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."

DOE Hydropower Vision report

The U.S. Department of Energy (DOE) has released a report on the future of domestic hydropower.  Its Hydropower Vision finds that U.S. hydropower could grow from 101 gigawatts of capacity in 2015 to nearly 150 gigawatts by 2050.  More than 50% of this growth could be realized by 2030, according to the report.  Much of the new capacity would come from pumped storage, with the remainder coming from upgrades to existing plants, adding power at existing dams and canals, and "limited development of new stream-reaches."

DOE's Wind and Water Power Technologies Office describes its report, Hydropower Vision: A New Chapter for America’s First Renewable Electricity Source, as presenting "a first-of-its-kind comprehen sive analysis to evaluate future pathways for low-carbon, renewable hydropower (hydropower generation and pumped storage) in the United States, focused on continued technical evolution, increased energy market value, and environmental sustainability." While it does not evaluate or recommend new policy actions, the report does analyze the "feasbility and certain benefits and costs of various credible scenarios, all of which could inform policy decisions at the federal, state, tribal, and local levels."

The report's Executive Summary presents an overview of the report, and its three "pillars" or foundational principles developed in collaboration with stakeholders: optimizing the value and power generation contribution of the existing hydropower fleet, exploring the feasibility of "credible long-term deployment scenarios for responsible growth of hydropower capacity and energy production," and sustainability.  Analyzing data and modeled scenarios, the report found that "under a credible modeled scenario in which technology advancement lowers capital and operating costs, innovative market mechanisms increase revenue and lower financing costs, and a combination of environmental considerations are taken into account—U.S. hydropower including PSH could grow from 101 GW of capacity in 2015 to 150 GW by 2050."

Chapter 1 of the Hydropower Vision describes how technical resource assessments and computational models can be used to interpret hydropower's future market potential.  It also evaluates potential innovations or nontraditional approaches to technology and project development that could affect the future development of new hydropower projects.

Chapter 2 of the Hydropower Vision presents a snapshot of the state of the U.S. hydropower industry as of year-end 2015, from the Energy Department's perspective.  It notes that hydropower generation and pumped storage have "provided a stable and consistently low-cost energy source throughout decades of fluctuations and fundamental shifts in the electric sector, supporting development of the U.S. power grid and the nation’s industrial growth in the 20th century and into the 21st century." The report points to 2015 data showing 2,198 active hydropower plants in the U.S. with a total capacity of 79.6 gigawatts, plus 42 pumped storage hydro plants totaling another 21.6 gigawatts.  In 2015, hydropower provided about 6.2% of net U.S. electricity generation, and 48% of all U.S. renewable power.

Chapter 3 of the report explores over 50 possible future scenarios for the hydropower industry, to assess the nation's hydropower potential.  It presents an extensive body of analysis, considering potential contributions over time to the electric sector of both the existing hydropower fleet and new hydropower deployment resulting from: upgrades at existing plants, powering of non-powered dams (NPD), pumped storage hydropower (PSH), and new stream-reach development (NSD).  It found that the greatest influence on potential growth scenarios comes from 3 variables: technological innovation, environmental considerations, and financial improvement.

The report's fourth chapter lays out a roadmap of 64 potential actions for stakeholder consideration, "to optimize hydropower’s continued contribution to a clean, reliable, low-carbon, domestic energy generation portfolio while ensuring that the nation’s natural resources are adequately protected or conserved."  These actions are organized around 5 topical areas: technology advancement, sustainable development and operation, enhanced revenue and market structures, regulatory process optimization, and enhanced collaboration, education, and outreach.

As noted by the Energy Department, while utility-scale battery storage projects are starting to be developed, most U.S. electricity storage capacity takes the form of pumped storage.  Flexible and reliable generating or storage resources can support efforts to integrate increasing amounts of intermittent renewable energy sources, like wind and solar, into the grid.

Maine examines interconnection standards

The Maine Public Utilities Commission has opened an inquiry into whether it should change its rule governing how small distributed generation resources may interconnect with the electric grid.  This small generator interconnection procedures inquiry may reshape how distributed energy resources will interconnect with the Maine grid going forward.

While many large central power plants are subject to some federal regulation, states generally may prescribe the standards for how most solar photovoltaic panels and other small distributed energy resources may interconnect with the grid.  Interconnection standards and procedures are designed to provide a safe, fair, and timely way for utility customers to connect generation to the grid.

In a 2009 report, the Maine Public Utilities Commission concluded that it should create standardized, statewide interconnection procedures for Maine’s utilities.  In the Commission’s view, “standardized rules would increase the efficiency of the interconnection process, encourage the increased use of renewable energy and other distributed generation resources like micro combined heat and power systems, and may foster an easier business environment for the companies that sell and install small generation systems.”

In 2010, the Commission adopted its Rule Chapter 324, Small Generator Interconnection Standards.  That rule was based largely on model standards released by the Interstate Renewable Energy Council (IREC) in 2009, which were themselves based on the federal Small Generation Interconnection Procedures.  While the Commission adopted minor changes to Chapter 324 in 2013, it remains largely as originally adopted.

At the same time, the intervening years have brought changes to some of the context for interconnection issues.  First, IREC has updated its model standards.  The most recent edition, released in 2013, features significant changes from the prior standards, including the creation of a pre-application report, changes to the application fees for interconnection review, and definitional clarifications.

Second, increasing adoption of distributed generation has led FERC and state regulators to consider whether small generation facilities should be required to have “frequency and voltage ride through capability”, an ability to protect the grid’s reliability as amount of distributed generation grows on the electrical system.

In light of these developments, the Maine Commission has issued a notice of inquiry seeking comment on these issues.  According to that notice, the inquiry will assess “whether and to what extent Chapter 324 should be revised to (1) reflect changes in the IREC interconnection standards and procedures and (2) incorporate requirements for frequency and voltage ride through capability of small generation facilities.”

The Commission has docketed the case as Docket No. 2016-00068, and requests public comment by May 20, 2016.

Report projects modest need for electric generation capacity growth

The U.S. Energy Information Administration has projected that 351 gigawatts of new electric generating capacity will be added to the U.S. grid between 2013 and 2040.  This projected new capacity, most of which EIA expects to be fueled by natural gas, will replace older power plants as they retire, as well as modestly increasing the country's net installed capacity.

EIA's forecast implies a growth rate well below recent annual levels observed.  Under EIA's projection, capacity additions through 2016 will average 16 GW per year.  But from 2017 through 2022, EIA expects additions of less than 9 GW per year as the existing generating fleet will be sufficient to meet expected demand growth in most regions.  From 2025 to 2040, annual additions increase to an average 14 GW per year, but remain below recent levels.

EIA expects that natural gas will be the primary fuel source for the projected added capacity, accounting for 73% of capacity additions in the reference case (or 255 GW).

Renewables will account for 24% of the new capacity (or 83 MW).  Of renewable capacity additions, 39 GW are solar photovoltaic (PV) systems (60% of which are rooftop installations).  Another 28 GW are wind, most of which will occur by 2015 to qualify for federal renewable energy production tax credits).

New nuclear capacity will total about 3% (or 10 GW), including 6 GW of plants currently under construction and 4 GW projected after 2027.

EIA also projects that 1% of capacity additions (or less than 3 GW) will come from coal, with more than 80% of that total currently under construction.  EIA notes that federal and state environmental regulations and uncertainty about future limits on greenhouse gas emissions reduce the attractiveness and economic merits of coal-fired plants.

Like any forecast, EIA's projections rest upon a series of assumptions.  Under alternative cases, we might experience actual capacity additions that differ from EIA's forecasts.  Nevertheless, the EIA Annual Energy Outlook 2014 offers a glimpse of changes to the portfolio composing our energy mix may come in the next decades.

U.S. natural gas to pass coal as electricity fuel in 2035

Coal will continue to fuel the largest share of electricity generated in the U.S. until 2035, when natural gas will surpass it, according to a recent federal report.

The U.S. Energy Information Administration's 2014 Annual Energy Outlook presents a long-term forecast of energy supply, demand, and prices from the present through 2040.  Its scope includes predictions about shifts in the portfolio of types of electricity generating resources used to produce power.  The largest such trend projected in EIA's 2014 report is that the market share of coal and nuclear generators will likely decline over the next two decades, as natural gas-fired and renewable electricity sources grow in prominence.

Historically, coal has fueled the largest share of electricity generated in the U.S.  Typically operating as baseload generation, coal has traditionally been a relatively low-cost fuel for electric production.  Coal's share of the electricity mix peaked in 2007, at 49% of all electric power generated.  Since then, coal's share has declined; in 2012, coal-fired generators produced 39% of all electricity generated by utilities -- still the largest piece of the generation portfolio, despite a significant decline.

Coal's role in the nation's energy mix is under challenge from multiple fronts.  Economically, the increased availability of lower-cost natural gas has made coal less competitive.  Meanwhile, tighter environmental regulations -- such as the U.S. Environmental Protection Agency's Mercury and Air Toxics Standards, or MATS rules -- have placed additional pressure on coal plant operators to either invest in upgraded environmental controls or shut down.

At the end of 2012, 310 gigawatts of coal-fired generating capacity was available to run in the U.S.  Of that, EIA projects that 50 gigawatts will be retired by 2020 under its base case model.

Under EIA's model, natural gas will grow its market share while coal declines.  EIA projects that 70% of all new capacity added before 2040 will be fueled by natural gas.  If EIA's assumptions hold, natural gas will surpass coal as a fuel for electricity generation in 2035.

While EIA's model rests on a series of assumptions, all of the alternative cases examined by EIA assume that coal-fired capacity will be retired, while natural gas-fired and renewable generation will grow.  What will the future hold for the U.S. energy mix?