Building a Regional Roadmap for Offshore Wind: Northeast States Receive DOE Award

Author: Valerie Stori, Clean Energy Group | Projects: Clean Energy States Alliance, Offshore Wind Accelerator Project

blogphoto-Wind-generators-turbinesThe US Department of Energy’s State Energy Program has awarded $592,683 in competitive funds to New York State Energy and Research Authority (NYSERDA), state organizations in three other Northeast states (the Maine Governor’s Office, the Massachusetts Department of Energy Resources, the Massachusetts Clean Energy Center, and the Rhode Island Office of Energy Resources), and the Clean Energy States Alliance (CESA) to advance offshore wind market development through multi-state cooperation.

The states will develop a regional roadmap detailing actions states can take individually and collaboratively to support offshore wind development at scale. Offshore wind (OSW) can help meet state GHG emission goals and renewable energy targets, while providing multiple other benefits such as grid reliability, peak demand generation, and reduced transmission costs.

NYSERDA is responsible for overall project administration, and the four states will have an equal role and stake in the project and its outcome. The award comes shortly after tides began turning for OSW in the US with the nation’s first offshore wind demonstration project (Deepwater Wind’s 30 MW project) installing US-made foundations off the coast of Rhode Island in July. The announcement also follows this summer’s release of New York’s State Energy Plan as well as New York City’s request for information on options for new renewable energy generation capacity. The state’s offshore wind resources could be used to meet the City’s goal for 100% renewable energy for government operations. Likewise, legislation has been proposed in Massachusetts requiring utilities to conduct periodic joint solicitations for OSW projects at scale. And at the federal level, Senators Tom Carper (D-DE) and Susan Collins (R-ME) have introduced the Incentivizing Offshore Wind Power Act, which, if passed, would provide an investment tax credit for the first 3000 MW of OSW.

Despite the tremendous potential of offshore wind, its high cost is a major barrier to development. Although no offshore wind farms have yet been completed in U.S. waters, the European experience has demonstrated that a market of sufficient scale and duration can reduce costs. Europe has installed over 8 GW and costs have decreased dramatically. A recent report by BVG Associates predicts that offshore wind projects in the UK will be cost competitive with new natural gas plants by 2020.

Although the individual states are already taking important steps to advance offshore wind, and will continue to do so, cooperation among them has the potential to speed progress and reduce costs. Through this DOE award for state energy planning through regional collaboration, the four Northeast states and CESA will examine how to bring OSW to scale in the Northeast, quantify cost improvements associated with a pipeline of projects, and identify opportunities for regional collaboration. The final project deliverable will be a regional roadmap detailing the near- and long-term regional market and the individual state actions and collaborative approaches needed to improve the OSW project pipeline beyond “one-off” projects.

The offshore wind project is one of 12 projects selected for funding through the DOE State Energy Program.


This blog post was also published in Renewable Energy World.

Distributed Resilient Storage for Utility Capacity Shaving: A Use Case

Author: Todd Olinsky-Paul, Clean Energy Group | Project: Resilient Power Project

blogphoto-GMP-RutlandEarlier this month, I had the pleasure of attending the commissioning of a solar+storage powered microgrid in Rutland, Vermont. The microgrid, which is owned and operated by the vertically integrated utility Green Mountain Power (GMP), includes 4 MW of battery storage (2 MW lithium ion + 2 MW advanced lead acid), 2.5 MW of solar PV, and 2 MW inverters.  It was partly funded through a state solicitation, which resulted in a joint federal/state award from VT Public Service Department and US DOE, Office of Electricity; and in addition to helping GMP integrate a whole lot of solar (Rutland, VT recently became the “solar capital of New England,” with more PV per capita than any other city in the region), the system will provide resilient power to a school designated as a community emergency shelter – important in an area that was devastated by Tropical Storm Irene, and where grid outages are all too frequent.

GMP intends to put the $12 million microgrid to its best use. They will test out a number of use cases, but at the top of the list, in terms of economic returns, is reducing the utility’s peak capacity payments to the New England ISO.

The concept is very similar to demand charge management. Essentially, GMP pays millions each year to the grid operator for its share of capacity costs (the money paid to peaker plants to make sure they are available during peak load periods). GMP’s share of this cost is calculated based on their demand during one annual peak hour. In addition, there are 12 monthly peaks on which GMP’s portion of a transmission charge is calculated. Currently, GMP’s annual obligation is $80-90 million/year, based on one annual capacity peak ($30 – $40 million/year) and 12 monthly transmission peaks ($50 – $60 million/year). However, both of these rates are rising, with the capacity rate set to triple by 2018. By that time, GMP calculates it will be paying $150 million annually to the ISO.

Obviously, anything the utility can do to reduce its demand during these 13 hours out of the year could save it, and its ratepayers, quite a lot of money. In fact, GMP has said it values the microgrid at about $1 million per megawatt per year, half of which will come from using the batteries for capacity peak shaving and frequency regulation alone (the other half is based on income from the solar portion of the microgrid, including RECs and the value of electricity generated). Given this valuation, GMP is looking at a payback period of 5-10 years, and likely closer to the low end of that range.

To put this into context, the 4 MW of batteries on-site cost about $5-$6 million, and should achieve payback in just a few years.

But this is only the beginning for GMP. The utility has partnered with Tesla, and plans to install an additional 1 MW of Tesla Powerwall batteries at customer sites, beginning this fall. GMP will offer customers two business models:

  1. Utility-owned option – utility owns and operates distributed behind-the-meter storage, customer pays a monthly fee for backup services
  2. Customer-owned option, with contractual utility control during demand peaks in exchange for a bill credit

In both cases the customer gets a resilient power benefit. If this is successful, GMP intends to quickly increase distributed storage capacity beyond the initial 1 MW level.

To summarize, GMP is piloting three business models for resilient energy storage in Rutland:

  1. Centralized utility-owned or merchant-owned storage (economic benefit to utility, little or no resiliency benefit)
  2. Distributed utility-owned storage, customers purchase resiliency services (economic benefits to utility, resiliency benefit to customer)
  3. Distributed customer-owned (or third-party owned) storage, utility purchases demand response services (economic benefits to utility and customer, resiliency benefit to customer)

In considering these three models, it seems that the third offers a number of advantages as a replicable model. It works in regulated or deregulated electricity markets; engages the greater resources of the utility or load-serving entity (LSE) in deploying distributed storage; benefits the LSE, the participating customer, and ratepayers at large (who end up paying for capacity); encourages the deployment of larger amounts of distributed storage, which can provide more resiliency, since from the LSE’s POV, there is no diminishing return for deploying larger systems; and rewards early adopters, since they will benefit the most. From the customer’s POV, this looks like a simple demand response program run by their utility.

GMP is not the only utility to see the value of customer-sited energy storage systems. Similar plans have been proposed by a number of utilities from SDG&E and Southern California Edison in California to the Glasgow Electric Plant Board in Kentucky to APS in Arizona. And a recent survey of electrical utilities by Black & Veatch found that over 74 percent of utilities are looking to incorporate distributed behind-the-meter resources, such as solar PV and storage, into their business model. These utilities see solar+storage as a key technology for operational demand response, and they identified renewables combined with battery storage as the demand response technology that will have the greatest impact on their business going forward.

What can states do to turn this economic model into a resiliency model?

  1. Create a list of eligible critical facilities (schools/shelters, firehouses, water/wastewater treatment plants, fueling stations, communications hubs, transportation hubs, etc.)
  2. Define resiliency in terms of duration of islanded critical load
  3. Work with utilities/LSEs and third-party solar+storage providers to create customer programs
  4. Create a state incentive (prescriptive rebate?) for distributed resilient power systems at eligible facilities. The function of the state incentive is to direct storage to critical facilities that serve public functions.

Ideally, utility investment + state incentive + energy cost savings should equal low/no upfront costs + fast payback + economic benefits to the customer.

Resiliency should be free.


This blog post was also published in Renewable Energy World.

Shedding Some Light on a Taxing Situation for Community-Shared Solar

Author: Nate Hausman, Clean Energy Group | Project: Clean Energy States Alliance

Boardman Hill Solar Farm under construction in December 2014. Reprinted with permission.

For renters and for property owners with inadequate roof space, the many benefits of solar electricity may seem out of reach. About half of all households and businesses in the U.S. are not viable candidates to host a PV system. Community-shared solar offers these electricity customers a way to take advantage of solar PV by buying an interest in an offsite shared solar array and receiving a credit on their electricity bills for their ownership interest.

The community shared solar market is growing rapidly, but its success depends on supportive regulatory frameworks and market systems. As community-shared solar has proliferated, a growing number of states have adopted community solar-enabling laws. This is clearly good news for solar, but one issue that has been less clear is whether an individual owner of solar panels installed in an offsite, community- shared array qualifies for one of the primary carrots offered to homeowners adopting solar—the 30% federal residential investment tax credit called the “residential ITC.” This uncertainty has created confusion in the marketplace.

The Clean Energy States Alliance (CESA), a national nonprofit coalition of public agencies and organizations working on clean energy issues, took this issue head on. Working with stakeholders in Massachusetts and Vermont and with the law firm Foley Hoag, CESA facilitated the submission of a Private Letter Ruling request to the Internal Revenue Service to clarify whether an owner of solar panels in a shared, offsite solar array is eligible for the residential ITC. The IRS recently released its Private Letter Ruling confirming the taxpayer’s eligibility for the residential ITC. While the ruling is only legally applicable to the individual taxpayer in question, the ruling will be taken as a positive development by community-shared solar participants and project developers.

The recent Private Letter Ruling represents the first instance in which the IRS has publicly weighed in on the applicability of the residential ITC to an owner of solar panels in a shared, offsite array. The ruling suggests that the IRS may be receptive to claims for the residential ITC when a project mirrors the structure of the project that was the subject of the Private Letter Ruling. It represents more good news for the burgeoning community-shared solar market.

The Private Letter Ruling and other documents of interest are available on CESA’s website at


CESA hosted a webinar discussion on the details and legal implications of this Private Letter Ruling on September 22, 2015. Foley Hoag attorneys Nicola Lemay and Adam Wade presented. Slides and a recording are available at:

This blog post was also published in Renewable Energy World.