On February 29, 2024, President Biden nominated three individuals to serve as commissioners on the Federal Energy Regulatory Commission (FERC), signaling a key move towards shaping the nation's energy policies. [1] The nominees, if confirmed, would bring diverse expertise and backgrounds to FERC, contributing to the agency's oversight of energy markets and regulation. Willie L. Phillips, an attorney with a strong background in energy law, offers insights into regulatory processes and legal frameworks. Ashley L. Poling, known for her experience in energy policy and legislative affairs, brings a deep understanding of the intersection between policy and regulation. Lauren "Bubba" McDonald Jr., a seasoned public servant and advocate for energy infrastructure, provides perspectives on energy security and grid reliability. These nominations reflect the administration's commitment to addressing pressing energy and environmental challenges, including promoting clean energy integration and ensuring equitable access to reliable energy. The confirmation of these nominees would play a crucial role in shaping the nation's energy landscape and advancing the administration's clean energy agenda.
[USA] FERC accepts ISO New England plan facilitating storage as transmission-only assets
On October 19, 2023, the Federal Energy Regulatory Commission (FERC) accepted a proposal from ISO New England (ISO-NE) to allow for energy storage to “play an important role in ensuring a reliable transmission system.”[1] Storage as transmission-only assets (SATOAs), which may include a variety of storage resources like batteries and pumped hydro storage, would be owned and maintained by transmission companies, but ISO-NE system operators would control their use. Because they would be built only to serve a transmission reliability purpose, they will not compete in electricity markets and will have minimal effect on wholesale prices. These assets would used “under specific system conditions to prevent localized overloading after at least two unplanned equipment outages on the transmission system.” They may also be deployed as a last resort to help prevent or mitigate controlled outages if demand exceeds regionally available supply or to help with system recovery after an outage.
The new rules will not apply to or restrict other energy storage resources that already compete in the markets, which include almost 2,000 MW of pumped storage and more than 600 MW of new and existing battery storage resources. The rules would also not apply to or restrict the roughly 18,000 MW of battery resources proposed in ISO-NE’s Interconnection Request Queue or future projects looking to participate in the markets. Construction of SATOAs will depend on selection in ISO-NE’s open regional system planning process administered, similar to the way reliability-based system upgrades are handled today. FERC directed the ISO to submit a filing identifying the effective date of the SATOA revisions no less than 30 days prior to their implementation.
[1] https://isonewswire.com/2023/10/25/ferc-accepts-rules-allowing-storage-to-aid-transmission/?utm_source=isone&utm_medium=newsfeed
[USA] FERC, NERC report highlights problems with natural gas system during Winter Storm Elliott
In a report released on September 21, 2023, by the Federal Energy Regulatory Commission (FERC) and the North American Electric Reliability Corporation (NERC), the natural gas system in New York City nearly failed and left a million customers without heat on December 24, 2022, during Winter Storm Elliott.[1] The near emergency has not previously been disclosed. The report was released during a FERC meeting, during which the commission also approved four new natural gas projects despite continued disagreement over how projects’ greenhouse gas emissions should be assessed.
On the morning of December 24, 2022, Consolidated Edison (ConEd), the largest utility in the state, declared a gas emergency as pipeline pressure declined rapidly. If the utility had not taken emergency action, FERC staff said gas heating could have been shut off for months in “all or parts” of the utility’s footprint. ConEd serves gas to 1.1 million customers in New York City. During Winter Storm Elliott, the natural gas system experienced widespread freezing issues and problems with the interstate pipelines. Outages at 63 natural gas power plant units were attributed to natural gas deliveries being cut off.
[1] https://www.ferc.gov/news-events/news/presentation-ferc-nerc-regional-entity-joint-inquiry-winter-storm-elliott
[USA] FERC approves new interconnection rules to help spur new generation
On July 27, 2023, the Federal Energy Regulatory Commission (FERC) approved Order 2023, which aims to speed up interconnection processes.[1] The rule is the first major change to FERC’s interconnection requirements in 20 years. Order 2023 largely follows a Notice of Proposed Rulemaking (NOPR) released in June 2022. The rule adopts a “first-ready, first-served” cluster study approach, replacing the practice of looking at individual proposals on a first-come, first-served basis. According to FERC, this approach “will increase the efficiency of the interconnection process, help minimize delays and improve cost allocation by analyzing the transmission system impacts of multiple projects at once.”
It requires interconnection customers to pay increased study deposits, meet more stringent site control requirements, and pay commercial readiness deposits. In addition, Order 2023 sets deadlines for regional transmission organizations (RTOs) and other transmission providers to complete interconnection studies, with penalties set for missing deadlines. The rule also requires transmission providers to allow more than one generating facility on a shared site at a single point of interconnection and share an interconnection request. Transmission operators have 90 days to file plans with FERC explaining how they will put the rule in place.
[1] https://www.ferc.gov/news-events/news/fact-sheet-improvements-generator-interconnection-procedures-and-agreements
[USA] Federal appeals court strikes down FERC approval of SEEM market
On July 14, 2023, the U.S. Court of Appeals for the District of Columbia Circuit ruled that Federal Energy Regulatory Commission (FERC) had unlawfully approved the Southeast Energy Exchange Market (SEEM)[1].[2] SEEM is a proposed trading platform for utilities in the Southeast covering 12 states that allows utilities in the region to make automated bilateral trades every 15 minutes using available transmission capacity. The trades are enabled by non-firm energy exchange transmission service (NFEETS).
In a split decision, the court ruled that FERC’s November 2021 decision approving SEEM’s transmission rules went against its open access requirements in Order 888, which aim to ensure transmission owners offer non-discriminatory access to their networks. The appeals court said that FERC failed to explain why the market should be allowed to exclude participants outside the region. The court remanded FERC’s 2021 decision approving the SEEM market. The court also directed FERC to revisit its decision approving SEEM and told the commission to consider an earlier appeal from clean energy companies and environmental groups that it had previously dismissed as untimely.
[1] SEEM members include Associated Electric Cooperative, Dalton Utilities, Dominion Energy South Carolina, Duke Energy Carolinas, Duke Energy Florida, Duke Energy Progress, Georgia System Operations Corporation, Georgia Transmission Corporation, JEA, LG&E and KU Energy, MEAG Power, N.C. Municipal Power Agency No. 1, NCEMC, Oglethorpe Power Corp., PowerSouth, Santee Cooper, Seminole Electric Corporation, Southern Company, Tampa Electric Company and TVA.
[2] https://www.cadc.uscourts.gov/internet/opinions.nsf/0D7A85E32E0291DF852589EC0050747A/$file/22-1018-2007875.pdf
[USA] FERC gives approval for construction on Mountain Valley Pipeline
On June 28, 2023, the Federal Energy Regulatory Commission authorized the resumption of construction for the Mountain Valley pipeline.[1] Mountain Valley Pipeline, which is set to run about 300 miles from northwestern West Virginia to southern Virginia, was initially approved by FERC in 2017. However, the project has faced several court decisions rejecting its federal permits due to environmental concerns. FERC’s recent order follows the passage of the debt ceiling bill earlier in June, which required federal agencies to approve the pipeline. In FERC’s unanimous order, the commission said that all work, including portions of the project that will run through the Jefferson National Forest, could proceed. The order authorizes FERC’s Office of Energy Projects to approve any future changes to the project as long as the director of the office finds them “to be needed to complete construction.”
[1] https://elibrary.ferc.gov/eLibrary/filelist?accession_number=20230628-3041&optimized=false
[USA] PJM asks FERC to help resolve generator complaints about Winter Storm Elliott penalties
On April 14, 2023, PJM Interconnect asked the Federal Energy Regulatory Commission (FERC) to help lead discussions to resolve eight pending complaints against the grid operator by power plant owners over penalties for failing to meet their capacity obligations during December 2022 Winter Storm Elliott.[1] At the peak of Winter Storm Elliott, about 57,000 MW were offline in PJM’s footprint.[2] About 63% of all outages were natural gas-fired power plants, 28% coal, 4% oil, 2% nuclear, 1% hydroelectric, and about 1% other. According to a fact sheet released by PJM, about 200 market participants face roughly $1.8 billion in performance penalties for falling short of their required power deliveries on December 23 and 24.
In the request, PJM said FERC should appoint one or more settlement judges to help PJM, the complainants, and the intervenors resolve as many of the non-performance charge disputes as possible. PJM said it plans to answer each complaint and show that in each case, the assessed non-performance charges follow its tariff; that the relevant tariff provisions are just and reasonable, assuming they are even open to challenge; and that PJM properly invoked its emergency procedures. However, PJM noted that it recognizes there are benefits to a quick resolution to the dispute.
[1] https://elibrary.ferc.gov/eLibrary/filelist?accession_number=20230414-5132&optimized=false
[2] https://www.pjm.com/-/media/markets-ops/winter-storm-elliott/faq-winter-storm-elliott.ashx
[USA] White House names Willie Phillips as acting chairman of FERC
On January 3, 2023, the White House named Willie Phillips (D) as acting chairman of the Federal Energy Regulatory Commission (FERC). Phillips has been a FERC commissioner since December 2021.[1] Phillips is the first black person to lead FERC and the first former state utility regulator to lead the agency since Pat Wood III’s tenure ended in mid-2005. Phillips was chairman of the Public Service Commission of the District of Columbia before he joined FERC. He replaces Richard Glick (D), whose tenure ended at the end of 2022 after Senate Energy and Natural Resources Committee Chairman Joe Manchin (D-WV) declined to hold a nomination hearing for his second term. As a result, FERC now has only four sitting commissioners, two Democratic commissioners, Allison Clements and Willie Phillips, and two Republicans, James Danly and Mark Christie. Commissioner Danly’s term will end on June 30, 2023.
[1] https://www.ferc.gov/news-events/news/president-biden-names-willie-phillips-acting-chairman
[USA] PJM to request a mid-auction capacity market rule change
During a presentation on the status of PJM’s 2024/2025 Base Residual Auction on December 21, 2022, Stu Bresler, Sr. Vice President of Market Services, stated that the grid operator plans to ask the Federal Energy Regulatory Commission (FERC) to approve a rule that would allow it to change a capacity auction parameter that led to anomalous results in its auction.[1] In the case of a small locational deliverability area (LDA) like Delmarva Power South, additions of large and/or intermittent units can lead to an increase in the area’s reliability requirement because capacity transfers are needed to account for times when the resources are not available. According to Bresler, when PJM determined how much capacity it would need, it assumed a mix of generators would offer about 1,000 MW in the Delmarva Power South area[2] because they had signed interconnection agreements. However, those generators didn’t bid into the auction, resulting in the LDA being short and the market clearing at an unjustly high price because of the increased reliability requirement.
Through a Section 205 filing[3], PJM plans to ask FERC to approve a rule change that would allow it to lower an area’s reliability requirement during the auction process if generators don’t bid into the auction as expected. PJM intends to ask FERC to make a decision on the proposal within 60 days. The grid operator expects to issue two sets of auction results on January 3, 2022. One set will show the results under existing rules, while the other will show results under the proposed rule. PJM will wait for FERC approval before clearing the auction. Joseph Bowring, President of Monitoring Analytics, PJM’s Independent Market Monitor, expressed his support for PJM’s actions.
[1] https://insidelines.pjm.com/pjm-updates-members-on-2024-2025-capacity-auction-results/
[2] Delmarva Power South covers part of Delaware, Maryland, and Virginia.
[3] In a Section 205 filing, the gird operator submits a new document containing or affecting a rate, term or condition of a FERC-jurisdictional service or charge with FERC for approval.
[USA] FERC orders reliability standards and registration requirements for IBRs to ensure grid reliability
On November 17, 2022, the Federal Energy Regulatory Commission (FERC) ordered mandatory reliability standards for inverter-based resources (IBRs) to help ensure wind, solar, and battery storage don’t threaten grid reliability.[1] FERC also directed the North American Reliability Electric Reliability Corporation (NERC) to develop a plan within 90 days to identify and register the owners and operators of IBRs connected to the bulk-power system that are not currently required to register with the organization.
NERC estimates that roughly 860 GW of wind, solar, and storage, which use inverters to convert direct current electricity to alternating current electricity, could come online over the next decade. Compared to synchronous generators like natural gas-fired power plants, IBRs must be programmed to ride through grid disturbances. Most FERC-approved Reliability Standards to date were developed with synchronous generation in mind. To address this, FERC’s proposed rule directs NERC to develop new or modified standards to eliminate four reliability gaps related to IBRs: data sharing, model validation, planning and operational studies, and performance requirements.
[1] https://www.ferc.gov/news-events/news/joint-presentation-items-e-1-registration-inverter-based-resources-and-e-2
[USA] FERC approves MISO request to keep Ameren Missouri’s Rush Island coal plant open
On October 24, 2022, the Federal Energy Regulatory Commission (FERC) approved a system support resource (SSR) agreement for Ameren Missouri’s 1,195-MW Rush Island power plant, stating that the coal plant is necessary to maintain grid reliability.[1] The SSR agreement can be renewed annually, and the contract will be paid for by load-serving entities that benefit from keeping Rush Island open. In a separate decision, FERC said the proposed monthly payments Ameren Missouri would receive for running the plant need further review through a hearing process.[2] FERC also rejected Ameren Missouri’s request for an additional 0.5% return on equity (ROE) for cost recovery for keeping the plant open longer than expected, stating that the ROE adder only applies to transmission facilities.
The Rush Island Power plant was originally set to retire on September 1, 2022. Instead, Ameren Missouri now expects to keep it running until mid-2025 to support grid reliability. According to the Midcontinent Independent System Operator (MISO), retiring the coal plant could cause severe voltage stability problems, leading to cascading power outages. In MISO’s application for an SSR agreement, the grid operator identified four transmission upgrades that are needed to maintain voltage on the grid, with the last one expected to be online by June 2025. Potential renewable energy additions or demand-response programs wouldn’t be enough.
[1] https://elibrary.ferc.gov/eLibrary/filelist?accession_number=20221024-3065&optimized=false
[2] http://elibrary.ferc.gov/eLibrary/filelist?accession_number=20221024-3066&optimized=false
[USA] FERC approves $500K fine for ISO-NE over allegations it paid $100 million to nonoperating gas plant
According to an agreement approved on September 30, 2022, by the Federal Energy Regulatory Commission (FERC), ISO New England (ISO-NE) will pay a $500,000 fine to settle allegations that it violated market rules by allowing a 674 MW natural gas-fired power plant to collect money from consumers before the facility had produced any power.[1] The settlement between ISO-NE and FERC’s Office of Enforcement was approved by FERC commissioners in a 4-0 decision. The investigation, which took place over the last five years, found that ISO-NE issued over $104 million in payments to Salem Harbor Power Development LP, a subsidiary of Footprint, in 2017 and 2018 despite knowing that the company’s gas facility was not going to meet its expected commercial operating date. The Salem Harbor Generating Station was initially expected to enter commercial operation on May 31, 2017. However, it did not reach commercial operations until June 2018. The grid operator also withheld information about the facility from its independent market monitor.
In the agreement, ISO-NE agreed to the facts presented by FERC staff but “neither admits nor denies” that any violations occurred. The fine will be paid through a reduction in compensation for ISO-NE’s 10-person senior leadership team. The grid operator also agreed to invest up to $350,000 to bolster its compliance program to prevent future incidents.
[1] https://elibrary.ferc.gov/eLibrary/filelist?accession_number=20220930-3077&optimized=false
[USA] FERC approves extension for Mountain Valley pipeline
On August 18, 2022, the Federal Energy Regulatory Commission (FERC) extended the permit for the Mountain Valley natural gas pipeline project by four years.[1] The $6.6 billion project is being built by a joint venture of Equitrans Midstream, NextEra Energy, Consolidated Edison, AltaGas, and RGC Resources. The pipeline will run 304 miles from northwestern West Virginia to southern Virginia and deliver 2 billion cubic feet of gas daily to the Southeast. Construction on the project has been slowed by several court decisions rejecting federal permits. When FERC initially approved the pipeline in 2017, it said the project had to be operating by October 2020. However, in August 2020, FERC extended the permit deadline to October 13, 2022. With the most recent extension, the project must be completed by mid-October 2026. In its decision, FERC unanimously ruled that the basis for its findings in its initial 2017 approval remained the same. The commission rejected calls to conduct a supplemental environmental analysis. Equitrans now expects to complete the Mountain Valley project in the second half of 2023. Currently, the project is roughly 94% complete.
[1] https://elibrary.ferc.gov/eLibrary/filelist?accession_number=20220823-3076&optimized=false
[USA] More than 30 organizations urge FERC to create a strong transmission planning rule
On August 16, 2022, a day before the comment deadline on the Federal Energy Regulatory Commission’s (FERC) Notice of Proposed Rulemaking (NOPR) on Regional Transmission Planning and Cost Allocation and Generator Interconnection, more than 30 organizations wrote a letter in support of a strong new planning rule that helps strengthen the nation’s transmission network.[1] The NOPR, released in April 2022, proposed reforming both FERC’s Open Access Transmission Tariff and Large Generator Interconnection Agreement to fix what the commission saw as deficiencies in existing regional transmission planning and cost allocation requirements. As written, the NOPR would require public utility transmission providers to undertake long-term regional transmission planning and consider dynamic line ratings and advanced power flow control devices more.
Organizations that signed the letter include utilities, consumers, nongovernmental organizations, think tanks, labor groups, national trade associations, equipment providers, clean energy buyers, transmission developers, builders and operators, independent power producers, and environmental organizations. The organizations emphasized that a better planned and integrated power system would help both in terms of consumer savings and reliability of service. Additionally, greater national rulemaking could trickle down into helpful regionalization. “The ability to move power across large areas helps deliver low-cost renewable energy, which is what consumers, utilities, and states are procuring,” the letter said.
[1] https://acore.org/macro-grid-initiative-letter-under-ferc-transmission-nopr/
[USA] FERC approves ISO-NE plan to end MOPR
On May 27, 2022, in a 4-1[1] vote, the Federal Energy Regulatory Commission approved ISO New England’s (ISO-NE) plan to phase out its minimum offer price rule (MOPR) over two years.[2] A MOPR sets a floor price for bids in a capacity market to prevent resources from bidding artificially low prices. ISO-NE, which oversees grid operations in Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island, and Vermont, submitted the proposal to end its MOPR on March 31, 2022. ISO-NE proposed ending the MOPR in 2025. The transition will exempt up to 700 MW of qualified state-supported capacity (about 2,000 MW of nameplate capacity) from the MOPR over the next two capacity auctions. According to ISO-NE, adopting a two-year transition will help maintain reliability. The grid operator said that an immediate elimination of the MOPR could cause the retirement of existing capacity resources before state-sponsored resources are commercially available and able to replace the retiring resources.
FERC said the proposal “strikes a reasonable balance among the different considerations raised here, including efforts to ensure resource adequacy, minimize potential adverse effects on reliability that could result from an immediate change to the market rules, promote market certainty, and limit the costs associated with over-mitigation.” In his concurring statement, FERC Chairman Richard Glick said he wished the grid operator had proposed ending the MOPR immediately but stated that he understood that the New England states did not oppose ISO-NE’s proposal. He also urged ISO-NE to quickly develop “a capacity accreditation proposal to ensure that the [forward capacity market] is accurately valuing the capacity contribution of all resources.”
[1] Chairman Richard Glick (D), Commissioner Allison Clements (D), Commissioner Willie Phillips (D), and Commissioner Mark Christie (R) voted for the proposal. Commissioner James Danly (R) dissented.
[2] https://elibrary.ferc.gov/eLibrary/filedownload?fileid=8af6af9e-2c5f-c7bf-92cd-81084af00000
[USA] FERC rejects MISO self-fund rule for merchant HVDC line upgrades
On April 29, 2022, the Federal Energy Regulatory Commission (FERC) voted 4-1 to reject the Midcontinent Independent System Operator’s (MISO) proposal to allow incumbent transmission owners in the region to pay for and profit on grid updates needed for merchant high-voltage direct current (HVDC) lines.[1] The proposal, filed in November 2021, centered around upgrades needed for merchant HVDC lines, which are paid for by entities using the line rather than utility customers. The proposal built on a similar FERC decision in 2019 that restored transmission owners’ option to self-fund network upgrades before interconnection customers are offered the chance to finance it. MISO argued that merchant HVDC line-related upgrades should be treated similarly to interconnection-related network upgrades because both types of projects require upgrades that would not be needed if not for the projects.
In its decision to reject MISO’s proposed self-fund rule, FERC said that MISO failed to show how the expansion of the self-fund rule to merchant HCDV line upgrades wasn’t discriminatory. According to FERC, the upgrades are not identical because MISO would not offer all available funding options to merchant HVDC developers when they haven’t secured injection rights[2]. Commissioner James Danly (R) dissented, saying that the other commissioners’ decision “denies the transmission owners’ right to receive a return on and of the capital costs of network upgrades, necessary upgrades, and transmission owner system protection facilities.”
[1] https://elibrary.ferc.gov/eLibrary/filedownload?fileid=2b8979ce-11e6-cb9e-856b-8077d7500000
[2] Injection rights are rights to inject capacity at a specified point on the transmission system.
[USA] ACPA and RENEW complaint claims ISO-NE’s market rules are biased toward natural gas generators
In a complaint filed with the Federal Energy Regulatory Commission (FERC) on March 15, 2022, the American Clean Power Association (ACPA) and RENEW Northeast argue that ISO New England (ISO-NE) gives some natural gas-fired power plants an unfair advantage in the grid operator’s capacity and operating reserves markets by assuming that these resources will always have fuel supplies and be able to operate.[1] By comparison, ISO-NE considers how much capacity other resource types can consistently deliver, resulting in renewable resources having accredited capacity below their nameplate capacity. The complaint says that about 9.2 GW of pipeline-supplied gas-fired capacity in New England lacks a backup fuel source. This equals about 28% of the capacity that cleared the grid operator’s most recent capacity auction. The renewable energy trade groups claimed that the grid operator’s preferences for natural gas-fired generators lowers capacity, real-time reserve, and real-time energy prices, thereby creating barriers to renewable energy and energy storage facilities.
ISO-NE is starting a stakeholder process to consider how Effective Load Carrying Capability (ELCC) techniques could be used in quantifying resource capacity contributions to regional resource adequacy, which could address some of the complaint’s concerns. However, the new methodology would be in place until June 2028, so the complaint requests that FERC require ISO-NE to change its capacity accreditation rules by mid-2027.
[1] https://cleanpower.org/wp-content/uploads/2022/03/2022-03-15-Full-complaint-FINAL.pdf
[USA] FERC extends emergency certificate for Spire STL pipeline
On December 3, 2021, the Federal Energy Regulatory Commission (FERC) issued a temporary certificate allowing the Spire STL pipeline to continue operating through winter.[1] The 65-mile pipeline runs from Illinois to the St. Louis, Missouri area to serve Spire Missouri customers. Spire STL has been operational since 2019, but in June 2021, the D.C. Circuit vacated the pipeline’s certificate of public convenience and necessity. The court ruled that FERC had failed to adequately assess the need for the Spire pipeline. FERC issued a temporary certificate in September 2021, which was set to expire on December 13, 2021. Prior to FERC’s December decision, Spire had warned that shutting off the pipeline would lead to 400,000 St. Louis area customers experiencing extended loss of service this winter. The new temporary certificate allows the pipeline to remain in service while FERC decides how to proceed. The temporary certificate bars the company from engaging in construction activities or expanding service but allows the pipeline to operate under the rates that are currently in effect.
FERC’s decision came right after Spire STL Pipeline LLC petitioned the Supreme Court to review the D.C. Circuit’s ruling.[2] In its appeal, the company argued that the D.C. Circuit should not have revoked the permit in light of the "dangerous, and potentially fatal, consequences" of the decision.
[1] https://www.ferc.gov/news-events/news/ferc-extends-temporary-operations-spire-stl-pipeline
[2] https://missouriindependent.com/2021/12/03/spire-stl-pipeline-appeals-to-u-s-supreme-court-to-overturn-self-dealing-ruling/
[USA] SEEM goes into effect following FERC deadlock
The Southeast Energy Exchange Market (SEEM), a proposed trading platform for 15 utilities[1] in the Southeast, became operational on October 12, 2021, after the Federal Energy Regulatory Commission deadlocked 2-2 on whether to approve it.[2] The proposal was enacted by default because the four-member commission didn't act within the 60-day limit set by section 205 of the Federal Power Act (FPA). The commission could not agree on the lawfulness of the change, according to FERC’s notice. The proposal was initially filed with FERC in February 2021 and has since been amended twice. According to the utilities backing the plan, SEEM will set up an automated trading platform to buy and sell excess wholesale energy every 15 minutes, with the aim to reduce costs to customers and boost renewable energy resources. The platform is expected to produce up to $50 million in annual savings in the near term. SEEM expects to be operational in 11 states by mid-2022. Rehearing requests for the FERC decision are due in 30 days and the commission will have another 30 days to respond to them. FERC's commissioners will explain their views on the SEEM proposal in upcoming filings.
[1] The full list of expected members is: Associated Electric Cooperative, Dalton Utilities, Dominion Energy South Carolina, Duke Energy Carolinas, Duke Energy Progress, Georgia System Operations Corporation, Georgia Transmission Corporation, LG&E and KU Energy, MEAG Power, NCEMC, Oglethorpe Power Corp., PowerSouth, Santee Cooper, Southern Company and TVA.
[2] https://southeastenergymarket.com/wp-content/uploads/Notice-re-SEEM-Effective-by-OOL-10.13.2021-ER21-1111.pdf
https://southeastenergymarket.com/wp-content/uploads/NR-SEEM-FERC-Approval-2-2-vote-FINAL-101321.pdf
[USA] Spire asks Supreme Court to pause Missouri pipeline shut down
On October 4, 2021, Spire STL Pipeline LLC requested the Supreme Court stay an order from the U.S. Court of Appeals for the District of Columbia Circuit shutting down the Spire STL pipeline.[1] The 65-mile pipeline runs from Illinois to the St. Louis, Missouri area to serve Spire Missouri customers. The pipeline has been operational since 2019 and is a rare case of federal courts vacating a pipeline’s service after it is operational. In June 2021, the D.C. Circuit vacated the pipeline’s certificate of public convenience and necessity, which was issued by the Federal Energy Regulatory Commission (FERC) in 2018. The court ruled that FERC had failed to adequately assess the need for the Spire pipeline. Following this, Spire obtained a temporary certificate from FERC in September 2021 to operate the pipeline until December 13, 2021, while regulators consider the next steps for the pipeline. On October 1, 2021, the D.C. Circuit declined Spire's request to delay its issue of a formal shutdown mandate on Oct. 8.
In its application for an emergency stay from the Supreme Court, Spire warned that shutting off the pipeline will lead to 400,000 St. Louis area customers experiencing extended loss of service when FERC's temporary permission expires this winter. Spire argued that there is no guarantee that FERC will keep the temporary certificate in place or offer an extension. The company’s application comes as it prepares for a broader Supreme Court challenge of the D.C. Circuit’s decision.
[1] https://www.supremecourt.gov/Search.aspx?FileName=/docket/docketfiles/html/public%5C21a56.html