FERC distributed energy resource technical report

A technical report by U.S. electricity regulatory staff assesses the potential reliability issues and likely benefits to the bulk power system resulting from an increased penetration of distributed energy resources. According to the report, increasing penetration of distributed energy resources may bring several associated reliability benefits to the bulk power system -- or could cause reliability concerns, if the resources are not properly accounted for.

Distributed energy resources, or DERs, have no single definition -- but they are generally conceived of as small, geographically dispersed electric resources, installed and operated on the distribution system at voltage levels below the typical bulk power system levels of 100kV. Historically, the term focused on generation like rooftop solar panels or on-site combined heat and power plants, but its meaning has broadened to include energy efficiency, microgrids, and even new technologies like energy storage. Distributed energy resources can be cost-effective alternatives to traditional utility infrastructure and business models.

Distributed energy resources installations have increased significantly in some regions of the United States in recent years thanks to factors including technology advances and state energy policies. In 2016, when distributed energy resources of all types accounted for about two percent of the nation's installed generation capacity, distributed solar photovoltaic (PV) installations alone represented over 12 percent of new capacity additions.  At the same time, regulators and industry participants are working to integrate these resources into the grid from engineering, reliability, and system planning perspectives.

In February 2018, staff of the Federal Energy Regulatory Commission published a report, "Distributed Energy Resources: Technical Considerations for the Bulk Power System." This report filed in Docket No. AD18-10-000 considers how the increasing penetration and integration of distributed energy resources in specific regions may affect bulk power system reliability. It summarizes technical assessments performed by Commission staff using industry power system models and commercially available power system simulation software "to identify the potential reliability issues and likely benefits to the bulk power system" from increasing distributed energy resource penetration. The study notes that its modeling of distributed energy resource capacity was "based on current trends for technology types, operational capabilities, and deployment distributions."

According to the report, greater penetration of distributed energy resources could have associated reliability benefits for the bulk power system. For example, by providing power close to the customer distributed resources can serve to reduce grid losses and reduce system peak load, or can serve as non-transmission alternatives that displace the need for more expensive wires upgrades.

At the same time, the report warns that "increasing DER capacity, if not properly accounted for, could cause reliability concerns for the bulk power system." It calls for improving and refining the data that is available for distributed energy resources for incorporation into planning and operating models, noting, "Collecting and using the most current and accurate data is key to getting a complete picture of how DERs affect the bulk power system."

The report identified key bulk power system reliability topics to explore in light of the growing adoption of distributed energy resources in the U.S., including:

• The impact of the current common industry modeling practice of netting DERs with load, which may mask the effects of DER operation;
• DER capabilities for voltage and frequency ride through during contingencies;
• The potential for improved voltages due to the unloading of the bulk power system associated with the location of DERs at or near customer loads;
• Potential effects upon system -wide transmission line flows and generation dispatch due to changing load patterns;
• The sensitivity of voltage or power needs to different types of DER applications (i.e., providing energy, capacity, or ancillary services);
• The need to develop planning processes that capture more detailed models of DERs and allow for modeling of the interface between the transmission and distribution systems to enable information exchange and more accurate calculations of the DER impact on the bulk power system; and
• The advantages and disadvantages of allowing DERs to participate directly in the organized wholesale electric markets.

The report also calls for continued examination of other issues, such as "sensitivities with higher DER penetration levels, changes in siting patterns, and potential impacts to the system’s response to events, disruptions and outages, including frequency events." It concludes, "Efforts such as these could help track and assess the impact of changing conditions on the bulk power system to identify emerging trends and address potential future reliability challenges."

Massachusetts community microgrid projects solicited

A Massachusetts economic development agency focused on clean energy has launched a program seeking to catalyze the development of community microgrids throughout Massachusetts.

Generally speaking, a microgrid is a localized power grid that can disconnect from the traditional grid to operate autonomously.  According to the U.S. Department of Energy, a microgrid's ability to operate while the main grid is down means microgrids can strengthen grid resilience and mitigate disturbances, while enabling faster system response and recovery once reconnected to the main grid. Microgrids can also support flexibility and efficiency, by enabling the integration of growing deployments of renewable and distributed energy resources like solar, and by reducing energy losses in transmission and distribution.
 
A "community microgrid" could be defined in several ways, but a typical definition focuses on a multi-user microgrid providing electrical and/or thermal energy to multiple consumers, integrated with and supported by the local community, relevant utilities, and building or site owners.  As with other microgrids, a community microgrid implementation could reduce energy costs and reduce greenhouse gas emissions, while providing increased energy resilience.

While federal support for microgrids has existed for years, states are now becoming active in exploring how microgrids can help meet society's energy needs and policy goals. Massachusetts is one hotbed of interest in microgrids, and a recently announced program could help stimulate the microgrid industry. The Massachusetts Clean Energy Center’s (MassCEC) Community Microgrids Program anticipates providing about $75,000 in funding to support each of 3 to 5 prospective community microgrid projects with the following characteristics:

• Are community, multi-user microgrids (as opposed to single owner or campus-style microgrids) located in Massachusetts -- but MassCEC will consider proposals from Applicants with an existing campus wishing to extend the microgrid to additional parties outside of its borders;
• Demonstrate significant potential to reduce greenhouse gas emissions through the integration of energy efficiency, Combined Heat and Power (“CHP”), renewable energy systems, electric and/or thermal storage technologies, demand management, energy efficiency, and other relevant technologies;
• Have the active and engaged support of the local utility (either investor-owned or municipal light plants) and other relevant stakeholders;
• Encompass a public or private critical facility, including but not limited to schools, hospitals, shelters, libraries, grocery stores, service (gas) stations, fire/police stations or waste water treatment plants;
• Support the distribution system by addressing capacity concerns, providing black start capability, facilitating renewables integration, or providing other services that are meaningful to the local utility;
• Attract third party investment; and 
• Highlight Massachusetts-based clean energy/microgrid technology.

MassCEC is presently soliciting Expressions of Interest from groups interested in participating in feasibility assessments for community microgrid projects meeting its defined criteria.  According to MassCEC, respondents may include municipalities and their public works departments, electric distribution companies, municipal light plants, emergency services departments, owners of critical infrastructure such as hospitals and financial institutions, self-organized groups of commercial building owners, developers or any other actor that either owns property within a potential microgrid or can demonstrate that they represent stakeholders with the capability of developing a community microgrid.  Support from the local government and the relevant electric or gas distribution company is also required.

MassCEC says it intends its funding to support feasibility assessments to advance the selected microgrid projects through the early project origination stages, enabling them to attract third-party investment. Projects that produce a favorable feasibility assessment may then be eligible for additional technical assistance or grants for later stages of project development

Completed expressions of interest, including all required documentation, must be received by MassCEC by Friday, June 23, 2017 by 4:00pm. MassCEC anticipates awarding the first round of feasibility assessments in Q3 2017.

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.

July 6, 2010 - biomass after the Manomet biomass study

A recent report by the Manomet Center for Conservation Sciences has been widely reported as casting doubt on whether biomass-generated power is truly climate-friendly. However, another set of sources are critiquing the mass-media coverage as misleading. (For example, see this Morning Sentinel editorial expressing support for biomass, including wood pellets.)

So what did Manomet really study? The Executive Summary provides a 4-page overview, and the whole report is available here. The Manomet work addresses three policy questions that are being asked as Massachusetts develops its policies on the use of forest biomass:

1. What are the atmospheric greenhouse gas implications of shifting energy production from fossil fuel sources to forest biomass?
2. How much wood is available from forests to support biomass energy development in Massachusetts?
3. What are the potential ecological impacts of increased biomass harvests on forests in the Commonwealth, and what if any policies are needed to ensure these harvests are sustainable?

Manomet's study divides the carbon impacts of biomass combustion into two phases: carbon debt and carbon dividend. Manomet uses "carbon debt" to describe the excess of emissions from forest biomass burning over fossil fuels. However, over time, forest re-growth removes this carbon from the atmosphere, and can reduce this carbon debt to zero. Over even longer times, after the carbon debt is paid off, biomass yields "carbon dividends" -- atmospheric greenhouse gas levels below the levels that would have resulted from making the same amount of energy by using fossil fuels.

Manomet concludes that the carbon debt from burning biomass in combined heat-and-power is lower than the debt created from utility-scale stand-alone biomass plants -- not a surprising result for anyone familiar with CHP. Manomet also notes that how quickly a biomass project "breaks even" over its carbon debt depends on what resources the biomass replaces. Replacing oil provides carbon dividends within 5 years, while Manomet found that replacing natural gas electric generation with biomass may not break even after 90 years.

Manomet also found that within Massachusetts, there wasn't that much more biomass available -- although if biomass prices rise (probably due to energy prices rising), it would be economical to harvest more wood within the Commonwealth.

So when we hear the "Manomet report" described as dooming the biomass industry, I recommend a closer reading of the report itself, to see its true impacts on biomass energy.

Also in Maine editorials: the Lewiston Sun Journal supporting wind power, including former Governor Angus King's proposed 128 MW wind farm in Highland Plantation. The editorial notes that former Green Independent Party candidate Jonathan Carter (who lives 3.5 miles from the Highland site) publicly opposes wind in Maine. The editorial observes that some of Carter's concerns are valid -- like impacts from roadbuilding, or scenic impacts -- but that on the whole, as a policy matter, these downsides are worth facing in order to reap the upside. Whether or not you agree with the Sun Journal's editorial board, they did a great job laying out the policy considerations. The mere existence of a downside does not make bad policy. No real-world solution is flawless; all have their downsides. But if society feels those downsides are worth the upside, then that choice can make sense.

How many Maine energy-related editorials can there be in one week? At least one more, with the Bangor Daily News expressing support for wind energy.

Meanwhile, breaking news: Maine Earth First is blocking access to the Kibby Mountain site, where TransCanada is adding 22 more towers to its existing 22 tower array. About 350 Earth Firsters are attending Earth First's annual weeklong international gathering nearby.

And way out there on the R&D level: researchers at Washington State University have created a never-been-seen-before form of ultra-high density xenon difluoride (XeF2). Nifty stuff, especially so since it could theoretically be used to store radical amounts of energy. In essence, as you compress XeF2, the molecules change shape: the massive amount of mechanical compression energy is converted into chemical energy, resulting in a whole lot of juice stored in a little box. This is all way too new to be commercial yet, but keep your eyes on the horizon for this technology.

Thomas Casten on CHP

I recently read an interesting article which aims to identify obstacles to broader use of combined heat and power (CHP) in the Nov.-Dec. issue of Cogeneration and On-Site Power Production. The article by Thomas Casten notes that despite the potential to cut US emissions by 20% and save consumers $80 to $100 billion per year, US markets remain dominated by the central generation plant model - a model whose overall generation efficiency is about 33%.

Casten points to ratemaking policy for the electric industry as a cause of this resistance: the regulator-approved electricity rate structure drives utilities to want to maximize their sales, which leads to utility opposition to broader implementation of local generation.

Casten gives an overview of recent history. In 1978, PURPA allowed efficient cogenerators to sell to their local distribution utilities at avoided cost. PURPA may have broken the monopoly on generation, but it preserved utilities' monopoly on distribution. In response, utilities set high rates for back-up service to make self-generation less attractive; because cogenerators had no alternative options for back-up distribution service, utilities could force customers to pay this higher price. Likewise, utilities began making the interconnection process more onerous by requiring extensive studies, and by requiring interconnections to be at transmission-level voltages.

We have seen utilities interpose these obstacles. For example, one local distribution company attempted to shift its rate structure to recover more from customers based on their peak demand using a "demand ratchet". Although this reduced the volumetric energy component of the utility's rates, the effect on a customer who had recently installed self-reliant cogeneration was to require that customer to pay nearly the same amount for backup service as it had been paying for full-requirements service. Only through a rate case before the Public Utilities Commission did we push the utility back.

The 1992 Energy Policy Act is Casten's next milepost. EPAct 1992 broadened the right to sell power at wholesale, while eliminating the cogeneration requirement. In the ensuing decade, over 120,000 MW of merchant gas-fired generation was built, and coal and nuclear plants increased their run-time. Meanwhile, many states forced utilities to divest their generation.

Other highlights include:

• US T&D line losses average 9%, and can reach 25% at peak. By contrast, local generation losses might be 2%.
  
• T&D development is expensive, and has a high capital cost. Local generation requires little to no T&D build-out.
• Nearly half of the average 10 cents per kWh customers pay in the US goes to pay for line losses, return on T&D capital, and operations. Local generation incurs none of these costs.

Casten concludes that the US should establish enhanced incentives for clean generation including CHP. Specifically, Casten proposes a federal requirement that utilities develop a clean standard offer which includes distribution costs. Casten estimates that this would result in a 15% decrease in rates paid by consumers.

Casten also dips into climate change issues. He proposes an "output-based pollution allowance system", under which a decreasing number of allowances are allocated to generators to be credited against MWh generation and Btu conversion.

Personally, I see CHP as a significant opportunity for the future. I'd even consider installing CHP units in new residential construction. Particularly once the installed price goes down, we can achieve both environmental and financial goals through efficient cogeneration.