[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] MISO opens energy and operating reserves markets to storage

On September 6, 2022, the Midcontinent Independent System Operator (MISO) announced that Electric Storage Resources (ESRs) are now eligible to participate in its energy and operating reserve markets for the first time.[1] According to the press release, the new resource type has operational characteristics that support reliability and resilience. ESRs include batteries, pumped storage facilities, and compressed air energy storage. Although a “nominal” amount of storage capacity is currently registered, MISO’s generator interconnection queue shows that more than 150 energy storage projects (about 13,300 MW of capacity) are in development. “We are excited to see this space grow with increasing member interest and participation, particularly as we continue to adapt to the accelerating resource transition,” said Jessica Lucas, MISO’s executive director of system operations. “With the introduction of Electric Storage Resources to our market portfolio, we will continue to position MISO’s grid and its members for the Grid of The Future.”

The integration of these resources follows the Federal Energy Regulatory Commission’s (FERC) Order 841, which directed grid operators to remove barriers to market participation for storage resources. MISO had previously requested to delay the compliance deadline until 2025, but FERC denied that request.

[1] https://www.misoenergy.org/about/media-center/miso-introduces-electric-storage-resource-to-market-portfolio/

[USA] Report: ISO-NE reserve margin may need to rise up to 300% by 2040 as more renewables are added

According to a report released by ISO New England (ISO-NE) on July 29, 2022, the grid operator’s reserve margin may need to increase from 15% to 300% by 2040 under some scenarios as more renewables are added to the grid and dispatchable generation is retired.[1] The Future Grid Reliability Study (FGRS), requested by New England Power Pool stakeholders, modeled a variety of decarbonization scenarios through 2040. The deep decarbonization scenario is based in part on assumptions used in Massachusetts’ 2050 Deep Decarbonization Roadmap Study. It includes the addition of 16 GW of offshore wind, 28 GW of solar, 600 GW of battery storage systems, and new transmission. Under this scenario, heating and transportation make up 20% and 18.6% of the grid operator’s total load, respectively.

In a modified deep decarbonization scenario where reliability criteria are met using only solar, wind, and storage, the transmission system would be challenged and would require 89,900 MW of those resources. Currently, ISO-NE has only 5,600 MW. The report concluded that ISO-NE “may require a significant amount of gas or stored fuels to support variable resources.” The report also found that the addition of new transportation and building electrification loads as part of decarbonization efforts will shift the grid to a winter-peaking system and require changes to planning processes. ISO-NE plans to issue a trio of appendices later in 2022 to address production cost, ancillary services, and resource adequacy. The second phase of the FGRS will consider the role of wholesale electricity markets.

[1] https://www.iso-ne.com/static-assets/documents/2022/07/2021_economic_study_future_grid_reliability_study_phase_1_report.pdf

[USA] MISO board approves $10.3 billion portfolio of long-range transmission projects

On July 25, 2022, the Midcontinent Independent System Operator (MISO) Board of Directors announced that they had approved a portfolio of long-range transmission projects for the Midwest subregion.[1] The $10.3 billion investment includes 18 transmission projects. According to MISO, this Tranche 1 portfolio is the first of four planned tranches in its Long-Range Transmission Planning (LRTP) process. The grid operator plans to follow this portfolio with another set of transmission projects for its northern and central areas, one for its southern region, and one to increase transmission capacity between its northern and southern areas. The projects are necessary to begin the integration of new generation resources outlined in MISO member and state plans as well as increase resiliency in the face of severe weather events.  

Analyses indicate that the Tranche 1 benefits will exceed costs, with a benefit-to-cost ratio of at least 2.2 for all resource zones in the grid operator's Midwest subregion. Benefits include congestion and fuel savings, avoided capital costs of local resource investment, avoided transmission investment, resource adequacy savings, avoided risk of load shed, and decarbonization. MISO used existing transmission corridors to plan this Tranche 1, which reduces the impact on local areas and communities, lowers construction costs, and shortens implementation time.

[1] https://www.misoenergy.org/about/media-center/miso-board-approves-$10.3-in-transmission-projects/

[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] 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] D.C. Circuit orders FERC to reinvestigate alleged market manipulation in MISO

On August 6, 2021, the U.S. Court of Appeals for the District of Columbia Circuit ruled that the Federal Energy Regulatory Commission (FERC) must reinvestigate alleged market manipulation in the 2015 capacity auction for the Midcontinent Independent System Operator (MISO).[1] MISO is the second largest regional transmission operator (RTO) in the U.S. and spans 15 states.[2] During the 2015 auction, capacity prices in the zone covering most of Illinois were 50 times higher than those across the rest of MISO. In their complaints to FERC, the state of Illinois, consumer advocacy group Public Citizen, and others allege that Dynegy Inc., which had just acquired four new power plants in the region, was responsible for the price spike. According to the state, the region in MISO was unable to meet its reliability requirements without purchasing capacity from Dynegy due to the company’s purchase of the power plants. Therefore, the clearing price was artificially inflated, costing the average residential customer an additional $131 in electricity costs in the 12 months that followed the capacity auction.

FERC dismissed the complaints in 2019 and dismissed the requests for rehearing in 2020, stating that the auction clearing price was just and reasonable. Then Commissioner and now-Chairman Richard Glick dissented in both orders, saying that the Commission did not adequately examine the complaints.[3] In response to FERC’s dismissal of the complaints, Public Citizen appealed FERC’s decisions to the D.C. Circuit. Similar to Chairman Glick’s previous findings, the three-judge panel found that the majority of commissioners failed to explain why the claims should be dismissed.

[1] https://www.cadc.uscourts.gov/internet/opinions.nsf/418CFCD8F8D7ED6F85258729004F14E5/$file/20-1156-1909243.pdf

[2] MISO covers all or a portion of Arkansas, Illinois, Indiana, Iowa, Kentucky, Louisiana, Michigan, Minnesota, Mississippi, Missouri, Montana, North Dakota, South Dakota, Texas, and Wisconsin

[3] https://www.ferc.gov/news-events/news/appellate-court-remands-miso-2015-capacity-auction-order-ferc

[USA] Coalition asks Congress for cost analysis of RTOs

A coalition of consumer advocates, pro-market groups, and others sent a letter on July 8, 2021, requesting that Congress direct the Government Accountability Office (GAO) or other independent oversight organization to conduct a first-of-its-kind cost analysis of organized power markets.[1] The coalition is spearheaded by the Electricity Consumers Resource Council (ELCON) and includes groups such as Public Citizen, Energy Choice Coalition, and R Street Institute. In 1999, the Federal Energy Regulatory Commission (FERC) encouraged participation in organized markets under Order 1000. As a result, about two-thirds of the U.S. by area is now served by Regional Transmission Organizations and Independent System Operators (collectively RTOs). In their letter, coalition members expressed concern that while FERC has promoted RTOs based on the idea that they benefit customers, the commission has not initiated a full-scale, independent study to ensure that RTOs provide reliable and affordable electricity. The coalition is requesting an analysis of the cost impacts of federal policy on market structure, particularly the net benefits to retail consumers of forming RTOs. The study should examine how existing RTO markets have impacted the cost of electricity for retail consumers. The coalition also asked that the study explore the impacts of wholesale market structures on reliability and develop a set of best practices for RTO expansion.

[1] https://elcon.org/independent-study-of-the-cost-of-electricity/

[USA] ERCOT report finds weather-related issues were the primary cause of February outages

On April 6, 2021, the Electric Reliability Council of Texas (ERCOT) sent its preliminary report to the Texas Public Utility Commission (PUC) on the causes of generator outages and derates during the February 14-19, 2021 extreme cold weather event.[1] ERCOT’s report follows initial requests for information from generators about why so much generation went offline during the cold weather event. The report found that most of the outages during the event were weather-related outages, which ERCOT defined as outages “explicitly attributed to cold weather,” such as frozen or flooded equipment. During the February 14-19 time period, weather-related issues caused 54% of generator outages, equipment failures caused 14% of outages, and fuel limitations caused 12% of outages. ERCOT estimates that approximately 51,173 MW were forced offline during that period, which is slightly lower than the original estimate of 52,277 MW. ERCOT is still waiting on data for February 10-13, 2021. The grid operator anticipates completing a full report on the event by the end of August 2021.

[1]http://www.ercot.com/content/wcm/lists/226521/51878_ERCOT_Letter_re_Preliminary_Report_on_Outage_Causes.pdf

[USA] Texas governor declares billing errors an emergency matter

On March 9, 2021, Governor of Texas, Greg Abbott (R), announced that the correction of billing errors is an emergency matter to be considered immediately by the Texas legislature.[1] The announcement comes after regulators at the Texas Public Utility Commission (PUC) declined on March 8, 2021 to direct the Electricity Reliability Council of Texas (ERCOT) to retroactively reprice its artificially inflated prices during the February 2021 cold weather event.[2] The commissioners expressed concern that there was too much uncertainty in how customers might be impacted by directing ERCOT to reverse its pricing. The decision goes against the recommendation of Potomac Economics, the region’s independent market monitor (IMM). According to the IMM, ERCOT should have immediately lowered prices after load shed instructions ended on February 17, 2021, but prices remained high through February 19, 2021 which cost the market $16 billion over the course of 32 hours. On March 8, 2021, Texas Lt. Gov. Dan Patrick called on the PUC to retroactively change the prices from that time period. On the same day, Texas PUC Commissioner Shelly Botkin resigned effective immediately. Her departure comes just a week after the resignation of Chair DeAnn Walker and leaves the commission with just one member left, Chair Arthur D’Andrea.

[1] https://www.utilitydive.com/news/texas-puc-loses-2nd-commissioner-as-lt-gov-presses-ercot-to-correct-16b/596378/

[2] https://www.utilitydive.com/news/texas-regulators-decline-to-act-after-market-monitor-reports-16b-of-inapp/596252/

[USA] ERCOT Board of Directors fires CEO after Texas power outages

The Electric Reliability Council of Texas' (ERCOT) Board of Directors voted on March 4, 2021 to issue a 60-day termination notice for CEO Bill Magness.[1] In a statement, the Board of Directors state that they will "begin an immediate search for a new President and CEO.” The vote comes just weeks after the state experienced widespread power outages during an extreme cold weather event in February 2021. In addition to this news, the Chair of the Public Utility Commission of Texas (PUCT), DeAnn Walker, resigned on March 1, 2021. In her resignation letter, Walker stated that she "accepted [her] role in the situation," but that others, including the Texas Railroad Commission, ERCOT, and the legislature, should accept blame as well.

On March 4, 2021, the chairman of the House Oversight and Reform Subcommittee on the Environment, Representative Ro Khanna (D-California), sent a letter to CEO Bill Magness that requested documents regarding ERCOT's lack of winter storm preparation.[2] In his letter he stated, "The Subcommittee is concerned that the loss of electric reliability, and the resulting human suffering, deaths, and economic costs, will happen again unless ERCOT and the State of Texas confront the predicted increase in extreme weather events with adequate preparation and appropriate infrastructure."

[1] https://www.utilitydive.com/news/texas-head-utility-regulator-deann-walker-resigns-authority-ercot-blackouts/595932/

[2] https://oversight.house.gov/sites/democrats.oversight.house.gov/files/2021-03-03.Khanna%20to%20ERCOT%20re%20Winter%20Storms%20in%20Texas.pdf

[USA] MISO and SPP launch joint study to address interconnection challenges

On September 14, 2020, two regional transmission organizations (RTOs), the Midcontinent Independent System Operator (MISO) and Southwest Power Pool (SPP), announced a year-long transmission study to address historical challenges facing customers in areas where the RTO boundaries connect, known as seams, by identifying comprehensive, cost effective, and efficient upgrades.[1] Seams are the invisible boundaries between two RTO control areas, systems, and markets. The primary issue with seams is that there are inherent differences in how the RTOs create market rules or designs which leads to inefficiencies at the seams that prevent the economic transfer of capacity and energy between neighboring RTOs. One of the biggest issues this study seeks to address is the large amount of renewable energy that cannot be developed due to the issues inherent at seams.

The study will focus on solutions that MISO and SPP believe will offer benefits to both their transmission customers and end use consumers of RTO member companies. While the RTOs’ have a Joint Operating Agreement, which allows them to work through reliability issues, current processes do not include coordinated evaluation of benefits, or allocation of cost, to both load and interconnection customers. The study is expected to formally begin in December 2020 and will include several joint stakeholder meetings to provide updates on the findings. Any projects identified by the joint study will need to be approved by each RTOs’ respective Board of Directors before moving ahead.

[1] https://www.misoenergy.org/about/media-center/miso-and-spp-to-conduct-joint-study-targeting-interconnection-challenges/