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Omaha Public Power District announces sites for two new gas generators

October 6, 2020

by Peter Maloney
APPA News
October 6, 2020

The Omaha Public Power District (OPPD) has taken its next step in adding 600 megawatts (MW) of gas-fired generation in support of up to 600 MW of solar power that it plans to add to its fleet.

At the September meeting of its board of directors, the Nebraska public power utility announced the location of two sites for the gas-fired generators, one in Douglas County, the other in Sarpy County.

The gas generators will be used to back up between 400 MW and 600 MW of utility-scale solar generation and are part of OPPD’s Power with Purpose project. The utility’s board in November approved OPPD’s proposal to negotiate and enter into procurement contracts for the proposed gas plants.

OPPD also said the Power with Purpose project honors its commitment to keep rates steady for customers with no general rate increase for a fourth consecutive year.

Locations for the solar components of the Power with Purpose project have not yet been announced because sourcing for solar portions of the project are still under way.

The Power with Purpose project is part of OPPD’s broader aim of achieving net-zero carbon dioxide production by 2050. OPPD initiated a Pathways to Decarbonization study to identify and prioritize strategies to reach that goal.

OPPD also said its Power with Purpose project will allow it to retire coal-fired units at its North Omaha Station, which would enable an 80% to 90% reduction in carbon dioxide emissions at the plant.

“This is OPPD’s first step into our decarbonization efforts to be net zero carbon by 2050, and the organization is fully committed to the new future,” Tim Burke, the utility’s president and CEO, said in a statement. The new gas-fired plants will help OPPD make up for the retired coal units and maintain reliability on its system, he said.

“These natural gas facilities are needed as backup, in order to maintain a reliable and resilient system,” Mary Fisher, vice president of energy production and nuclear decommissioning, said at the board meeting. “The historic flooding we saw in March of last year demonstrates how important resilience is for the future.”

The new gas generators will be used to back up the solar component of the Power with Purpose project. OPPD estimates they would operate about 10% to 15% of the time. The utility also highlighted the benefits of modern gas turbine technology, namely, the ability to ramp up quickly to provide energy when needed and the ability to produce fewer harmful emissions than older gas turbines.

California offshore wind could help flatten duck curve, study finds

September 10, 2020

by Peter Maloney
APPA News
September 10, 2020

Offshore wind resources along the central California Coast are well suited to meet demand when it is most needed, according to a new study by researchers at California Polytechnic State University in San Luis Obispo.

California leads the nation in solar power with over 28 gigawatts (GW), but as the sun sets, consumer demand rises, creating a sudden need for other forms of energy to meet daily peak needs, a phenomena that has come to be known as the “duck curve.”

“The alignment between potential offshore wind power production and demand highlights the important role that offshore wind energy could play in meeting California’s ambitious renewable energy goals,” Yi-Hui Wang, the research scientist who led the Cal Poly team, said in a statement.

Instead of taking a conventional approach to identifying areas with promising wind resources by using mean wind speeds, the researchers said they compared the diurnal and seasonal patterns of offshore wind power production to diurnal and seasonal patterns of power demand across California and to power production from other renewable resources, such as solar and land-based wind power.

They then used the relative alignment between the power production of the various renewables and demand to calculate a demand-based value and, looking at the daily and seasonal fluctuations in recent wholesale power prices, they generated an estimate of the wholesale dollar value of power produced.

Solar power generation in California peaks in June at noon while the peak in the value of power demand occurs in July and August at about 4:00 pm, the researchers noted, adding that land-based wind power generation peaks in June at midnight while the value of power demand peaks in August at about 10:00 pm.

Offshore wind power generation, on the other hand, aligns well with daily peak demand, which occurs between 7:00 pm and 8:00 pm, depending on the month, the researchers said.

Regarding the wholesale value of offshore wind, the researchers report that due to strong variations in pricing, these values show more extreme daily and seasonal changes than power production. The wholesale value of power is close to zero on a typical spring noon because of the solar overgeneration and peaks during evening hours when solar generation is low and demand is high.

“The framework by which we assess spatial and temporal patterns in offshore wind energy production and its value can be applied to other regions where offshore wind is being considered,” the researchers wrote.

The federal Bureau of Ocean Energy Management, which funded the study, is considering California’s central coast region for the location of the state’s first offshore wind farm and has proposed priority areas for leasing by energy companies.

“Looking at this wind data in relation to maps of fisheries, whale and seabird activity will help identify locations where offshore wind farms could add the most value and yet have the least impact on local economies and marine wildlife,” biology professor Crow White, a member of the Cal Poly research team, said in a statement.

The researchers noted that the greatest wind speeds, which would produce the most energy, are found farther from the coast. And while most existing offshore wind farms are installed close to shore in waters less than 160 feet deep, floating wind farms in deeper waters have begun operation in Europe.

“Floating offshore wind farms are now a proven technology and game-changer in many respects,” physics professor and team member Ryan Walter said in a statement.

The Cal Poly study did not include a full economic analysis because of a lack of data on the costs of building and operating offshore wind farms and the losses associated with transmitting the power back to shore.

“Ultimately, we hope this information and our ongoing work will inform the conversation, helping the policymakers and citizens of California decide if, how and where to prioritize renewable offshore wind energy,” biology professor and team member Ben Ruttenberg, said in a statement.

As a next step, the Cal Poly team is looking at a study that would estimate the total amount of electricity wind farms in the area could produce and how those wind farms might affect the broader economy of San Luis Obispo County.

The study is available here.

Redwood Coast Energy Authority taps consortium for offshore wind partnership

The Redwood Coast Energy Authority, a California local government Joint Powers Agency, in 2018 selected a consortium of companies to enter into a public-private partnership to pursue the development of an offshore wind energy project off the Northern California coast.

In 2019, Monterey Bay Community Power, a California community choice aggregator, and Castle Wind LLC said that they signed a memorandum of understanding that outlines the mutual interests and intent of both parties to enter into future long-term power purchase agreements for approximately 1,000 megawatts of energy from an offshore wind project being developed by Castle Wind.

Gas-fired generation hit a record on July 27, EIA says

September 3, 2020

by Paul Ciampoli
APPA News Director
September 3, 2020

Natural gas-fired generation in the lower 48 states hit an all-time high of 316 gigawatts (GW) on July 27, according to data from the Energy Information Administration (EIA).

The EIA noted that the record coincided with a record level of natural gas consumed by generating plants, so-called gas burn, set on the same day as reported by S&P Global Platts.

Platts estimates put gas burn at 47.2 billion cubic feet (Bcf). The previous record, 45.4 Bcf, was set on Aug. 6, 2019. In addition to beating the previous record, gas-burn exceeded 45.4 Bcf per day on seven days in July 2020 and one day in August.

The record level of gas-fired generation is the result of a combination of factors, namely, high demand in response to searing summer temperatures, relatively low natural gas prices, the start-up of new gas-fired capacity and increased natural gas consumption in the power sector, EIA said.

The use of natural gas for power generation has been rising for years. Earlier this month, the EIA noted that gas-fired generation in the lower 48 states increased nearly 55,000 gigawatt hours (GWh), or 9%, in the first half of 2020 compared with the first half of 2019 despite a 5% decline in total electricity generation as a result of COVID-19 mitigation efforts.

The increased use of gas-fired generation is fueled by persistently low gas prices. The EIA noted that natural gas prices at the benchmark Henry Hub in Louisiana averaged $1.73 per million British thermal units (MMBtu) for gas delivered on July 27. And, from June 1 to July 30, Henry Hub prices averaged $1.64/MMBtu, 30% lower than the prices during the same period in 2019. Adjusted for inflation, the average price is the lowest for that period since at least 1993, the EIA said, citing data from Natural Gas Intelligence.

Of the electricity generated on July 27 in the lower 48 states, natural gas held the largest share at 45%, followed by coal with a 24% share, nuclear power had a 17% share, renewable energy a 12% share, and other sources a 3% share, the EIA noted.

Low gas prices are also prompting utilities and developers to convert coal-fired plants to burn gas. A total of 121 coal plants were repurposed to burn other types of fuels between 2011 and 2019. Most of those plants, 103, were converted to burn natural gas or replaced by a gas-fired plant.

Natural gas is also the leading fuel for new fossil fuel generation. Between January 2019 and May 2020, the United States added 13.8 GW of gas-fired capacity and retired 5.4 GW for a net gain of 8.4 GW, making gas-fired generation second only to the 12.6 GW of onshore wind power built in the same period, according to EIA’s Preliminary Monthly Electric Generator Inventory.

Most of the new gas-fired capacity is in the form of combined-cycle plants that use the latest technology to achieve high efficiency ratings, the EIA said, adding that the retired gas plants were less efficient steam plants or combustion turbines.

MRES celebrates beginning of generation at the Red Rock Hydroelectric Project

September 2, 2020

by Paul Ciampoli
APPA News Director
September 2, 2020

Missouri River Energy Services (MRES) on Sept. 2 marked the beginning of hydropower generation at the Red Rock Hydroelectric Project (RRHP) in Iowa with a video dedication ceremony.

Built on the Lake Red Rock dam near Pella, Iowa, RRHP will create a new purpose for an existing Army Corps of Engineers facility completed in 1969, MRES said. MRES, a joint action agency, broke ground on the project almost exactly six years ago.

Now Iowa’s second-largest hydropower generator, the retrofitted dam will harness the power of the Des Moines River to produce electricity for thousands of homes in MRES member communities across Iowa, Minnesota, North Dakota and South Dakota.

RRHP is expected to produce more than 36 megawatts of electricity, and 55 MW during summer months when water levels are typically highest. Financing for the project was provided by MRES’s partner, Western Minnesota Municipal Power Agency.

“RRHP serves as a model for public-private partnerships to retrofit some of the estimated 80,000 dams in the U.S. that do not produce power,” MRES said in a news release. The project was included in the federal Infrastructure Permitting Dashboard, which was designed to speed the development of critical infrastructure projects across the U.S.

“The Red Rock plant will run 24-7,” said Tom Heller, president and CEO of MRES. “It is not intermittent like wind or solar power.”

The project “will also give us another generating resource in our ongoing effort to diversify our renewable portfolio,” Heller said in the video dedication ceremony.

“What an amazing achievement to get this done,” said Joy Ditto, President and CEO of the American Public Power Association, in the video dedication ceremony. She noted that the project will provide renewable, affordable and reliable hydropower.

Ditto said that Heller was an “incredible leader to help get this done.” (Heller received the Mark Crisson Leadership and Managerial Excellence Award during APPA’s Public Power Connect: Virtual Summit & Business Meeting earlier this year).

The communities that MRES serves “were instrumental in ensuring that this project could come to fruition,” she went on to say.

“Working with their locally elected officials who manage their utilities, understanding what their community needs were going to be now and into the future, demonstrates the value of public power and the way that we can come together and ensure that our communities’ needs are being met through our electric utilities.”

The project is an example of how public power utilities listen to their communities, Ditto said.

As public power pursues innovative initiatives like electric vehicles, community solar and energy storage “we’re going to be working with our communities and our community leaders in understanding how we need to achieve those innovative activities,” she said.

Other speakers participating in the video dedication ceremony were:

To view the video dedication ceremony, click here.

How PREPA brought earthquake-damaged plant online ahead of Isaias

August 24, 2020

by Peter Maloney
APPA News
August 24, 2020

In January, it looked like one of Puerto Rico’s biggest power plants would be out of commission for a year. Instead, one unit of the damaged plant was able to start generating power just days before Tropical Storm Isaias hit the island.

The speedy restoration of the Costa Sur plant is “by far the biggest success PREPA (Puerto Rico Electricity Power Authority) has ever had,” Todd Filsinger, senior managing director at Filsinger Energy and chief financial advisor to PREPA, said.

The two-unit, 820-megawatt (MW) Costa Sur plant, PREPA’s largest, was knocked out of service on Jan. 7 by a 6.4 magnitude earthquake that cracked foundations, ruptured pipes, split water tanks, and damaged a turbine and the plant’s control room.

Costa Sur provides about one quarter of PREPA electrical supplies and is one of the public power utility’s most efficient plants. Without it, PREPA was forced to use its more expensive diesel peaking plants and to rely more heavily on purchased power from third party generators such as EcoElectrica and a coal-fired plant owned by AES Corp.

Before actual repair work on Costa Sur could begin, however, a lot of negotiations and financial arrangements had to be made, all of which were complicated by Puerto Rico’s financial troubles – the island, and then PREPA, entered into a bankruptcy like process in 2017 – and in that same year was devastated by two hurricanes, Irma and Maria.

Soon after the earthquake in January, there were discussions with the Federal Emergency Management Agency (FEMA) for temporary generators, but that solution was thwarted by technicalities.

Meanwhile, plans to repair Costa Sur had to be approved by regulators, including the Puerto Rico Energy Bureau and the Financial Oversight and Management Board.

As part of the bankruptcy process, PREPA created a project management office (PMO) that reports directly to the head of the utility. The discipline, experience and focus of the PMO were key to the rapid restoration of Costa Sur, Filsinger said.

As the groundwork for the restoration efforts for Costa Sur began, it became apparent there were opportunities to negotiate a better deal in the form of lower prices and tighter schedules, Fernando Padilla, director of PREPA’s project management office, said.

When negotiations were completed and financing was in place – over 80% of the $40.2 million total cost is being covered by PREPA’s insurance – the actual physical work of restoration began in May.

The work was undertaken by a team of about 360 contractors and PREPA employees, many of them union workers, who worked in 24-hour shifts. PREPA was able to begin ramping up the 410-MW Unit #5 at Costa Sur within 24 hours of Isaias hitting Puerto Rico. Unit #5 is now fully operational, and Unit #6 is expected to be online by late October.

Among the key lessons learned from the restoration efforts, Padilla says, is to stay in close contact with the workers. He walked the power plant’s floor four times a day. “If you are not close to the people,” it is difficult for them to understand the scope and progress of their efforts. “It is hard to translate that from a piece of paper.”

“It is about having first eyes and hands on the problems to seek immediate solutions,” Padilla said. “Being there allows you to understand problems, employee needs, project risks, and to address contractors’ and employees’ problems and even creates opportunities to make work more efficient and quicker,” Padilla said. A daily management presence “also provides employees with the comfort that our executive team is fully committed” to bringing the plant back online quickly and motivates employees and signals urgency to contractors, he added.

The other lesson is the benefit of using a mix of contractors and public power union employees. “PREPA’s union expertise was indispensable due to their knowledge of the asset and its operation,” and union labor was lower cost compared with contractors of the same level of expertise, said Padilla.

Looking to the future, Padilla and his PMO team are working on other projects that will enable PREPA to be prepared for other disasters that befall Puerto Rico. Among them, vegetation management projects on 600 miles of the island’s electrical wires and a future that includes more decentralized power resources.

More generation came from natural gas in first half of 2020 versus a year ago

August 18, 2020

by Peter Maloney
APPA News
August 18, 2020

Driven by low prices, the rapid growth of natural gas as a fuel for power generation continued through the first half of the year.

Natural gas-fired generation in the lower 48 states increased nearly 55,000 gigawatt hours (GWh), or 9%, in the first half of 2020 compared with the first half of 2019, the Energy Information Administration recently reported.

The gains by natural gas came even as total electricity generation declined by 5% because of reduced business activity as a result of COVID-19 mitigation efforts.

Coal-fired generation absorbed most of the decrease in electrical load in the first half of 2020, registering a 138,000 GWh (30%) decline in output. Because of historically low natural gas prices so far in 2020, coal-fired generation this year has been uneconomical in most regions compared with natural gas-fired generation, leading to price-driven coal-to-natural gas fuel switching, EIA pointed out.

In the first half of 2020, natural gas prices at the U.S. Henry Hub benchmark reached record lows. The average monthly Henry Hub spot price in the first six months of the year was $1.81 per million British thermal units (MMBtu) compared with an average of $2.74/MMBtu in the first half of 2019. And monthly prices reached a low of $1.63/MMBtu in June, the lowest monthly inflation-adjusted price since at least 1989, EIA noted.

Coal prices, on the other hand, were relatively stable in the first half of 2020. The average delivered cost of coal was $1.91/MMBtu this year through May compared with an average delivered cost of $2.07/MMBtu at the same time last year.

Low gas prices relative to coal prices often results in fuel switching in competitive wholesale power markets where cheaper fuel often determines which power plant is dispatched.

Coal-to-natural gas switching was most prominent in the PJM Interconnection and the Midcontinent Independent System Operator (MISO), which together account for about 35% of the total electric power generation in the Lower 48 states, EIA said.

At the end of June, local spot gas prices at hubs in PJM and MISO were at $1.58/MMBtu and $1.66/MMBtu, respectively, down nearly 50¢/MMBtu each from last year, EIA said.

Gas-fired generation increased by about 17,000 GWh in PJM and by 15,000 GWh in MISO in the first half of 2020, while coal-fired generation declined about 34,000 GWh in PJM and 40,000 GWh in MISO.

The Electric Reliability Council of Texas (ERCOT) region was the exception to that trend. Coal-fired generation in ERCOT declined 8,650 GWh in the first half of 2020 compared with the first half of 2019, but gas-fired generation also declined slightly. Most of the decline in coal-fired generation in ERCOT was offset by increases in wind and solar generation, which together increased about 8,400 GWh in the first half of 2020, EIA noted.

Coal-fired generation remains reasonably competitive in ERCOT, EIA said, because power plants there have access to low-cost subbituminous coal from Wyoming’s Powder River Basin and to lignite produced at mines near several plants.

Natural gas has also become the favored fuel for new power plants. About 18,000 MW of combined-cycle natural gas turbine plants have entered service since 2018, according to the EIA’s Electric Power Monthly. During the same 30-month period – January 2018 through June 2020 – about 31,000 MW of coal-fired capacity retired along with about 2,400 MW of nuclear power capacity.

Many coal-fired plants are also being repurposed to burn other types of fuels. A total of 121 coal plants were repurposed between 2011 and 2019, most of them to burn natural gas, the EIA reported earlier this month.

The EIA also noted, however, that gas-fired generation is facing increased competition from solar and wind capacity. Since 2018, about 23,200 MW of new net solar and wind capacity has been added. Renewable energy, consisting of wind, solar, and hydroelectric generation, has increased by about 5% and has been the only other fuel source other than natural gas to grow in the first half of 2020, the EIA said.

MEAG Power, JEA, And Jacksonville Unveil Settlement of Litigation Tied to Vogtle PPA

July 31, 2020

By Paul Ciampoli
APPA News Director
Posted July 31, 2020

Florida public power utility JEA, the City of Jacksonville and the Municipal Electric Authority of Georgia (MEAG Power) on July 30 announced a settlement of all disputed issues relating to the new Units 3 and 4 of the Alvin W. Vogtle Electric Generating Plant, a nuclear power generating facility in Georgia, and an amended and restated power purchase agreement.

The JEA board, the City of Jacksonville and the MEAG Power Board approved the settlement.

Terms of the settlement include JEA and the City of Jacksonville dismissing their civil action against MEAG Power currently pending in U.S. District Court, and MEAG Power dismissing its lawsuits against JEA currently pending in U.S. District Court and the U.S. Court of Appeals.

Also, JEA, the City of Jacksonville and MEAG Power agree to accept without challenge or appeal a June 17 order entered by U.S. District Judge Mark Cohen, including without limitation his determination that the JEA PPA is valid and enforceable. Terms also include certain provisions that will create additional future value to both JEA and MEAG Power, JEA and MEAG Power said in a news release.

In his June 17 ruling, Cohen said that a power purchase agreement between JEA and MEAG Power tied to the expansion project at Plant Vogtle was valid and enforceable.

Under the terms of the PPA, which was signed in 2008, and amended and restated in 2014, JEA committed to purchase all of the energy generated by the new units 3 and 4 of the Vogtle plant, as part of “Project J,” during their first 20 years of operation, as well as to pay for approximately 41 percent of MEAG Power’s share of the construction cost for the new units during those 20 years.

JEA and the City of Jacksonville, Fla., in 2018 filed a complaint in Florida state court for declaratory judgment regarding the PPA. The complaint was filed in the Fourth Judicial Circuit Court of Florida on the same day that MEAG Power filed a breach of contract lawsuit against JEA.

Plant Vogtle Units 3 and 4 are two 1,100-megawatt Westinghouse AP1000 nuclear reactors being constructed in Burke County, Ga.

MEAG Power’s co-owners in the Vogtle expansion project are Georgia Power (45.7 percent), Oglethorpe Power (30.0 percent) and Dalton Utilities (1.6 percent).

MEAG Power provides wholesale electricity to 49 member communities in Georgia, who own their local distribution systems. JEA, which is located in Jacksonville, Fla., serves an estimated 478,000 electric, 357,000 water, 279,000 sewer customers and 15,000 reclaimed water customers.

Kentucky Municipal Energy Agency Issues RFP For Intermediate Capacity And Energy

July 30, 2020

by Paul Ciampoli
APPA News Director
Posted July 30, 2020

The Kentucky Municipal Energy Agency (KYMEA) is seeking proposals to supply intermediate electric capacity and energy to it starting June 1, 2022 for terms of three to 20 years.

KYMEA on July 24 said that it prefers to purchase capacity and energy from resources delivered by a seller to MISO Zone 6, the LGE/KU transmission system or a distribution system of one of KYMEA’s members.

KYMEA, an inter-local agency which provides electric power and related services to municipal utilities, anticipates considering purchases ranging from 30 megawatts to 60 MW.

This invitation and all proposals are subject to the provisions of KYMEA’s request for proposals (RFP), which provides specifications for the solicitation.

The RFP specifically provides that prospective proposers must contact only Rob Leesman at KYMEA to obtain information about this solicitation, KYMEA noted.

Contacts by prospective proposers with KYMEA Board members and other representatives of KYMEA or its members will be a cause for disqualification of proposals as further explained in the RFP.

The RFP requires submittal of a proposal responsive to the solicitation and containing data at a level sufficient for KYMEA to screen alternatives to determine if the proposal is reasonably susceptible of being accepted for award based upon the evaluation factors set out in the RFP.

Potential proposers may request a copy of the RFP by emailing KYMEA at: rleesman@kymea.org.

Those requesting the RFP are asked to provide the organization’s legal name and address and a primary contact name, email address and phone number.

Proposals must be received by email no later than 2 pm EDT on August 19, 2020.

COVID-19 Has Minimal Effect On Power Plant Startups, EIA Says

July 20, 2020

by Peter Maloney
APPA News
Posted July 20, 2020

Efforts to mitigate the spread the COVID-19 have delayed the start dates of proposed power plants slightly more than average, according to the Energy Information Administration’s (EIA) March and April preliminary monthly electric generator inventory data.

About 20% of the power projects due online within 12 months in 2018 and 2019 experienced some delays. In March and April, 21% and 29% of projects, respectively, experienced delays, some of which were attributed to efforts to prevent the spread of COVID-19, the EIA reported.

The minimal increase in delays suggests that COVID-19 mitigation efforts “may have been a contributing factor” in some project delays reported in March and April, but not the only factor involved, EIA said. “The majority of projects in development are still on schedule,” the authors said.

Generating projects that expect to begin commercial operation within 12 months report their status to the EIA. If a project is delayed, project developers must provide the EIA with a cause for the delay.

In an effort to better understand the impact of COVID-19 mitigation efforts, such as state-mandated stay-at-home orders and business shutdowns, the EIA emphasized an existing survey question that allowed respondents to specify whether or not project delays were attributable to COVID-19.

In March 2020, 163 of the 772 proposed power projects reported delays in their startup dates, with 41 citing COVID-19 for the delay. In April, 746 power projects reported they expected to begin operation within 12 months. Of those, 220 reported delays and 67 cited COVID-19 as a reason.

The COVID-19 related delays reported in March and April represent 3.1 gigawatts (GW), or 18% of total delayed capacity. The median delay reported was two months, regardless of whether or not COVID-19 was cited as the cause of delay.

The EIA data showed that projects in construction were more likely to be delayed as a result of COVID-19 than projects in earlier stages of development. Sixty-one projects, totaling 2.4 GW, that were under construction in March and April were delayed as a result of the COVID-19.

Even though construction workers are considered essential, building a power project requires scheduling of simultaneous and dependent activities that involve numerous components, equipment, and specialized workers, EIA noted. The impacts of COVID-19 mitigation efforts, including supply chain disruptions, permitting delays, and restricted travel of specialized workers, affected project scheduling and increased the risk of project delays, the EIA report said.

COVID-19 related delays aside, most of the delays reported in March were for project in construction while most of the delays reported in April were for projects in the permitting process.

Among technology types, solar photovoltaic projects were most affected by COVID-19 restrictions.

In March and April, 53 solar projects, totaling 1.3 GW, were delayed as a result of COVID-19. Wind power projects were the second most affected by COVID-19, with 1.2 GW of wind projects citing the pandemic’s mitigation factors as a cause for delays.

Appeals Court Rules On FERC’s Use of “Tolling Orders” To Delay Acting On Rehearing Requests

July 15, 2020

by Paul Ciampoli
APPA News Director
Posted July 15, 2020

The U.S. Court of Appeals for the District of Columbia Circuit recently issued a ruling that addresses the Federal Energy Regulatory Commission’s use of “tolling orders” to delay ruling on rehearing requests under the Natural Gas Act (NGA).

The case, Allegheny Defense Project v. FERC, involved several consolidated appeals challenging a FERC order that issued a certificate of public convenience and necessity for a gas pipeline expansion project under section 7 of the NGA.

The parties challenging the pipeline project (including several landowners located in the proposed route) requested rehearing of FERC’s initial certificate order, which is a prerequisite for appealing a FERC order under the NGA.

The NGA requires FERC to act upon rehearing requests within 30 days, or they are deemed denied, at which point a party can appeal the challenged order.

For a long time, FERC has almost universally issued tolling orders that “grant” rehearing for the limited purpose of giving FERC more time to consider rehearing requests.

The Commission issued a tolling order in the Allegheny Defense Project v. FERC case, deferring consideration of the rehearing requests filed by parties objecting to the pipeline project.

A pipeline company that receives a certificate under NGA section 7 is given eminent domain authority for the approved pipeline route. Because filing of a request for rehearing does not stay the effectiveness of a FERC order, pipelines can move forward with eminent domain proceedings while opponents’ rehearing requests — and their right to appeal — remain subject to further FERC action, delayed by the issuance of a tolling order.

Also, FERC has frequently even allowed pipeline construction to begin while rehearing requests of a certificate order remain pending, as was the case in this proceeding.

FERC recently modified its rules to prohibit pipeline construction activities until it rules on the merits of any rehearing request.

Seeking to bypass the usual FERC process, a number of parties challenging the pipeline project filed an appeal soon after FERC issued its tolling order in this proceeding, arguing that FERC did not have authority to extend the 30-day deadline to act on rehearing through a tolling order, and, thus, FERC’s approval of the pipeline expansion project could be appealed without waiting for further FERC action on the rehearing requests.

Although the challengers also filed appeals once FERC denied their rehearing requests nine months later, the tolling order issues remained open in the case.

Details on court’s ruling

The court’s ruling focused on the section of the Natural Gas Act (15 U.S.C. § 717r) governing rehearing requests and judicial review under the statute. The Federal Power Act (FPA) includes a virtually identical provision.

The central issue in the case was whether, in issuing a tolling order, FERC “acts upon” a rehearing request within the meaning of NGA section 717r, such that any appeal at that point would be premature.

The court concluded that issuance of a tolling order does not amount to “acting upon” a rehearing application. Therefore, a tolling order is insufficient to prevent the deemed denial of a rehearing application or to deprive aggrieved parties of the right to seek judicial review following such deemed denial.

The court reasoned that, to act upon a rehearing application, FERC must either (i) grant rehearing, (ii) deny rehearing, (iii) abrogate the order without further hearing; or (iv) modify the order without further hearing.

The court turned aside FERC’s arguments that its tolling orders fall within the statute because they technically “grant” rehearing for the purpose of giving FERC more time to consider the rehearing requests.

The court determined instead that tolling orders “amount only to inaction on the application, which would trigger the possibility of judicial review as a deemed denial.”

Among the reasons for this conclusion, the court observes that a “grant” of rehearing, as opposed to inaction on an application for rehearing, requires at least some substantive engagement with the application. A grant of rehearing cannot consist solely of a grant of additional time to decide whether to grant rehearing, the court said.

In response to FERC’s arguments that it needs more than 30 days to address rehearing requests, the court said “that the only question we decide is that the Commission cannot use tolling orders to change the statutorily prescribed jurisdictional consequences of its inaction. That is not the same thing as saying the Commission must actually decide the rehearing application within that thirty-day window.”

The court said that in this regard it is not deciding “how Section 717r(a), the ripeness doctrine, or exhaustion principles might apply if the Commission were to grant rehearing for the express purpose of revisiting and substantively reconsidering a prior decision, and needed additional time to allow for supplemental briefing or further hearing processes.”

The court also points to language in section 717r that allows FERC to modify or set aside an order at any time up until the record of the FERC proceeding is filed in a federal court of appeals. Since the record is usually filed in court 40 days after an appeal is filed and served on FERC, the court observes that, in practice, FERC will have at least 70 days to act on rehearing requests (the original 30 days plus the 40 days before the record is filed in federal appeals court).

The court considered and rejected arguments that it should stand by previous D.C. Circuit rulings upholding the use of tolling orders.

The court concluded that after thirty days elapsed from the filing of a rehearing application without Commission action, the tolling order “could neither prevent a deemed denial nor alter the jurisdictional consequences of agency inaction.”

Having addressed the tolling order issues, the court denies the substantive challenges to FERC’s approval of the pipeline project.

FERC on July 6 filed a request with the D.C. Circuit asking it to delay the mandate (i.e., the formal judgment in the case for 90 days.)

FERC said there was good cause for a stay of the mandate, citing the need for time for the Commission to assess how to implement the opinion into the Commission’s “decades-old, judicially-sanctioned rehearing process.”

Chatterjee, Glick issue joint statement

Following the court’s ruling, FERC Chairman Neil Chatterjee and Commissioner Richard Glick on July 2 issued a joint statement in which they asked Congress to consider providing FERC with a reasonable amount of additional time to act on rehearing requests involving orders under both the NGA and FPA.

“We believe that any such legislation should make clear that, while rehearing requests are pending, the Commission should be prohibited from issuing a notice to proceed with construction and no entity should be able to begin eminent domain proceedings involving the projects addressed in the orders subject to those rehearing requests,” Chatterjee and Glick said.

In comments made at the American Public Power Association’s Wholesale Markets Virtual Summit on July 14, Glick said that “in my view, I think Congress should just revise the Natural Gas Act and the Federal Power Act to give us slightly more time – 45 days, 90 days, 120 days – you could argue what that might be. I tend to think 90 days is a good number, but different people might have different views on it.”

FERC “would have more time,” but it would still need to “move forward and get these orders out in a relatively timely fashion,” he said.

“In addition, I think we need to reconsider what we do on rehearing. In a lot of cases, rehearing requests are filed by parties that essentially repeat the same arguments they made before the original order went out and then we end up saying that these are the same arguments, but we’re going to address all these arguments and it takes forever,” he said.

In cases where nothing new has been said or argued in a rehearing request, FERC should say, “you know what, we’re just going to let it slide. Under the law, after 30 days, if we don’t act on it, the rehearing request is deemed automatically denied. We’ll let that happen, will go to court with the original order and to me that will solve a lot of our administrative issues from not having enough staff and resources to address all the rehearing requests we get in thirty days,” Glick said.