New England's electric grid and winter 2017-18

Monday, December 11, 2017

New England's electricity grid is ready for reliable operations this winter, says the region's grid operator -- but special operating procedures might be required in the case of unexpected outages or fuel delivery constraints.

According to ISO New England Inc., the independent, not-for-profit regional transmission organization responsible for almost all of New England, supplies of electricity should be sufficient to meet regional consumer demand this winter. The grid operator projects a peak demand of 21,197 megawatts under normal winter temperatures (about 7 degrees Fahrenheit), or 21,895 megawatts of peak demand if extreme weather occurs (2 degrees F).

These projections are higher than last winter's actual peak demand (19,647 MW on December 15, 2016, during the hour from 5 to 6 p.m.), but lower than the region's all-time winter peak (22,818 MW, on January 15, 2004) or the record peak (28,180 MW on August 2, 2006). ISO-NE notes that total energy consumption and regional peak demand have remained flat in recent years "as a result of increased use of energy-efficiency measures and behind-the-meter solar photovoltaic (PV) systems."

The grid operator projects that it has commitments from enough power plants and demand-side resources to meet the forecast peak demand under both normal and extreme weather conditions. ISO-NE also points to its fifth seasonal Winter Reliability Program provides incentives for generators to stock up on oil or contract for liquefied natural gas, and also for demand-side resources committing to be available. As noted by the grid operator, the availability of generators with fuel has been a key reliability factor during recent cold winters, thanks in part to the past winter reliability programs. ISO-NE says its new capacity market performance incentive rules which take effect June 1, 2018 should eliminate the need for future special programs.

At the same time, the grid operator warns of its "continuing concern" over the availability of fuel for those power plants to generate electricity when needed. In a press release, ISO-NE noted, "The region’s natural gas delivery infrastructure has expanded only incrementally, while reliance on natural gas as the predominant fuel for both power generation and heating continues to grow." It observed that over 4,000 megawatts of natural-gas-fired generating capacity is at risk of not being able to get fuel when needed, due to natural gas pipeline constraints.

The grid operator also cites changes to the regional portfolio of generating resources, such as the May 2017 retirement of a 1,500 MW coal- and oil-fired power plant. According to ISO-NE, the Brayton Point power plant's closure "removed a facility with stored fuel that helped meet demand when natural gas plants were unavailable." The reliability benefits of stockpiled fuel and baseload power and related proposals are currently under examination by the Federal Energy Regulatory Commission.

The grid operator listed challenges that could affect power system operations such as "if demand is higher than projected, if the region loses a large generator, electricity imports are affected, or when natural gas pipeline constraints limit the fuel available to natural-gas-fired power plants," as well as the special operating procedures it would invoke in those circumstances.

U.S. approves Arctic oil drilling off Alaska

Thursday, November 30, 2017

The U.S. has issued a final permit allowing Eni US Operating Co. to drill for oil and gas in Arctic waters. The November 28 approval by the Bureau of Ocean Energy Management's Bureau of Safety and Environmental Enforcement of Eni's application for a drilling permit represents the first approval of U.S. Outer Continental Shelf oil exploration in the Arctic in over 2 years.

Eni U.S. Operating Co. Inc. had applied for the permit earlier this year, and federal regulators gave it conditional approval in July 2017. With the final approval now issued, regulators expect Eni to begin drilling an exploratory well from a man-made island in the Beaufort Sea as early as December 2017. While the drillsite would be located within State of Alaska waters, the company's "extended reach drilling" is expected to target a formation in federal waters over the Outer Continental Shelf.

Beyond Eni's approved exploration plans, some other companies have expressed interest in increasing production of oil and gas from federal and state lands in Alaska such as the Alaska National Wildlife Refuge as well as nearby Arctic waters. The area is considered likely to hold producible hydrocarbons.

But previous efforts to explore for oil in the U.S. Arctic have met with challenges. In 2008, Royal Dutch Shell spent over $2 billion to acquire federal leases beneath the Chukchi Sea in the U.S. Artic; after unsuccessful efforts in 2012 and 2015 to conduct drilling on the prospects which were challenged by ice and technical problems, in 2016 Shell walked away from all but one of its federal offshore leases in the Chukchi. While the Trump administration may be more supportive of U.S. Arctic oil and gas production than under President Obama, project economics and environmental concerns remain challenging - let alone the rigors of the Arctic marine environment.

2017 FERC Report on Enforcement

Monday, November 27, 2017

Federal regulators of U.S. energy markets and infrastructure described an increase in litigation activities in the most recent fiscal year. According to the eleventh annual Report on Enforcement issued by the Federal Energy Regulatory Commission’s Office of Enforcement, the office has five cases pending in various federal district courts.

The Commission is responsible for enforcing various laws and regulations affecting energy markets and infrastructure. On November 16, 2017, staff from its Office of Enforcement presented to the Commission on the office's activities in Fiscal Year 2017 (October 1, 2016 through September 30, 2017).

According to the 2017 Report on Enforcement, the office has maintained the previous year's enforcement priorities: (1) fraud and market manipulation; (2) serious violations of reliability standards; (3) anticompetitive conduct; and (4) conduct that threatens transparency in regulated markets.

As noted in the Commission press release announcing the 2017 enforcement report, "Conduct involving fraud and market manipulation poses a significant threat to the wholesale energy markets because it undermines FERC’s goal of ensuring efficient energy services at reasonable cost, and it erodes confidence in those markets to the detriment of consumers and competitors." The report notes that conduct which is anticompetitive or which threatens market transparency "undermine confidence in the energy markets and harm consumers and competitors." It also emphasizes the importance of compliance with reliability standards established by Electric Reliability Organization NERC.

The report describes activities by each division of the Office of Enforcement, including staff negotiation of five settlements that resulted in more than $51 million in civil penalties and disgorgement of more than $42 million in unjust profits. These settlements are in addition to the Commission’s November 7, 2017, settlement with Barclays Bank and three traders that requires Barclays to pay a $70 million penalty and disgorge $35 million in unjust profits.

While noting that at least one litigation matter has settled since the close of the fiscal year, the report states that Enforcement staff continues litigating five Federal Power Act matters in United States District Courts, along with two Order to Show Cause proceedings under the Natural Gas Act. According to the report, "In total, as of the end of FY2017, counting all pending federal court matters and the two NGA OSC proceedings before the Commission, staff sought to recover $806,865,000 in civil penalties and $53,987,678 in unjust profits through seven litigation proceedings."

Looking forward, the report emphasizes that in FY2018 the Office of Enforcement will continue to pursue these priorities.

Fourth National Climate Assessment special report

Monday, November 13, 2017

The Trump administration has released an updated assessment of the science of climate change, concluding "based on extensive evidence, that it is extremely likely that human activities, especially emissions of greenhouse gases, are the dominant cause of the observed warming since the mid-20th century."

The report by the U.S. Global Change Research Program, 2017: Climate Science Special Report: Fourth National Climate Assessment, Volume I, represents the first of two volumes of the Fourth National Climate Assessment, mandated by the Global Change Research Act of 1990. It builds on previous assessments while covering new information developed since the May 2014 publication of the Third U.S. National Climate Assessment. The program is composed of 13 Federal departments and agencies that carry out research and support the Nation’s response to global change, including the Department of Agriculture, the Department of Commerce (NOAA), the Department of Defense, the Department of Energy, the Department of Health and Human Services, the Department of the Interior, the Department of State, the Department of Transportation, the Environmental Protection Agency, the National Aeronautics and Space Administration, the National Science Foundation, the Smithsonian Institution, and the U.S. Agency for International Development.

According to the Fourth National Climate Assessment special report, "Recent data add to the weight of evidence for rapid global-scale warming, the dominance of human causes, and the expected continuation of increasing temperatures, including more record-setting extremes." The report cites temperature data, global average sea level rise, and changes in the characteristics of extreme weather events as evidence.

While the report does not provide much detail on potential policies that could be adopted to address climate change, it does link the magnitude of climate change beyond the next few decades to the amount of carbon dioxide and other greenhouse gases emitted globally.

Maine utility storm damage and response in question

Thursday, November 9, 2017

As Maine recovers from widespread power outages following a storm, what will the event mean for how its public utilities design, operate, and maintain their electric grids?

On October 30, 2017, a storm brought winds and heavy rain to much of New England. In Maine, about 500,000 people lost power, with the state's largest utility Central Maine Power Company reporting the largest number of outages in the company's history and Emera Maine reporting the most widespread outages since 1998.

The utilities had taken some steps to prepare for the storm, describing advance planning to "ensure that adequate resources are in place to restore power outages that might occur as a result of the storm." After the storm passed, line crews from out of state arrived to provide mutual aid. Maine Governor Paul LePage issued an emergency proclamation to allow drivers of electrical line repair vehicles to operate additional hours during storm restoration efforts. By November 5 -- about one week after the storm -- the utility reported that it had restored power to about 99 percent of customers who had lost service, with about 6,000 customers left to go.

A convoy of utility repair trucks after the storm.

Now that the lights are back on in most homes and businesses, most people have cleaned spoiled food from refrigerators and freezers and are back at work. But the storm and outage have thrown a spotlight on the reliability of Maine's electricity grid, and utility preparation and response to storms. Some customers are complaining, pointing to the loss to the state economy caused by the blackouts, on top of personal inconvenience. As with past storms and outages such as the 1998 New England ice storm, preparation, operational response, and communications with customers and policymakers are focal points for complaint.

Some of the present complaints focus on the fact that what has been called the worst power outage in Maine history comes just two years after CMP completed its $1.4 billion Maine Power Reliability Program transmission upgrades. Other complaints focus on the utility's communications with customers -- while CMP's website provided real-time outage information during the storm including estimates on when service will be restored, the Portland Press Herald reported that CMP has acknowledged problems with the web listings, causing customer frustration over inaccurate information.

The Bangor Daily News cites a Maine Public Utilities Commission spokesman as saying that, following further information gathering, the regulatory agency may consider changes to regulation to better hold transmission and distribution utilities accountable for outages and storm restoration efforts. Maine law also allows the Commission to institute a complaint or investigation proceeding into any matter affecting utility service, and requires the Commission to investigate if ten or more aggrieved people file a complaint against a utility.

Canadian regulator predicts 2019 peak fossil fuels

Wednesday, November 8, 2017

Canadian energy regulators predict Canadians will likely use less fossil fuels in the future, with the baseline case suggesting Canadian fossil fuel use will peak around 2019.

Canada's National Energy Board is an independent federal regulator whose mandate is to promote safety and security, environmental protection and economic efficiency in the Canadian public interest, in the regulation of pipelines, energy development and trade. The Board prepares periodic long-term energy outlooks, which it describes as "the only publically available, long-term energy supply and demand outlook covering all energy commodities and all provinces and territories."

On October 26, 2017, the National Energy Board released its latest such report, titled "Canada's Energy Future 2017: Energy Supply and Demand Projections to 2040." The 2017 report uses economic and energy models to explore "how possible energy futures might unfold for Canadians over the long term."

The report features a baseline Reference Case, based on a current economic outlook, a moderate view of energy prices, and assuming climate and energy policies similar to those announced at the time of analysis. According to the report, this projection shows Canadian fossil fuel use peaking around 2019, and flattening out in the long term.

The report also considers two alternative scenarios -- a Higher Carbon Price case, and a Technology Case considering increased carbon pricing plus the greater adoption of select emerging production and consumption energy technologies such as electric vehicles and solar power. Under these two alternative cases, consumption of fossil fuels would fall 8 and 13% respectively, by 2040.

ISO New England's 2017 Regional System Plan

The operator of New England's electric grid has issued an updated power system plan, presenting the grid operator's view of power system needs for the next 10 years and how these needs can be addressed. ISO New England, Inc.'s 2017 Regional System Plan portrays the region's energy system as "in the midst of a major evolution toward a cleaner, hybrid grid," including both traditional resources such as natural-gas-fired generation and renewable technologies such as wind and solar, plus energy efficiency or conservation measures.

ISO New England is the independent system operator for the electric grid serving most of New England. Its tariff as approved by the Federal Energy Regulatory Commission requires it to prepare and periodically update a Regional System Plan, addressing forecasts of annual energy use and peak loads for a 10-year planning horizon, market responses that can meet defined system needs, and descriptions of regional transmission projects that meet identified needs, among other information.

On November 2, ISO New England's board of directors approved its 2017 Regional System Plan (RSP17). The 2017 plan builds on the 2015 plan, while providing updated information on system needs and resources.

Highlights of the 2017 plan include:
  • Increased adoption of solar photovoltaic and energy efficiency resources will lead to long-term declines in annual use of electric energy and summer peak demand (but load will grow slightly without more solar PV and efficiency, as was previously predicted).
  • The most recent Forward Capacity Market auction (FCA #11), held in February 2017, procured sufficient resources to meet resource adequacy criteria through 2021. These resources include about 264 MW of new generation, plus 640 MW of new demand-side resources (mostly new energy efficiency, with a little new wind and solar).
  • The region's portfolio of generating resources is changing. About 4,800 megawatts of generation will be retired from 2010 to summer 2020. Older oil- and coal-fired and nuclear generators are most at risk of retirement due to economic and environmental pressures. Natural-gas-fired and renewable generation like wind and solar are the most likely replacements.
  • While the region should have sufficient resources to meet capacity requirements and adequate trans mission facilities to meet reliability criteria, ISO New England says "fuel security remains a primary issue the region must resolve to meet its energy-supply needs. " It cites limited availability of the natural gas transportation infrastructure to supply gas to generating units, and notes the grid operator's ongoing operational fuel-security analysis to quantify the region’s risk.
  • Transmission investment (and related costs) continue to grow. From 2002 through June 2017, 730 reliability-oriented transmission projects were put into service in New England states at a cost of $8.4 billion. As of June 2017, another $4 billion in transmission investment for reliability wa s planned. While ISO-NE predicts the overall need for major transmission projects for reliability to decline over the 10-year planning horizon, it says integrating large-scale renewable energy resources is a potential driver for future transmission investments.
The report also discusses efforts to coordinate New England's planning process with other neighboring regions.

Stanford publishes clean energy finance papers

Tuesday, November 7, 2017

Stanford University's Precourt Institute for Energy has launched a Clean Energy Finance Initiative with a forum and the release of a series of papers addressing the challenge and opportunity of dramatically increasing global investment in clean energy deployment.

A framing paper, Derisking Decarbonization: Making Green Energy Investments Blue Chip, presents an investor's view of the risks that could deter significant increases in clean energy investment. It considers the investment required to meet the International Energy Agency's "450 Scenario" aimed at limiting global warming below 2 degrees Centigrade. IEA forecasts that investment in clean energy, must average $2.3 trillion per year through 2040, an annual spending rate roughly three times higher than the rate during the period 2010-2015.

The Stanford framing paper considers a broad range of clean energy technologies, including energy efficiency, renewables, nuclear power, carbon capture and storage (CCS), natural gas, cogeneration, and key enabling technologies including transmission, storage, and demand response. In addition to the practical challenges involved in tripling clean energy investment rates, the paper identifies challenges including the size of clean energy demand relative to annual new investible capital, a mismatch between institutional investor risk profiles and the currently high-risk nature of most clean energy projects, and a locational mismatch between sources of capital and global need for clean energy.

The paper concludes that since most sources of capital will not significantly lower their investment standards for climate reasons, the quality of the green investments offered must be improved: "Green energy projects must become blue chip investments, if we are going to successfully confront climate change." It then analyzes specific issues of investment risk and potential solutions, including market risk, policy risk, project development risk, and investment framework risk.

Eight additional "solutions papers" address specific aspects of investment risk. Some evaluate opportunities to enable more efficient clean energy finance in China or to mitigate financial risk in Indian renewable energy investments. Another examines the implications to investors and to politicians of carbon dividends.

FERC report on energy independence executive order

Monday, November 6, 2017

U.S. energy regulators have issued a final report describing actions taken by the Federal Energy Regulatory Commission pursuant to an executive order promoting energy independence and economic growth.

On March 28, 2017, President Trump signed Executive Order 13783, titled Promoting Energy Independence and Economic Growth. Executive Order 13783 includes a variety of directives, generally aimed at reducing federal regulations affecting domestic energy production. Among these mandates is a requirement that all federal agency heads "review all existing regulations, orders, guidance documents, policies, and any other similar agency actions (collectively, agency actions) that potentially burden the development or use of domestically produced energy resources, with particular attention to oil, natural gas, coal, and nuclear energy resources."

On October 31, 2017, the Commission released its final report presenting a review of its actions pursuant to Executive Order 13783. In that report, the Commission identified nine "agency actions that potentially materially burden the development or use of domestic energy resources." The Commission considers agency actions that potentially affect not only oil, natural gas, coal, and nuclear energy resources, but also hydropower and other renewable generation resources.

Of the nine agency actions identified by the Commission as potentially materially burdening the development or use of domestic energy resources, eight relate to the Commission's regulation of hydropower resources. The Commission's final report identified three broad areas where potential material burdens may exist: licensing processes; exemption processes; and determinations on deficient applications. A ninth relates to liquefied natural gas (LNG) proceedings.

The report also describes the Commission's examination of policies regarding centralized electric capacity markets and generator interconnections, and its decision not to identify any potential material burdens regarding these items.

Maine ruling on biomass for renewable energy

Friday, November 3, 2017

Maine renewable energy regulators have issued a ruling clarifying that biomass generators fueled by a "dewatered cellulose pulp" developed by a municipal solid waste recovery company may qualify under the state's renewable portfolio standard. The ruling could help support a municipal waste management company if it creates a market for the company's residual material.

Maine statutes and Maine Public Utilities Commission regulations establish a renewable portfolio standard, or RPS, which currently requires that at least ten percent of the power electricity suppliers sell must come from “new renewable capacity resources” (Class I facilities) and another thirty percent from resources that are renewable or efficient (Class II facilities). The lists of renewable resources eligible for each class are generally similar, although Class I facilities must also be “new" (built, refurbished, etc. after September 1, 2005).

Biomass generators that are fueled by wood, wood waste or landfill gas are eligible for Class I certification or Class II certification depending on their vintage date.  Class II certification is also specifically available for anaerobic digestion of agricultural products, by-products or wastes.

In its role as regulator of the renewable portfolio standard, the Public Utilities Commission has had occasion to consider exactly what counts as "biomass," "wood," or "wood waste." In an order adopting amendments to its renewable portfolio standard rule in 2007, the Commission concluded that, “without further legislative direction and in light of the unqualified statutory term ‘biomass,’ the Commission would adopt a relatively broad definition that includes all fuel derived from wood and wood byproducts (along with other organic sources).” In subsequent orders certifying individual facilities as Class I eligible, the Commission has repeatedly reaffirmed this broad interpretation of biomass and has applied it to such fuels as black liquor, biofuel, and pulp and paper fiber sludge.

On September 14, 2017, a company called Fiberight LLC submitted a request to the Commission for an advisory ruling seeking clarification as to whether dewatered cellulose pulp qualifies as an eligible resource pursuant to Maine RPS law. The company's website describes its "Targeted Fuel Extraction (TFE) process to cost effectively and efficiently convert municipal solid waste (MSW) into cellulosic biofuel, plant energy and marketable electricity.... Once renewable fuel production is complete a digestate fiber is available for compost production or can be pelletized for energy recovery." According to its application, Fiberight intends to sell this product to “compliant RPS facilities” and seeks confirmation that the cellulose pulp is consistent with the Commission’s broad definition of biomass.

On October 25, 2017, the Commission issued an order clarifying "that the dewatered cellulose pulp produced by Fiberbright is biomass."  The order cites the Commission's consistent employment of "a broad definition of biomass, particularly for organically-derived material," including pulp products. Accordingly, the Commission held that the dewatered cellulose pulp identified by Fiberight is a biomass fuel that Class I or Class II facilities may use to produce Maine RPS eligible electricity.

NH PUC considers efficiency plan

Thursday, November 2, 2017

New Hampshire utility regulators are considering a three-year statewide energy efficiency plan proposed by several electric and gas utilities. The case could shape the near-term future of New Hampshire energy efficiency programming.

Under a 2016 settlement agreement, the New Hampshire Public Utilities Commission approved the implementation of an Energy Efficiency Resource Standard (EERS) beginning 2018, subject to Commission approval of the specific programs proposed to meet this standard. On September 1, 2017, utilities Liberty Utilities, Public Service Company of New Hampshire, Unitil Energy Systems, Inc. and Northern Utilities, Inc. jointly proposed a 2018-2020 Statewide Energy Efficiency Plan for approval by the Commission. The proposed 2018-2020 New Hampshire Statewide Energy Efficiency Plan document spans 369 pages, and is supported by testimony filed by the utilities.

As described by the utilities, their proposals would extend and expand existing "NHSaves" programs for another 3 years, and would add new initiatives including "a new residential energy audit option, a financing option for moderate income residents, new measure offerings in both residential and commercial programs, and multi -year energy planning to encourage long-term energy savings projects among large commercial customers."

According to the utilities, the measures implemented through the 2018-2020 Plan will save more than 4 billion electric kilowatt-hours and 7.5 million natural gas MMBtu, plus another 5.4 million MMBtus from other fuels, yielding customer energy cost savings of more than $867 million in energy costs over the life of the measures. The utilities also project that the measures "will reduce peak demand by 39 MW, which in tum will reduce costs for all customers."

The Commission has docketed the proceeding as Docket No. DE 17-136, and set a procedural schedule for the case including the filing of testimony and pursuit of possible settlement through November 2017, with hearings on the merits in early December.

US announces Gulf oil and gas lease sale

Wednesday, November 1, 2017

The U.S. Department of the Interior has announced plans to auction off the rights to the largest oil and gas lease sale ever held in the United States, covering 76,967,935 acres in federal waters of the Gulf of Mexico, offshore Texas, Louisiana, Mississippi, Alabama and Florida. The Bureau of Ocean Energy Management's Proposed Lease Sale 250 would be the second offshore sale under the National Outer Continental Shelf Oil and Gas Leasing Program for 2017-2022.

On October 23, Secretary Ryan Zinke announced the proposed region-wide lease sale, offering an area about the size of New Mexico which includes all available unleased areas on the Gulf’s Outer Continental Shelf. According to his announcement, the auction will be held on March 2018.  It will cover 14,375 unleased blocks, located from 3 to 230 miles offshore, in water depths ranging from 9 to more than 11,115 feet. The Trump administration stated that it estimates the amount of resources projected to be developed as a result of the proposed region-wide lease sale ranges from 0.21 to 1.12 billion barrels of oil and from 0.55 to 4.42 trillion cubic feet of gas.

According to the Bureau of Ocean Energy Management, the U.S. Outer Continental Shelf contains about 90 billion barrels of undiscovered technically recoverable oil and 327 trillion cubic feet of undiscovered technically recoverable gas; of this, BOEM estimates that the Gulf of Mexico is home to roughly half of these amounts.

Ontario long-term energy plan 2017 targets market renewal

Tuesday, October 31, 2017

The Canadian province of Ontario has released an updated long-term energy plan. The report, Delivering Fairness and Choice: Ontario's Long-Term Energy Plan 2017, notes the province's recent energy policy successes, and suggests that market restructuring underway by the grid operator could save ratepayers up to $5.2 billion CAD over a 10-year period.

Ontario first published a Long-Term Energy Plan in 2010, and updated the plan in 2013. The 2017 plan includes a recognition of recent investment the province has made in the province's electricity system -- nearly $70 billion since 2003. Investment focuses included reliability improvements, the elimination of coal-fired generation, and the addition of clean generation, yielding an electricity system that the province describes as more than 90 per cent free of greenhouse gas emissions.

The 2017 plan also notes that the province's Independent Electricity System Operator (IESO) has launched a "Market Renewal" program to restructure Ontario's electricity markets. Under Market Renewal, IESO plans to make a series of market changes to enable the province to more efficiently meet demand over the near and longer terms, including introducing a day-ahead market, enhancing real-time unit commitment, improving intertie scheduling, and implementing an incremental capacity auction.

According to the plan, the Market Renewal program forms a key component of the government’s plan to bring down the cost of electricity, and could save up to $5.2 billion between 2021 and 2030. Other overarching themes in Ontario's 2017 long-term energy plan include ensuring affordable and accessible energy, ensuring a flexible energy system, innovating to meet the future, improving value and performance for consumers, strengthening the province's commitment to energy conservation and efficiency, responding to the challenge of climate change, supporting First Nation and Metis capacity and leadership, and supporting regional solutions and infrastructure.

FERC Winter 2017-18 Energy Market Assessment

Monday, October 30, 2017

A recent report by U.S. energy regulators notes that newly built natural gas-fired and renewable power plants are replacing retiring coal and nuclear power plants, which can require grid operators to take extra steps to ensure electric system reliability.

On October 19, 2017, enforcement staff of the Federal Energy Regulatory Commission delivered their Winter 2017-18 Energy Market Assessment.  According to that report, recent years have seen natural gas-fired plant additions in several parts of the country, replacing retirements of coal and nuclear capacity.  Meanwhile, most recent capacity additions have been natural gas-fired or renewable.

FERC enforcement staff also noted that these changes to the portfolio of generating resources making up the capacity mix can affect fuel diversity and system reliability.