sell you a solar system has no idea how this works. The graph below provides a simplified description of the issue. 

Solar Net Metering Graphic1.png