TVA Enters Agreement With GE Hitachi Related To Potential Deployment Of Small Modular Reactor
August 5, 2022
by Paul Ciampoli
APPA News Director
August 5, 2022
The Tennessee Valley Authority (TVA) has entered a two-party agreement with GE Hitachi to support TVA’s planning and preliminary licensing for a potential deployment of a BWRX-300 small modular reactor (SMR) at the Clinch River Nuclear site and provide additional information needed as TVA continues to analyze the viability of SMRs, subject to future TVA board approval.
This follows an April 2022 collaboration agreement with Ontario Power Generation (OPG) to support the development of small modular reactors as an effective long-term source of 24/7 carbon-free energy in both Canada and the U.S.
Such collaborations could help reduce the financial risk that comes from development of innovative technology, as well as future deployment costs, TVA said on Aug. 2 as part of its release of third quarter Fiscal Year 2022 financial results.
The TVA-OPG agreement allows TVA and OPG to coordinate their explorations into the design, licensing, construction and operation of small modular reactors.
OPG is moving forward with plans to deploy an SMR at its Darlington nuclear facility in Clarington, Ontario. The Darlington site is the only location in Canada licensed for new nuclear with a completed and accepted Environmental Assessment.
U.S. Power Grid Added 15 GW Of Utility-Scale Generating Capacity In First Half Of 2022
August 4, 2022
by Paul Ciampoli
APPA News Director
August 4, 2022
The Energy Information Administration (EIA) on August 3 reported that 15 gigawatts (GW) of new utility-scale electric generating capacity came online in the United States during the first half of 2022.
Based on the most recently reported plans, developers could add another 29 GW of capacity in the second half of the year, it said.
EIA’s Preliminary Monthly Electric Generator Inventory compiles information on all U.S. utility-scale power plants — plants with a nameplate capacity of at least 1 megawatt (MW) — that are currently operating, planning to come online, or retired. The inventory includes all utility-scale plants that have retired since 2002.
EIA updates this inventory once a month with preliminary data and then finalizes that data annually with a survey that provides additional information about the power plants.
With respect to operating capacity, EIA reported that wind generation accounts for the largest share, 34%, of the 15.1 GW of capacity that came online in the United States during the first half of 2022, followed by natural gas, solar, and battery storage.
More than 40% of the wind capacity added so far in 2022 is located in Texas, 2.2 GW of the 5.2 GW wind total.
In terms of planned capacity, developers and project planners reported plans to add 29.4 GW of new capacity in the United States in the second half of 2022. Nearly half of that planned capacity is from solar (13.6 GW), followed by wind (6.0 GW). As in previous years, many projects plan to come online in December because of tax incentives.
Respondents to EIA’s survey currently plan to add 3.7 GW less solar capacity in 2022 than what they had expected at the beginning of the year. Pandemic-related challenges in supply chains and a U.S. Department of Commerce tariff investigation are likely causes for this decrease, the agency said.
As for retired capacity, of the 15.1 GW of electric generating capacity that U.S. operators plan to retire during 2022, more than half (8.8 GW) was retired in the first half of the year. Coal-fired power plants will account for 76% of the retirements this year, followed by natural gas (12%) and nuclear (9%).
Federal Nuclear Regulators Authorize Fuel Loading And Operation At New Georgia Unit
August 4, 2022
by Paul Ciampoli
APPA News Director
August 4, 2022
The Nuclear Regulatory Commission (NRC) has authorized Southern Nuclear Operating Company to load nuclear fuel and begin operation at Vogtle Unit 3 in Georgia, the first reactor to reach this point in the agency’s combined license process.
The NRC’s decision moves Vogtle Unit 3, adjacent to the operating Units 1 and 2, near Waynesboro, Georgia, out of the construction reactor oversight program and into the operating reactor oversight process.
Plant Vogtle Units 3 and 4 are two 1,100-megawatt Westinghouse AP1000 nuclear reactors being constructed in Burke County, Ga.
“The team at the site continues working diligently to make final preparations for Unit 3 fuel load, initiate startup testing and bring the unit online,” Southern, an investor-owned utility, noted on Aug. 3.
“Over the next several weeks, well-trained and highly qualified nuclear technicians will continue work required to support loading fuel, which is already onsite, into the unit’s reactor. This will be followed by several months of startup testing and operations,” the utility said.
Startup testing is designed to demonstrate the integrated operation of the primary coolant system and steam supply system at design temperature and pressure with fuel inside the reactor. Operators will also bring the plant from cold shutdown to initial criticality, synchronize the unit to the grid and systematically raise power to 100%.
Florida public power utility JEA, the City of Jacksonville and the Municipal Electric Authority of Georgia (MEAG Power) in 2020 announced a settlement of all disputed issues relating to the new Units 3 and 4 of the Alvin W. Vogtle Electric Generating Plant and an amended and restated power purchase agreement.
The Vogtle Electric Generating Plant is jointly owned by Georgia Power (45.7%), Oglethorpe Power Corporation (30%), Municipal Electric Authority of Georgia (22.7%) and Dalton Utilities (1.6%).
Additional information about Plant Vogtle Units 3 and 4 is available here.
DOE Issues Notice Of Intent For Potential Hydrogen Research Funding
August 4, 2022
by Peter Maloney
APPA News
August 4, 2022
The Department of Energy (DOE) recently issued a notice of intent for a potential funding opportunity to accelerate the research, development, and demonstration (RD&D) of clean-hydrogen technologies and grid resilience.
The potential funding would advance the DOE’s goal of reducing the cost of clean hydrogen to $1 per 1 kilogram in 1 decade that is central to the agency’s Hydrogen Shot initiative. It would also support the DOE’s H2@Scale initiative to develop clean and affordable hydrogen across multiple sectors in the economy and improve energy resilience.
The DOE said the goals would be advanced through RD&D efforts in several areas, including advanced pathways for solar-based hydrogen fuel production; technologies for high-resolution hydrogen sensing; demonstrations of materials-based hydrogen storage and transport systems; and development of high-performance, durable, low-cost fuel cell components for medium- and heavy-duty vehicles.
The potential funding opportunity would also seek to establish a grid resilience university consortium with agreements between universities in the United States, Canada, and Mexico to foster information sharing on best practices and cross-border dependencies. The consortium would work collaboratively with tribes, states, regions, industry, utilities, and other stakeholders to support grid resilience planning and pilot projects that can serve as a model for others.
In the Notice of Intent, the DOE said it envisions awarding multiple financial assistance awards in the form of cooperative agreements, with the performance period running from two to four years. DOE is encouraging applicants that include stakeholders in academia, industry, and national laboratories across multiple technical disciplines.
Teams are also encouraged to include representation from diverse entities such as minority-serving institutions or through linkages with Opportunity Zones.
The DOE said the potential funding opportunity would advance the Biden administration’s goals of achieving carbon-free electricity by 2035 and net-zero carbon emissions across the entire economy by 2050.
In February, the DOE announced two requests for information to collect feedback from stakeholders to inform the implementation and design of the Bipartisan Infrastructure Law’s Regional Hydrogen Hub and the Electrolysis and Clean Hydrogen Manufacturing and Recycling Programs.
In June, the DOE closed on a $504.4 million loan guarantee to the Advanced Clean Energy Storage project in Utah.
Nuclear Regulatory Commission Directs Staff To Issue Final Rule Certifying NuScale SMR Design
July 31, 2022
by Paul Ciampoli
APPA News Director
July 31, 2022
The U.S. Nuclear Regulatory Commission has directed its staff to issue a final rule that certifies NuScale’s small modular reactor (SMR) design for use in the U.S., the NRC said on July 29.
The certification’s effective date is 30 days after the NRC publishes the rule in the Federal Register.
NRC certification means the design meets the agency’s applicable safety requirements.
An application for a nuclear power plant combined license that references a certified design will not need to address any of the issues resolved by the design certification rule. Instead, the combined license application and the NRC’s safety review would address any remaining safety and environmental issues for the proposed nuclear power plant, the NRC said.
The design certification approves the NuScale reactor’s “design control document,” which is incorporated by reference in the final rule.
NuScale submitted an application to the NRC on Dec. 31, 2016, to certify the company’s SMR design for use in the United States. The NRC staff met its schedule goals for completing its technical review.
The design uses natural, “passive” processes such as convection and gravity in its operating systems and safety features, while producing up to approximately 600 megawatts (MW) of electricity.
The SMR’s 12 modules, each producing 50 MW, are all submerged in a safety-related pool built below ground level.
Carbon Free Power Project, LLC (CFPP), a wholly owned subsidiary of Utah Associated Municipal Power Systems, continues to advance the development and deployment of its first-of-a-kind SMR nuclear plant at the U.S. Department of Energy’s Idaho National Laboratory near Idaho Falls, Idaho.
CFPP successfully and safely completed field investigation activities at the site in January 2022, a major milestone for the project.
The CFPP will deploy a NuScale power plant that is based on NuScale’s SMR technology.
In May 2021, NuScale Power and Washington State’s Grant County Public Utility District announced the signing of a memorandum of understanding to evaluate the deployment of NuScale’s SMR technology in Central Washington State.
Canada’s Ontario Power Generation (OPG) and the Tennessee Valley Authority (TVA) will jointly work to help develop small modular reactors (SMRs), TVA announced earlier this year.
The agreement allows TVA and OPG to coordinate their explorations into the design, licensing, construction and operation of small modular reactors.
CPUC Seeks Comment On Study About Adding Hydrogen To Natural Gas Stream
July 28, 2022
by Paul Ciampoli
APPA News Director
July 28, 2022
The California Public Utilities Commission (CPUC) is seeking comment on a study about the feasibility and safety of injecting hydrogen into the natural gas system as a means of helping the state meet its decarbonization goals.
The CPUC commissioned the Hydrogen Blending Impacts Study in compliance with Senate Bill 1369 and as part of its ongoing Renewable Gas Rulemaking.
The Rulemaking examines expanding renewable hydrogen by establishing standards and interconnection protocols for injecting renewable hydrogen into natural gas pipelines.
The study was done by the University of California at Riverside.
The study found that hydrogen blends of up to 5 percent in the natural gas stream are generally safe but going beyond 5 percent results in a greater chance of pipeline leaks and the embrittlement of steel pipelines. In addition, hydrogen blended into the natural gas stream at levels above 5 percent could require modifications of appliances such as stoves and water heaters to avoid leaks and equipment malfunction.
Hydrogen blended at levels above 20 percent present a higher likelihood of permeating plastic pipes, which can increase the risk of gas ignition outside the pipeline. And because hydrogen has a lower energy content than natural gas, more hydrogen-blended gas would be needed to deliver the same amount of energy to users.
The researchers concluded that more study on the effects of blending hydrogen into the gas system is needed to ensure the safety of the practice. The researchers also said it is critical to conduct real world demonstrations of hydrogen blending under safe and controlled conditions to determine “the appropriate blend percentage suitable to mitigate operational risks such as ignition.”
In March 2020, the Northern California Power Agency said it was preparing to install equipment at a 304-megawatt (MW) power plant so it could burn hydrogen mixed with natural gas.
In December 2019, the Los Angeles Department of Water and Power said it planned to phase out the 1,800-MW, coal-fired Intermountain Power Project (IPP), which it participates in with electric power cooperatives and other public power utilities in California, Nevada and Utah, and replace it with natural gas-fueled generation that would eventually be fueled entirely by hydrogen.
“This Study provides additional insight into the possibilities and limits of California’s pipeline infrastructure as we explore options for supplying zero-carbon energy to hard to decarbonize applications,” Clifford Rechtschaffen, the CPUC commissioner assigned to the Renewable Gas Rulemaking, said in a statement. “I look forward to party comments on hydrogen-methane blending and its role in decarbonization strategies.”
The ruling seeking comments is available on the CPUC website, and members of the public can comment on the study and access related documents here.
Groups Raise Reliability, Cost And Other Concerns In Response To Idea Of Breaching Northwest Dams
July 20, 2022
by Paul Ciampoli
APPA News Director
July 20, 2022
The idea of breaching the Lower River Snake Dams (LSRDs) in Eastern Washington State fails to take into account a number of potential negative impacts that could result from such a move including an increase in electricity costs for consumers and removing a key pillar of reliable power supply for the region, the American Public Power Association (APPA) and regional public power groups said.
In June, U.S. Sen. Patty Murray, D-Wash., and Washington Gov. Jay Inslee announced the release of an independent draft report intended to help inform the recommendations of their Joint Federal-State Process regarding the Lower Snake River Dams and salmon recovery in the Pacific Northwest.
The draft report notes that the potential for improvements to West Coast salmon populations is one of the main factors prompting interest in breaching the LSRDs. The deadline for comments on the draft report was July 11, 2022.
Among the groups that weighed in on the draft report was the Oregon Municipal Electric Utilities Association (OMEU).
The draft report assumes the LSRDs will be less important in the future, OMEU said. “However, with 100% clean energy mandates in Oregon and Washington this is clearly untrue. With baseload resources being replaced by massive amounts of intermittent generation, the LSRDs’ ability to provide power — on demand — will become increasingly important for reliable grid operations and public safety, especially during extreme weather conditions,” OMEU argued.
It pointed out that during the heat dome events of last summer, the LSRDs provided much-needed energy, balancing and contingency reserves. “Without those four dams, powering through the heat wave could have been much more expensive and operationally challenging,” OMEU said.
For consumer-owned utility ratepayers, losing the LSRDs could increase consumer electricity rates by 25% or more, OMEU said. “Replacing the generating capabilities of the LSRDs, alone, would cost $15 billion in a zero-carbon future. This type of financial hardship threatens to irreparably harm the communities we serve, particularly our low income and vulnerable customers.”
APPA, which supports the comments submitted by the Washington Public Utility Districts Association (WPUDA) and OMEU, noted that many of APPA’s members buy power produced by the LSRDs, which are part of the broader Columbia River Power System, or own and operate their own hydropower projects.
Making full use of the nation’s hydropower resource is key to ensuring that the nation’s — and the Pacific Northwest’s — grid remains reliable and resilient, and that utilities can meet emission reduction goals, APPA said.
“It is difficult to overstate how critical it is to maintain the LRSDs as the region — and the nation — seeks to lower emissions while maintaining electric reliability and affordability over the long-term,” APPA said in its comments. “Moreover, recent extreme weather events have demonstrated that the LSRDs are an irreplaceable resource not just in the future but right now — both in terms of energy, capacity, and other grid services key to maintaining reliable electricity.”
Public power utilities are committed to scientific, cost-effective mitigation for the impacts of the federal hydropower system, APPA noted. It said that costs related to fish and wildlife mitigation, including the cost of lost power generation, comprise a quarter or more of the Bonneville Power Administration’s power rates.
“The LSRDs feature state-of-the-art fish passage technology that greatly improves in-river fish survival, achieving spring juvenile survival at 96 percent and summer migrating fish survival at 93 percent. Removal of the LSRDs is not a clear path to recovery of endangered species or overall abundance of salmon. More attention is needed to the threats of ocean conditions, avian predation, and over-fishing,” APPA said.
Removal of the LSRDs “may prove to be a tipping point, nudging the Northwest system into acute scarcity of electric supply. The Federal hydropower system, and particularly the LSRDs, are in a critical position to maintain grid reliability and prevent blackouts in the West.”
Moreover, no existing alternative technologies can provide the same combination of low cost, reliable, and flexible attributes, and it is far from clear that dam removal will result in meaningful fish recovery commensurate with costs, APPA added.
WPUDA noted that the draft states that three studies found the energy generated by the LSRD could be replaced by a clean energy portfolio. “It is important that the report emphasize that these studies do not demonstrate that an alternative clean energy portfolio can achieve the other electric system services provided by the LSRDs: peaking capacity, clean energy, grid stability, ancillary and grid services, transmission voltage support and low regional energy rates,” WPUDA said.
The draft report indicates the cost of dam breaching to be $10-$27 billion, WPUDA noted. “Given the stated purpose is salmon recovery, WPUDA believes it is worth asking whether this is the best use of this enormous sum of dollars. And if so, could this money be spent in alternative ways that better support salmon abundance (e.g., stream bank restoration, culvert replacement, enhanced salmon migration support)?”
Northwest RiverPartners, which serves not-for-profit, community-owned electric utilities in Oregon, Washington, Idaho, Montana, Utah, Nevada and Wyoming, said that “Our already fragile grid is facing unique challenges and threats. Removing the lower Snake River dams would not only create even greater challenges, but their loss would harm our efforts to keep the power on when we most need it.”
Additionally, losing the lower Snake River dams “makes it virtually certain that grid operators will be forced to continue using coal or natural gas generation for years longer than allowed under Washington’s clean energy laws to avoid blackouts,” Northwest RiverPartners said.
Following the public input period, tribal consultation, and other means of engagement, the report will be updated and released in final form. The senator and governor will then make their recommendations.
Ariz. Public Power And Cooperative Groups Urge PG&E To Extend Nuclear Plant’s Operating Life
July 12, 2022
by Paul Ciampoli
APPA News Director
July 12, 2022
In a recent letter to the CEO of California investor-owned utility PG&E, groups representing public power utilities and electric cooperatives in Arizona made the case for extending the life of the California nuclear power plant Diablo Canyon Power Plant past its existing license.
“While we understand that the history of the plant is long and complicated, we hope that you will agree that the benefits of extending the operating license outweighs the cons,” wrote officials with the Irrigation & Electrical Districts’ Association of Arizona (IEDA), the Arizona Municipal Power Users’ Association (AMPUA) and the Grand Canyon State Electric Cooperative Association (GCSECA) in their June 27 letter to Patricia Poppe, CEO of PG&E.
“The development of carbon-free replacement power is not keeping pace with California’s decision to eliminate fossil fuel generation by 2045,” the letter said. With ongoing supply chain and solar tariff issues, most new plant construction has been pushed out at least two years, the letter said. “If PG&E were to take a plant that provides roughly 9% of California’s energy offline in an environment of already limited capacity, rolling blackouts worse than those in 2020 are sure to follow.”
The letter was signed by Ed Gerak, executive director of IEDA, AMPUA’s Russell Smoldon, and Dave Lock, CEO of GCSECA.
In June 2016, PG&E said it planned to retire Diablo Canyon nuclear power plant in California under a joint proposal with labor and environmental groups. The California Public Utilities Commission in 2018 signed off on a request by PG&E that it be allowed to retire the Diablo Canyon nuclear plant by 2025. The two units at Diablo Canyon together produce approximately 2,300 net megawatts of power.
In their letter, Gerak, Smoldon, and Lock noted that in the Long-Term Reliability Assessment released in December 2021 and developed by the North American Electric Reliability Corporation, Diablo Canyon’s retirement was highlighted as further impacting the reserve margin, which it described as insufficient to manage region-wide heat waves like seen in 2020. “With the existing capacity constraints and the rapid increased cost for natural gas, companies are returning to coal for economic and reliability reasons. Closing Diablo Canyon would exacerbate this issue in the future,” the letter said.
Gerak, Smoldon, and Lock also noted that the Bipartisan Infrastructure Law has $6 billion in a Civil Nuclear Credit Program that could be used to help retrofit the plant and extend the license.
The U.S. Department of Energy (DOE) on June 30, 2022 announced an amendment to the Civil Nuclear Credit Program Guidance for the currently open award cycle. To incorporate these changes and give potential applicants the time they need to respond, DOE also extended the application period another 60 days to September 6, 2022. PG&E had requested an extension for the deadline.
In April, California Gov. Gavin Newsom told the Los Angeles Times editorial board that the state “would seek out a share of $6 billion in federal funds meant to rescue nuclear reactors facing closure,” the newspaper reported.
“With the ongoing drought, hydropower production has been severely impacted,” the letter from the IEDA, AMPUA and GCSECA officials said. “There is a real possibility of some plants losing power production completely. Nuclear power is the only carbon-free base load generation in the West that we can still count on. We hope that includes Diablo Canyon in the future.”
OPPD Recommends Delaying Retirement, Conversion Of Units At Plant
July 12, 2022
by Paul Ciampoli
APPA News Director
July 12, 2022
Nebraska public power utility Omaha Public Power District (OPPD) in June made a recommendation at a OPPD Board of Directors meeting to delay the retirement of North Omaha Station (NOS) units 1-3 and fuel conversion of units 4 and 5 from low-sulfur coal to natural gas.
The delay is only until the utility’s new natural gas generation balancing stations are fully approved for grid interconnection service in accordance with federal law issued by the Federal Energy Regulatory Commission and administered by the Southwest Power Pool (SPP), OPPD noted.
Previously, OPPD’s Board of Directors approved these changes at NOS to occur by the end of 2023, when the new natural gas generation balancing stations – Standing Bear Lake (SBLS) and Turtle Creek (TCS) were planned to come online.
However, due to unforeseen delays with grid interconnection regulatory approvals for those projects, part of the utility’s Power with Purpose (PwP) initiative, OPPD recommended maintaining current generating operations at NOS until the new natural gas balancing stations are fully available, which is estimated by 2026.
PwP will bring additional generation totaling approximately 1,200 megawatts (MW) of natural gas and solar capability online.
OPPD said that the construction of SBLS and TCS is critical to ensuring continued system reliability and resiliency. Once these stations are online, OPPD will look to retire North Omaha Station units 1-3 and refuel units 4-5 from low-sulfur coal to natural gas.
In 2016, OPPD retired North Omaha units 1-3 from coal operations. Today, these units are available to run on natural gas, serving as peaking units during times of high demand for electricity.
SBLS and TCS are under construction now. However, in accordance with federal requirements, SPP must conduct a grid interconnection study before they can be connected to the grid.
“And with a large number of new generation projects requesting to come online in our region and every other region in the country, there is a major study backlog,” OPPD noted.
In addition, the two new natural gas generation projects have experienced some siting and grading delays, as well as supply chain issues. The new solar generation projects have also experienced challenges with siting of projects and supply chain challenges, including impacts from the federal focus on solar panel imports.
“This is one of those moments where we need to slow down our present path to achieve our future goals,” said President and CEO Javier Fernandez. “The extension of North Omaha Station’s current mission supports our commitment to reliability and resiliency, something we know our customers and communities are especially mindful of following the 2021 polar vortex event.”
OPPD said its leadership team continues to work diligently on finding solutions to the challenges facing not only the utility, but utilities across the region. Current delays will not impact OPPD’s commitment to achieving net zero carbon by 2050, the utility said.
The board of directors will vote on the recommendation during its next meeting, Aug. 18.
New Report Highlights Key Role Of Natural Gas In Electric Power Sector
June 28, 2022
by Paul Ciampoli
APPA News Director
June 28, 2022
Natural gas will continue to be an important driver of electric reliability and cost in the U.S. and the nexus between the electric and natural gas industries will continue to be critical for the foreseeable future, a new report prepared for the American Public Power Association (APPA) states.
The report, released on June 24, was prepared for APPA by GDS Associates Inc., an energy industry consulting firm.
The report covers a wide range of topics including an overview of the natural gas industry, the electric and natural gas nexus and pipeline infrastructure needs.
With respect to the nexus between the electric sector and natural gas, the report notes that in the last 15 years, the intersection between the electric and natural gas industries has expanded and intensified.
“Natural gas has grown significantly as an electric generation fuel source in that time, both as a replacement for retiring coal and as flexible generation, balancing growing intermittent resources like wind and solar,” the report said.
It noted that the prominence of natural gas-fueled generation has been propelled by the shale gas revolution, which significantly increased domestic natural gas production, “resulting in sustained low prices for several years and a redefinition of how the natural gas pipeline network was utilized and expanded.”
Higher and higher intermittent generation penetration and the uncertainty and variability of electric output from these sources “make quick-starting natural gas generation a critical reliability component on the grid,” the report said.
Natural gas-fired electric generation will remain critical to maintaining reliable electric service for the foreseeable future, according to the report.
It points out that the U.S. Energy Information Administration (EIA) projects that natural gas resources will remain relatively constant as approximately one-third of the generation capacity mix through 2050, with some regions likely at a higher percentage.
Natural gas remains an important fuel for generating plants owned by public power utilities to serve the customers in their communities. According to analyses by APPA, natural gas-fueled power plants accounted for 44.1% of generating capacity owned by public power utilities as of 2020, and 34.4% of the energy generated by public power-owned facilities, the report noted.
It said that the importance of natural gas-fueled generation to reliable electric service “creates significant interdependencies between the electric and natural gas industries. These interdependencies have been areas of particular focus for years, often highlighted by severe winter weather events when peak electricity and natural gas usage coincide.”
Impact Of Natural Gas Prices On The Cost Of Power
Meanwhile, the report notes that there is a well-established connection between wholesale natural gas and power prices.
The recent increase in natural gas prices has been attributed to reduced exploration due to the COVID pandemic and environmental policy, fallout of the February 2021 arctic weather event, increased difficulty financing exploration, and increased liquefied natural gas (LNG) export activity, among other factors.
“Indeed, over the past seven years, the amount of LNG exports from the U.S. has consistently risen and is expected to continue to rise. This trend has only been accelerated and intensified due to the war in Ukraine, and domestic users of natural gas are increasingly competing with global users.”
As natural gas electric generation has grown and played a large part in replacing coal generation, the U.S. electric system is more heavily impacted by the price of natural gas. “Coal continues to compete with natural gas resources – and is relatively advantaged because of the recent increase in natural gas prices – but large amounts of coal generation have retired so its role as a substitute for natural gas fuel has diminished,” the report pointed out.
Renewables can also compete and substitute for natural gas generation, but their variable output means that natural gas generation also serves a complementary role with renewables. “Both coal and renewables have been challenged with supply chain disruptions which also reduce their capability to compete with natural gas.”
The importance of natural gas to reliable and affordable electric service “highlights the need to ensure an adequate and reliable natural gas supply chain, including sufficient natural gas transportation infrastructure,” the report said.
Among the report’s key conclusions was that “[w]ithout adequate natural gas supply and the pipeline infrastructure to transport it, natural gas, power, and home heating customers are likely to experience elevated energy prices.”
Regulation and Pipeline Infrastructure
As for regulation and natural gas pipeline infrastructure, the report notes that as the lead regulator with authority to approve new interstate natural gas pipeline facilities, the Federal Energy Regulatory Commission (FERC) plays a significant role in ensuring adequate infrastructure exists to meet demand for natural gas, including that for electricity generation.
In the past few years, FERC has been undertaking an overhaul of its processes for reviewing new pipeline applications, with potentially significant implications for natural gas supply and price reliability, the report said.
In 2018, FERC began exploring whether it should revise its gas pipeline certification policy statement that was originally issued in 1999. More recently, FERC in March 2022 voted to seek additional comments on two policy statements it issued in February that provide guidance regarding the certification of interstate natural gas pipelines and consideration of greenhouse gas emissions in natural gas project reviews.
“As the need for natural gas to address critical needs persists, including ensuring electric reliability, regulatory processes for review and approval of gas pipeline infrastructure must be efficient and provide regulatory certainty and predictability to applicants and other stakeholders,” the report states.
“Efficiency is achieved by having decision processes that are as streamlined and expeditious as possible, given statutory requirements, to provide reasonable outcomes while avoiding unnecessary delays or effort. Certainty is achieved with concrete and clear approval requirements. There should be a clear path to approval if required conditions are met. Efficiency and certainty are critical pillars of regulatory approval processes that should harmonize with the extent of statutory requirements of review.”
FERC’s goal to have legally durable pipeline approvals “is entirely consistent with the need for regulatory certainty and efficiency. A regulatory approval process can and should meet statutory requirements (avoiding judicial reversals) while also providing efficiency and certainty for applicants.”
At the same time, the report said that if regulatory approval processes are inefficient or create uncertainty, then needed infrastructure investment can be adversely affected.