FERC solicits panel members to resolve hydropower licensing study disputes

U.S. hydropower regulators have asked for volunteers interested in serving as panel members to assist in resolving disputes related to the scope of studies required for hydropower licensing.

Under federal law, the Federal Energy Regulatory Commission is tasked with processing applications for licenses for most hydropower projects located in the U.S. To process any given application, the Commission typically uses one of three different licensing processes. Since 2005, the Commission's "Integrated Licensing Process" or ILP has been the default choice.

Under the ILP, the applicant seeking a license files a proposed study plan describing the studies it intends to conduct to inform the Commission's review of its application. Studies might cover the project's impact on a variety of types of resources and issues, such as aquatic, terrestrial, cultural, recreational, geological, land management, engineering and socioeconomic topics. After a 90-day period of consultation with stakeholders and Commission staff, the applicant may file a revised study plan for Commission approval. Ultimately, the director of the Commission's Office of Energy Projects will issue a study determination approving the study plan with any modifications based on the record. Whatever studies are required by the Commission-approved study plan must be conducted by the applicant or its consultants.

The nature and extent of the studies required can be controversial. Stakeholders have opportunities to comment on the applicant's original study plan, to participate in consultation, and to comment to the Commission on the revised study plan.

Under the ILP, certain federal or state agencies or tribes also have the ability to request that a study dispute be referred to a dispute resolution panel. The three-member panel would consist of FERC staff, the agency or tribal representative referring the dispute, and an independent third person selected by the other two panelists from a list of subject-matter experts. The panel members make a finding with respect to each disputed study request, on the extent to which each study criteria set forth in the regulations is or is not met, and why. The panel then makes a recommendation to the Director of the Office of Energy Projects based on its findings.

On October 22, 2018, the Commission issued a notice requesting applications from those interested in being listed as potential panel members. The Commission previously compiled lists in 2004, 2010, and 2015. For the latest round, the Commission has requested applications by January 31, 2019.

Dominion affiliate proposes Tazewell pumped storage project

A Virginia-based utility company has applied to federal regulators for a preliminary permit to study the feasibility of a pumped hydroelectric storage facility in the coalfield region of Southwest Virginia. If built, Dominion Energy Services, Inc.'s Tazewell Hybrid Energy Center Project could use mine water sources for the initial fill and makeup water. 

On September 6, 2017, Dominion Energy Services, Inc. filed an application to the Federal Energy Regulatory Commission for a preliminary permit, pursuant to section 4(f) of the Federal Power Act, proposing to study the feasibility of the Tazewell Hybrid Energy Center Project. As described in Dominion’s application, a September 7 press release, and a September 29 notice by the Commission, the Tazewell project would be a pumped hydroelectric storage facility. According to Dominion, the project would “be operated by Dominion Energy Virginia for hydropower generation during peak energy demand periods and pumping during off-peak energy demand periods.” Dominion points to grid benefits from pumped storage including integration of intermittent power generation sources, enhancement of grid stability and supply of other ancillary benefits. The applicant notes that the site “could support multiple configurations, including different-sized pumped-storage facilities,” a flexibility which Dominion said enables it to determine the best environmental, technical and economic solution.

The project would not use any existing dams or hydroelectric facilities, but would involve new dams and other facilities constructed for the proposed project. In its application, Dominion described two alternative configurations — a smaller Alternative 1 and a larger-capacity Alternative 2 – featuring an upper reservoir and a lower reservoir. Under either alternative, Dominion described potential water sources “for the initial fill and makeup water” as

(1) Mine ID P03_903 and (2) Mine ID P03_017. The initial fill water for the Project's reservoirs will be supplied by one or more of these water sources via a proposed pump and water conveyance system… Although the upper reservoir would be located on Oneida Branch and the lower reservoir would be located in West Fork Cove Creek, it is anticipated that the proposed Project will use mine water sources for the initial fill and makeup water.

Dominion says it will evaluate the feasibility of relying on mine water sources under the preliminary permit.

Dominion’s press release mentioned that it is also conducting in-depth studies of another potential site for a pumped hydroelectric storage facility, the former Bullitt Mine near Appalachia, Virginia. That mine has been closed since 1997 and is currently flooded.

In its application, Dominion cited 2017 Virginia legislation that it said “encourages one or more pumped storage stations and includes a requirement that all or a portion of it be powered by renewable energy produced in the coalfield region.”  That legislation amended existing law to allow a utility to petition the State Corporation Commission for approval of a rate adjustment clause to recover from customers the costs of “one or more pumped hydroelectricity generation and storage facilities that utilize on-site or off-site renewable energy resources as all or a portion of their power source and such facilities and associated resources are located in the coalfield region of the Commonwealth ... regardless of whether such facility is located within or without the utility's service territory.” The coalfield region is defined as including seven counties and one city: Lee, Wise, Scott, Buchanan, Russell, Tazewell and Dickenson Counties and the City of Norton.

Will clustering help New England's interconnection queue?

Faced with a persistent backlog of requests to interconnect to the electric grid across parts of New England, will the region's major grid operator adopt a "clustering" methodology to streamline the study process and reduce procedural delays?

At issue are ISO New England's interconnection procedures, which govern the process through which generators and transmission lines may interconnect to the New England bulk power system.  For nearly all large projects and some smaller ones, ISO-NE administers the process and conducts extensive engineering studies to determine whether such interconnections would be feasible without adversely affecting reliability and how they should be accomplished.  In general, ISO-NE uses a first-come, first-served basis: a project's impacts on the grid are studied in sequential order based on that project's position in the interconnection queue.  In practice, this means that a project's studies do not commence until the studies for projects ahead in line are complete.

According to ISO-NE, this system has worked well for most of the region.  Excluding northern and western Maine, the grid operator reports that on average, system impact studies are completed within a year of the customer's interconnection request.  But ISO-NE notes that its "Interconnection Queue has experienced a persistent backlog of requests to interconnect in northern & western Maine."  Many of these requests relate to wind projects located relatively far from the transmission system, but similar challenges could arise relating to large solar projects in parts of Maine, Vermont, or New Hampshire.

The grid operator may be able to address this backlog by changing its interconnection procedures to be more in line those adopted in other regions, by allowing "clustering" or pooled and simultaneous study of certain resources. As described by ISO-NE in a presentation delivered last year, all of the other Independent System Operators or Regional Transmission Organizations -- such as NYISO, PJM, MISO, CAISO, and SPP - include some form of clustering in the interconnection process; New England stakeholders have requested that ISO-NE investigate clustering; and the Federal Energy Regulatory Commission has also addressed clustering, including in a May 2016 technical conference.

ISO-NE's proposed clustering methodology would allow, under specific circumstances, for two or more Interconnection Requests to be analyzed in the same System Impact Study (SIS) effort.  Projects participating in a cluster would share cost responsibility for certain shared interconnection related transmission upgrades, known as Cluster Enabling Transmission Upgrades (CETU), identified by ISO-NE as necessary for the applicable interconnection requests to interconnect.

As noted in an April 2017 presentation to the NEPOOL Participants Committee, this proposal was favorably voted by the Transmission Committee on January 24, 2017 and by the Participants Committee on February 3, 2017.

The presumptive next step forward in New England's attempt to resolve the interconnection queue backlog by clustering studies would be that ISO-NE will file its tariff revisions with the FERC -- but the grid operator has signaled an intent to wait to file the revisions until there is "a high probability of a FERC quorum."  Three of the five seats on the Commission are presently vacant, and the Commission is currently operating without a quorum.  In the meanwhile, ISO New England's present tariff does not allow clustering of studies, so for now customers and others proposing to interconnect generation or transmission into the New England grid will continue to wait and push for reform.

Maine biomass commission to meet

A commission charged by the Maine legislature to study the state's biomass energy industry will hold its first meeting next month.  The study committee's work will result in a report to the legislature, and could include recommended changes to state law.

The Maine State House.

At the end of its 2016 session, the Maine legislature enacted a resolve establishing the Commission to Study the Economic, Environmental and Energy Benefits of the Maine Biomass Industry.  The resolve directed the commission to:

1. Review and evaluate the economic, environmental and energy benefits of Maine's biomass resources, as well as public policy and economic proposals to create and maintain a sustainable future for the Maine biomass industry;
2. Consider the interconnection of economic markets for biomass and forest products and the energy policy of the State;
3. Consider whether the environmental, economic and energy benefits of biomass support updating the State's energy policy to strengthen and increase the role that biomass and the forest products industry play throughout the State;
4. Consider the costs of implementing any recommendations and the effect of leaving current policies in place; and
5. Examine any other issues to further the purposes of the study. 

The Maine biomass commission has now been formed, and has scheduled its first meeting for August 2, 2016.  As prescribed by the resolve, its membership includes a mix of legislators and others interested in the state's biomass energy policy.

The resolve directed the biomass study commission to submit a report and any suggested implementing legislation for committee consideration by December 6, 2016.

Biomass was a hot topic in the past legislative session.  On a separate track, this spring the Maine legislature enacted a law establishing a long-term contracting program for biomass-fueled power plants.  The Maine Public Utilities Commission has issued a request for proposals under that program, with contract proposals due on or before July 29, 2016.

Federal tax credits drive renewable power, CO2 reduction

A report by the U.S. Energy Department's National Renewable Energy Laboratory found that recent extensions to tax credits for wind and solar energy will drive a net peak increase of 48-53 gigawatts in installed renewable generation capacity in the early 2020s.

NREL is the U.S. Department of Energy's primary national laboratory for renewable energy and energy efficiency research and development.  NREL is operated for the Energy Department by The Alliance for Sustainable Energy, LLC.

In its February 2016 report, Impacts of Federal Tax Credit Extensions on Renewable Deployment and Power Sector Emissions, NREL examined the potential impact of recently extended federal tax credits on the deployment of renewable generation technologies and related U.S. electric sector carbon dioxide (CO₂) emissions.

At issue are federal tax credits for renewable energy: the wind production tax credit (PTC) and the solar investment tax credit (ITC).  Congress acted in December 2015 to extend by 5 years the expiration dates for these tax credits, with a phaseout or ramp down of tax credit value over time.

The NREL study examined two key questions, under models with high and low natural gas prices:

1.  How might renewable energy deployment in the contiguous United States change with these recent federal tax credit extensions?
2. How might this change in renewable energy deployment impact CO₂ emissions in the power sector?

Under both sets of natural gas assumptions, the NREL study found that tax credit extension scenarios show greater renewable technology investments through the early 2020s than scenarios without extensions:

The study found that scenarios with tax credit extensions also show lower CO2 emissions from the U.S. electricity system:

Cumulative emissions reductions over a 15-year period (spanning 2016-2030) as a result of the tax credit extensions are estimated to range from 540 to 1,400 million metric tons CO₂.

In all scenarios, nearly all of the estimated growth in renewable energy capacity was primarily comprised of new solar and wind capacity, as opposed to biopower, geothermal, or hydropower technologies.

The NREL study concludes that tax credit extensions can have a "measurable impact" on future renewable energy deployment and electric sector CO2 emissions under a range of natural gas price assumptions.

FERC staff guidance for Clean Power Plan modeling

Staff of the U.S. Federal Energy Regulatory Commission have issued a white paper presenting guidance principles for modeling state plans to comply with the U.S. Environmental Protection Agency's Clean Power Plan carbon regulations from existing fossil fuel-fired electric power plants.

The EPA issued the Clean Power Plan on August 3, 2015 as a regulation under Section 111(d) of the Clean Air Act.  The Clean Power Plan limits carbon dioxide emissions from existing fossil fuel-fired electric power plants.  The final rule provides state specific goals for carbon dioxide emissions from affected electric generating units, including interim emissions goals from 2022 to 2029 and a final goal for 2030.

Due to congressional concern that environmental regulations not jeopardize the reliability of the electric grid, each covered state must demonstrate that it has considered reliability issues in developing its plan.  That consideration of reliability is certain to include modeling.  The Federal Energy Regulatory Commission has entered into an agreement with EPA and the U.S. Department of Energy to coordinate certain activities to help ensure continued reliable electricity generation and transmission during the Clean Power Plan's implementation.

In furtherance of that mission, on January 19, 2016, staff of the Commission released an 18-page white paper identifying four guiding principles that may assist transmission planning entities in conducting effective analysis of the Clean Power Plan and associated state, regional, or federal compliance plans.

These guiding principles address four areas:

• Transparency and stakeholder engagement: "transparency and stakeholder engagement in model development, model inputs and study designs can help identify policy alternatives and effectively evaluate assumptions, while also improving coordination across transmission planning regions."
• Study methodology and interactions between studies: "incorporating changes to current study methodologies can allow transmission planning entities to more effectively assess the impact of the CPP and associated compliance plans."
• Study inputs, sensitivities and probabilistic analysis: "using study inputs that account for uncertainty and test for sensitivity can help effectively assess the impact of the CPP and associated compliance plans."
• Tools and techniques: "adopting new modeling tools and techniques may help transmission planning entities better assess the overall impact of the CPP and associated compliance plans."

The FERC staff white paper notes that while "effectively evaluating the impacts of the CPP may present challenges, these challenges can be mitigated by using appropriate modeling tools and techniques."  Under the Clean Power Plan, states have until September 6, 2016, to submit either a final carbon-cutting plan or to request a two-year extension and to submit an initial plan for EPA review.

U.S. renewable energy share highest since 1930s

In 2014, about 9.8% of the total energy consumed in the U.S. came from renewable energy sources, according to the U.S. Energy Information Administration.  This represents the highest share of total domestic energy supply coming from renewable resources since the 1930s.

Prior to the growth of production and distribution networks for petroleum and other fossil fuels in the early 20th century, many homes used wood for heating as did industry.  This reliance on renewable biomass historically satisfied a significant portion of the total domestic energy demand.  But technological advances and the birth of the electric power industry led to greater use of other fuels.  As a result, the EIA reports that renewable resources' share of total domestic energy supply peaked in the 1930s, then declined.

But recent growth in U.S. renewable energy use has brought the country's energy mix back to nearly 10% renewable.  Indeed, from 2001 to 2014, renewable energy use grew an average of 5% per year, largely through increased use of wind, solar, and biofuels:

• Wind energy grew from 70 trillion Btu in 2001 to more than 1,700 trillion Btu in 2014.
• Solar energy (solar thermal and photovoltaic) grew from 64 trillion Btu to 427 trillion Btu.
• The use of biomass for the production of biofuels grew from 253 trillion Btu to 2,068 trillion Btu.

According to EIA, inn 2014, slightly more than half of all renewable energy was used to generate electricity.  Renewable energy accounted for 13% of energy consumed within the electric power sector, the highest renewable use attributable to any sector.

NYISO solar study announced

Solar power is booming in the U.S. -- but how will growth in solar photovoltaic generating capacity affect the electricity grid?  The operator of the state of New York's electric grid has announced a study of the potential for growth in solar power resources to determine their impact on grid operations over the next 15 years.

Solar panels recently developed in a farm field in Massachusetts.

The New York Independent System Operator (NYISO) operates New York State's high-voltage transmission network, runs the state's wholesale electricity markets.  NYISO also evaluates trends in utility infrastructure development and usage, and what changes in these patterns imply for future infrastructure needs.

One such trend is the recent rapid growth in installed solar electric generating capacity.  In New York, a state government initiative known as NY-Sun aims to reduce solar installation costs by stimulating demand and increasing the number of solar PV systems installed in the state.  The NY-Sun program envisions the installation of more than 3,000 megawatts of customer-sited solar capacity by 2023, supported by about $150 million in annual state funding for solar PV projects.  Already, in the first two years of NY-Sun, a total of 316 megawatts of solar electric has been installed or is under contract.

Unlike standalone utility-scale solar development, the solar buildout directly triggered by the NY-Sun program will occur “behind the meter” — that is, on the customer's side of the utility meter, as opposed to a typical power plant sited remotely from customer load.  Nevertheless, increased consumption of power produced by distributed generation might affect NYISO's load forecasts or grid operations.  So too might the collective impacts of many generators with variable but correlated output.

To prepare for this future, NYISO has announced a "solar study" to evaluate the growing impact of sun-powered generation.  The study will focus on the following objectives:

• Developing solar forecasting tools and preparing 15-year forecasts of solar PV capacity for each of the 11 load zones in New York State
• Researching how other independent system operators and regional transmission organizations have integrated solar resources into their grids
• Evaluating solar generation variability and its impact on customer load served by the NYS electric systems.
• Reviewing operational impacts of various levels of solar and wind resources.

The results of NYISO's solar study are expected to be released in a report later this year.

More solar faster, predicts New England grid operator

New England will likely see even more solar photovoltaic energy projects over the next decade than was previously projected, according to the latest draft forecast by the operator of New England's electric grid.

Solar photovoltaic panels on the roof of a Massachusetts home.

To help plan for future needs, grid operator ISO New England, Inc. is developing an updated forecast of solar photovoltaic project development in New England.  In 2014, ISO New England developed its first multistate forecast of PV capacity growth.  It based its 2014 PV forecast heavily on development goals articulated as policies in the six New England states.

ISO New England is now updating that forecast for 2015.  Its draft 2015 Solar PV Forecast, released on February 27, notes that PV development is happening more rapidly than was previously projected.  Using updated historical data, it acknowledges that through 2014, 40% more solar capacity was developed in the region than it previously estimated.  As a result of this faster-than-expected growth, the draft now predicts a higher level of cumulative photovoltaic project development through 2023.

Perhaps more significantly for the solar boom, ISO-NE's draft 2015 forecast also frontloads more new project capacity into 2015 and 2016, while decreasing the amount predicted to be newly developed in later years.  While last year's forecast also predicts more incremental solar capacity will be developed in each of the next three years than in later years, the frontloading is more prominent in the draft 2015 forecast.

The draft 2015 forecast projects that 2,138.8 megawatts of solar photovoltaic projects will be developed in New England by 2024.  This capacity is stated as an alternating current nameplate rating, even though photovoltaic cells essentially generate direct current electricity.  The study derates direct current capacity to alternating current with an 83% array-to-inverter ratio, so this implies an even higher number of megawatts if stated as direct current capacity, as most solar projects are described.

The draft 2015 forecast projects that these solar photovoltaic projects will give rise to a summer seasonal claimed capability of 748.6 megawatts.

ISO New England did not include in its draft 2015 PV forecast any update to its forecast of how much energy these projects would produce.  Instead it suggests that it must first finalize its forecast of installed photovoltaic capacity, and can then estimate the energy production associated with the forecast.  The report does repeat 2014's forecast of energy as illustrative, keeping in mind that actual amounts of energy generated from solar photovoltaic capacity in New England will likely be higher if capacity forecasts are revised upward as is proposed in this draft.

The 2015 draft PV report is now under review by ISO New England's Distributed Generation Forecast Working Group.  That group next meets on April 14, where the final draft forecast will be presented.

Report: New England electric sector will face gas supply deficit

A recently released report on the adequacy of New England’s natural gas pipeline infrastructure has identified the potential for shortfalls in gas supply to electric generators through 2020.  The November 20, 2014 report, Assessment of New England’s Natural Gas Pipeline Capacity to Satisfy Short and Near-Term Electric Generation Needs: Phase II, was prepared by consulting group ICF International for regional electric grid operator ISO New England Inc.  It found “a high probability that the electric sector will have a gas supply deficit on 24 to 34 day per winter by 2019/20.”

The Phase II report follows on a 2011/12 “Phase I” study by ICF of the adequacy of the natural gas pipeline infrastructure in New England to serve the combined needs of the core natural gas market and the regional electric generation fleet.  In the years since the Phase I study, existing natural gas and electric power systems have experienced significant changes, with further changes projected.  ISO-NE also identified the need to extend the power sector gas supply adequacy analysis beyond the peak winter and summer demand day, to examine supply adequacy throughout the peak winter demand period (December 1 through February 28).

ICF’s Phase II report presents its updated findings given these changes.  Its conclusions include:

• Despite the likelihood of 450 MMcf/d of new interstate natural gas transportation capacity being added by the end of 2016, the New England market is likely to remain supply constrained through 2020.
• Updating projections for energy efficiency has a significant impact on projected gas consumption for electric generation. The studied cases reduced projection winter peak day gas consumption by as much as 550,000 Dth by 2019/20.  However, this was not sufficient to eliminate the projected winter peak day supply deficits.
• Future imports of liquefied natural gas (LNG) into the region are likely to be well below the rated capacity of the import terminals.  Neither the Northeast Gateway nor Neptune offshore import terminal has received any shipments since 2010, and neither was projected to receive any future LNG shipments in this study.
• The Maritimes & Northeast Pipeline from Eastern Canada into New England is expected to continue to flow at full capacity on a peak winter day. Eastern Canadian gas production is expected to decline overall from 2015 through 2020, even as the Deep Panuke field ramps up its production. Historically, the Canaport LNG terminal in St. John, New Brunswick, has been managed to keep the pipeline full on peak winter days (when New England gas demand and gas prices are highest). In the future, with fewer LNG shipments coming in, the pipeline will flow full on fewer winter days, reducing natural gas supplies into New England.
• The Winter Near-Peak analysis indicates that gas supply deficits may occur not just on peak days, but also on multiple high demand days throughout the winter. Based on projected gas supplies, local distribution company (LDC) demands for retail gas supply, and electric generator gas demands, there is a high probability that the electric sector will have a gas supply deficit on 24 to 34 day per winter by 2019/20.

With the Phase II report now in ISO New England's hands, the grid operator has an updated analysis of the adequacy of the region's natural gas pipeline infrastructure to meet all the demands on it through 2020.  ISO New England describes itself as playing three critical roles: grid operation, market administration, and power system planning.  From all three of these perspectives, projections of a high probability of gas supply deficit for the electric power sector are troubling.  ICF's findings thus may shape how ISO New England -- or state and federal regulators -- reforms the New England gas and electric markets.

Value of distributed solar energy

What is the value of distributed solar photovoltaic electric generation?  An investigation by the Maine Public Utilities Commission into this question is ongoing, and will culminate in a report to the state legislature this winter.  At stake are policies and incentives to foster the growth of solar energy in Maine.

Distributed solar generation -- such as solar panels on rooftops and ground-mounted solar arrays -- is a small but rapidly growing sector of the U.S. energy mix.  Solar panels can produce renewable electricity, with no direct fuel use, emissions, or reliance on foreign energy sources.  Customer-sited and other distributed generation resources can also enhance the reliability of the local electric grid, and reduce the need for more expensive transmission and distribution upgrades.  The growing shift to solar energy is also seen as a driver of jobs and economic development.

Rooftop solar photovoltaic panels on a business in Patten, Maine.

In recognition of these benefits, states and the federal government have enacted a variety of policies and incentives for solar power development and use.  These policies include renewable portfolio standards which mandate that utilities source certain amounts of their power from renewable resources, as well as net metering policies which allow a customer to offset its power bill with energy produced from on-site solar panels.

But what is the true value of distributed solar energy resources?  In an effort to find out, in 2014 the Maine Legislature enacted An Act To Support Solar Energy Development in Maine.  This law is also known as the Maine Solar Energy Act, P.L 2013 Chapter 562 (codified at 34-B M.R.S. §§ 3471-3473).  The law expresses the legislative finding that Maine's solar energy resources "constitute a valuable indigenous and renewable energy resource."  Moreover, the law is predicated on the findings that solar energy development is unique in its benefits to and impacts on the climate and the natural environment, and that it can help Maine because it can displace fossil fuel combustion and associated air pollution and greenhouse gas emissions.   The Act set a state policy "to encourage the attraction of appropriately sited development related to solar energy generation, including any additional transmission, distribution and other energy infrastructure needed to transport additional solar energy to market, consistent with all state environmental standards; the permitting and financing of solar energy projects; appropriate utility rate structures; and the siting, permitting, financing and construction of solar energy research and manufacturing facilities for the benefit of all ratepayers."

With these findings noted, the Act directed the Maine Public Utilities Commission to construct a report by February 15, 2015 on the value of distributed solar energy generation in Maine.  In so doing, the Act requires the Commission to develop a method for valuing distributed solar energy generation.   By statute, this method must, at a minimum, account for:

• the value of the energy;
• market price effects for energy production;
• the value of its delivery, generation capacity, transmission capacity and transmission and distribution line losses; and
• the societal value of the reduced environmental impacts of the energy.

The also Act requires the Commission's report to include a summary of options for increasing investment in or deployment of distributed solar energy generation, which may include recommendations for what Maine should do.

The Commission's investigation is ongoing.  On October 23, 2014, the Commission released a draft of its consultants' initial report, "Maine Distributed Solar Valuation Methodology."  That document is designed as a draft of the methodology to be used in the valuation phase, offered for public review and comment.

The Commission will accept written comments on the draft report until November 12, 2014.  In addition, the Commission and its consultant, Clean Power Research, will hold a work session on the Draft Methodology on October 30, 2014.

Following the first phase to establish the valuation methodology, the Commission and its consultants will conduct a second phase in which the methodology will be applied to Maine to calculate the value of distributed solar generation.  The Commission's work will be summarized in its report to the legislative energy committee, a draft of which the Commission plans to release in January 2015.

Study quantifies New England distributed generation, growth

Distributed generation – small-scale electric generation facilities installed at consumer sites – plays a growing role in the resource mix used to meet society’s needs. Typical distributed generation assets include solar photovoltaic panels and co-generation or combined heat and power units developed at homes and businesses. A study released yesterday found that distributed generation capacity in New England could roughly triple in the next decade – and that regional electric grid operator ISO New England Inc. needs to account for distributed generation in its planning.

As New England’s regional transmission organization, ISO New England plans for and coordinates the development of electric transmission infrastructure. In the past decade, New England ratepayers have spent approximately $5 billion on transmission additions and expansions. ISO New England’s 2012 Regional System Plan calls for the investment of another $6 billion in transmission projects in the coming years. As a result, regional transmission rates roughly tripled between 2006 and 2010, and continue to grow.

ISO New England’s plans are based on its forecasts of future system needs, including anticipated load growth and changes in the electric generation portfolio used to satisfy customer demand. But ISO New England may be underestimating the extent to which non-transmission alternatives like distributed generation can satisfy demand at a lower total cost than transmission line development. According to “Forecasting Distributed Generation Resources in New England: Distributed Generation Must Be Properly Accounted for in Regional System Planning”, prepared by Synapse Energy Economics Inc., ISO New England is significantly underestimating the current and potential distributed generation in New England, particularly with respect to solar photovoltaic resources.   According to Synapse, “This practice results in the ISO ignoring likely transmission and reliability benefits and overestimating electricity load—with ratepayers being asked to pay for larger, more expensive transmission upgrades than are needed.”

ISO New England predicts that about 800 MW of solar photovoltaic generation will be installed in New England by 2021, but excludes other types of distributed generation from its projection. But Synapse found that over 980 megawatts of distributed generation assets are already installed in the six New England states. By 2021, Synapse predicts that this could grow to over 2,855 MW based on existing policies and development trends.

Synapse Energy Economics, Inc., Forecasting Distributed Generation Resources in New England: Distributed Generation Must Be Properly Accounted for in Regional System Planning, at page 19.

State policies and the favorable economics of distributed generation projects are driving their adoption on a wider scale than in previous years.  For example, after exceeding its previous solar photovoltaic target, Massachusetts recently increased its target to 1,600 MW.  Renewable portfolio standards, net metering policies, and feed-in tariffs all contribute to the proliferation of distributed generation, as does a cost differential that makes natural gas-fired cogeneration more cost-effective than burning oil for heating and purchasing electricity in commercial and industrial applications.

Synapse’s report concludes, “It is essential that the ISO stop ignoring the impacts DG resources have on system planning—both their benefits and their challenges. This report provides a reasonable estimate of what the future holds for these resources and makes one thing very clear: assuming that these resources do not exist is unacceptable.”

Whether and how ISO New England and the states take distributed generation into account remains to be seen, but if the trends noted in the Synapse report play out to even a modest degree, non-transmission alternatives such as distributed generation may be able to limit further increases in regional transmission rates.