The Fifth Circuit Court of Appeals told FERC Wednesday that it must explain why it has yet to rule on disputes between state regulators and Entergy that have been pending for up to six years.
The Louisiana Public Service Commission has filed several FERC complaints against Entergy’s (NYSE:ETR) System Energy Resources, Inc. (SERI), which runs plants jointly owned by the firm’s different utilities, notably the Grand Gulf Nuclear Station in Mississippi.
The PSC, along with retail regulators in Arkansas, Mississippi and New Orleans, have submitted several complaints in recent years challenging SERI’s rates — the oldest dating back to January 2017 (EL17-41) and the newest in 2021 (EL21-56). (See Entergy Regulators Ask FERC to Settle Grand Gulf Dispute.)
“The LPSC argues that consumers are over-paying SERI by about $4 million per month due to the activity alleged in one complaint,” a three-judge panel said. “Another complaint alleges that consumers in Louisiana unjustly paid a further $360 million in costs for Grand Gulf.”
The Louisiana commission went to the court to complain that FERC was taking too long in the proceedings, and its inaction was “causing irreparable injury to consumers.”
While Congress never imposed firm deadlines for FERC to resolve Section 206 complaints under the Federal Power Act, “it certainly anticipated greater alacrity than this,” the court said.
The Regulatory Fairness Act of 1998 holds that FERC is supposed to give Section 206 complaints the same priority as Section 205 filings, which come with firm deadlines. FERC is supposed to explain why it has not ruled on a complaint after 180 days, but it regularly ignores that requirement and did so in the Louisiana PSC’s complaints, the court said.
“Despite the RFA’s guidance, Section 206 proceedings before FERC appear to take much longer, costing consumers hundreds of millions of dollars and pressuring parties to settle,” the court said. “The remaining LPSC complaints have gone four to six years without resolution.”
FERC argued against any requirement to act on the case, saying it would allow it to skip the queue of other items pending before it. But the court said that argument concedes that the federal regulator has other Section 206 proceedings that have been pending even longer, meaning many consumers have been paying unjust rates, without hope for a refund, for more than six years.
FERC must make a filing within 21 days explaining why it has taken so long to deal with the regulators’ complaints.
The U.S. economy is experiencing its first taste of high inflation in decades, and that is contributing to delays in new renewable power projects, experts told the Energy Bar Association Northeast Chapter’s Winter Summit on Wednesday.
The 1970s was the last time U.S. industry had to deal with very serious inflation, and it led to major changes in the regulation of the power sector, said the Brattle Group’s Peter Fox-Penner.
This round of inflation seems to be less serious than that of the 1970s, he said. “But it’s still a profoundly impactful one, and the first one in 30 years — in a very, very different industry.”
The two key characteristics of whether industries are impacted by inflation is their ability to set prices and how capital-intensive they are, said 18th Square Managing Member Walter Hopkins, who has advised offshore wind developers on how to bid for power purchase agreements.
Offshore wind farms involve huge upfront investments, which are only estimates when they bid for a contract, and that is paid for by long-term contracts that are include some elements of fixed price.
“Winning an offshore wind project in 2021, for instance, is a bit like if you agreed to pay for a bond that would give you a fixed stream of revenue,” Hopkins said. “But you didn’t know what the price was; you’re going to pay for the bond; and you’re going to have to pay for it a couple years later after inflation kicked in, and the costs of the project rise with inflation.”
That model used to work in the industry, as developers would sign a contract and then benefit from the declining costs of turbines, but with rising costs across the board to build anything, that is no longer the case, he added.
Eversource Energy (NYSE:ES) has signed contracts for offshore wind that are meant to see delivery start later this decade, said its vice president of energy supply, James Daly.
“It’s public information that a number of these projects have stated that they cannot close financing on their current contract prices,” Daly said. “So not surprisingly, developers are citing supply chain, interest rates, commodity and labor costs, as well as uncertainty on regulations stemming from, believe it or not, the Inflation Reduction Act.”
The IRA is meant to offer renewable projects more generous subsidies, but it is still unclear exactly how the law will be implemented, and that adds to uncertainty on project’s ultimate costs, he added.
Massachusetts offshore wind farms have asked the Department of Public Utilities to either change or let them out of contracts they have signed with Eversource and other utilities. Commonwealth Wind, a 1,232-MW project owned by Avangrid, has said it cannot make the deal it signed work and wants to rebid in a new round. Other wind farms have said they face the same challenges because of inflation.
The Mayflower Wind Project, a joint venture between Shell and Ocean Winds (another jointly owned firm from EDP Renewables and ENGIE), won changes for a contract for 804 MW it signed with Eversource and other utilities in a DPU order issued Dec. 30. The project is changing its point of interconnection to the retired Brayton Point Plant and locking in a 30% investment tax credit.
Eversource is not that interested in repricing contracts now, which would only serve to lock in high prices, said Daly. Doing so would be similar to what California did during its energy crisis, when the state signed many high-priced deals to secure supplies to stop rolling blackouts, and that led to decades of litigation, he added.
“It will take some time to work through this, [but] we are seeing a turning of a corner,” said Daly.
Inflation seems to be slowing, supply chains are working themselves out, and the technology is still improving with developers able to use larger, more efficient turbines to build the wind farms than they initially planned for, he added. But some adjustments to state policy might be needed to reflect the new, harsher economic reality.
“When the current targets were set, there was no COVID on the horizon,” said Daly. “And since then we’ve had fairly significant supply chain disruptions.”
Cogentrix Energy Power Management Vice President of Regulatory Affairs Christopher Sherman agreed. His company, a subsidiary of the investment firm the Carlyle Group, owns natural gas plants but is increasingly focused on developing storage.
The largest storage projects Cogentrix is developing are about 400 MW, but they will not be ready to connect to the grid for four years, he said.
“And yet in some of those markets, the state policy pressure is to close those dispatchable resources before that,” Sherman said. “So ultimately, probably what happens is you have increased consumer cost, and you possibly have reliability issues.”
The time frame for some of the transition away from traditional, dispatchable generation needs to be adjusted to reflect the current market conditions, he added.
FERC on Thursday conditionally accepted a compliance filing by Southern Company revising its formula rate protocols, which FERC said are unjust and unreasonable, and directed the utility to provide a further compliance filing in 60 days on remedying the commission’s concerns (ER22-2642).
Southern had submitted its compliance filing in July 2022 on behalf of its subsidiaries Alabama Power, Georgia Power and Mississippi Power in response to a FERC show-cause order, issued last March, that raised concerns about the formula rate protocols filed in Southern’s tariff. (See FERC Issues Southern Show-cause Order on Rate Protocols.)
The commission ordered the utility to address deficiencies with the protocols in three areas: scope of participation; transparency of information exchange; and ability of customers to challenge transmission owners’ implementation of the formula rate.
Utility Proposed Multiple Changes
In its filing, Southern updated the protocols to clear up each issue.
Regarding the scope of participation, FERC had directed Southern to “provide a definition of the ‘interested parties’ that can participate in customer meetings, information exchange, and challenge procedures.” Southern proposed a definition that would include “customers under the tariff, state utility regulatory commissions, consumer advocacy agencies, and state attorneys general.” It said the wording fit with established commission precedent.
For the information transparency issue, FERC said that interested parties might not be able to access information that would help them evaluate the correctness of the formula rate. In response, Southern suggested adding language that would require its annual informational filings and true-up filings to:
provide formula rate calculations and their inputs, along with supporting documentation;
specify the information that enables interested parties to replicate the calculation of the formula results;
identify all material adjustments made to relevant data in determining formula inputs; and
provide underlying data for formula rate inputs that require greater granularity.
Southern also proposed revisions that would allow interested parties to request information and documents necessary to determine the effect of an accounting change, to see if the annual filing includes appropriate data, and to assess the prudence of costs and expenditures. Additional new language would provide for annual meetings regarding the informational filings and joint meetings with other transmission owners. It would also address reorganizations and mergers that affect the inputs to the formula rate.
Addressing other FERC concerns, Southern added language detailing the issues that can be challenged during the review period, procedures for formal and informal challenges, protocols for appointing representatives to work with parties that submit a challenge, and processes for elevating an informal challenge to a formal one.
Clarification Still Needed
FERC accepted most of Southern’s revisions but identified remaining deficiencies that still must be addressed.
The commission noted that the language related to posting of the annual update filings does not include a provision for notification of the filing via email and ordered Southern to add language to that effect.
FERC also said Southern’s proposed true-up filing timeline seemed to require the filings be published by May 1 of the year following the relevant rate year. The proposed protocols, however, require interested parties to file informational requests by Aug. 1 of the rate year. That would be impossible if the filing was not available until the following year, FERC said. The commission required Southern to correct the error.
Regarding the challenge procedures, FERC said that “the lack of provisions in Southern’s protocols to post all information requests, responses to information requests, informal challenges, and informal challenge resolutions [online] could limit” the ability of interested parties to “fully participate in the formula rate process.” It ordered the utility to add a requirement that all relevant information be made available online.
Finally, the commission said that Southern’s proposed timelines for making formal challenges “may not allow interested parties adequate time” to respond. It directed Southern to “propose a date for any interested party to submit an informal challenge … as well as … a formal challenge … after being given a reasonable period of time to review Southern’s responses to the informal challenges.”
The commission set 15 days as the minimum acceptable time between responses to information requests and informal challenge submission deadlines, and 31 days between responses to informal challenges and formal challenge submission deadlines.
Southern is required to submit its compliance filing within 60 days of the date of the order. The original compliance filing is conditionally accepted, effective July 23, 2022, pending its receipt.
The Texas Public Utility Commission on Thursday unanimously agreed to the principles necessary to replace ERCOT’s energy-only market with a performance credit mechanism (PCM), sending the proposal to an uncertain fate in the legislature.
Chair Peter Lake guided the commission through a discussion and then an editing session of his “underlying foundation” for the mechanism. The commissioners summarized the proposal in a four-page memo attached to the order (Project 53298).
The PCM has been criticized by some as a sop to the market’s generators. It would reward them with credits based on their performance during a determined number of scarcity hours. Those credits must be bought by load-serving entities, based on their load during those same hours, or exchanged by LSEs and generators in a voluntary forward market.
The commission ordered PUC staff and ERCOT to delay implementation of the PCM “until such time as the 88th Legislature has had an opportunity to render judgment on the merits of the PCM and/or establish an alternate solution.”
The recommendation fulfills the PUC’s statutory obligation under Senate Bill 3, enacted following February 2021’s deadly winter storm. It completes a process that began in December 2021 and involved work sessions, stakeholder feedback and industry criticism. (See Proposed ERCOT Market Redesigns ‘Capacity-ish’ to Some.)
But State Sen. Charles Schwertner (R), author of SB3 and chair of the Business and Commerce Committee, tweeted that the PUC “chose to ignore the clear direction of the [Texas Legislature] by voting to replace the state’s competitive energy market with a costly and complex proposal that is unlikely to deliver the dispatchable generation resources that Texas needs. It’s unacceptable.”
In a letter to the commission last week, Schwertner said it would be “imprudent” for the commission to act without the legislature’s “consultation and collaboration.” (See PUC Closes in on ERCOT’s Market Redesign.)
The commission’s revised memorandum said it would open a project “to evaluate and establish an appropriate reliability standard” based on the PCM concept outlined in a report by consultants Energy and Environmental Economics (E3). The firm evaluated six alternatives but did not recommend the PCM, saying it would be too complex and costly, estimating the credits could cost retailers $5.7 billion a year. (See Proposed ERCOT Market Redesigns ‘Capacity-ish’ to Some.)
“Once implementation is launched at some point in the future subject to consideration and direction of the 88th Legislature, the commission will develop an implementation plan,” the PUC said in its memo.
It said the plan will identify which entity — including among the commission, ERCOT and the Independent Market Monitor — will be responsible for analysis related to each of 17 “decision points,” including such details as the PCM compliance period and the number of hours per compliance period.
“For decision point items relegated to ERCOT analysis, the commission will direct ERCOT to undertake stakeholder evaluation subject to ERCOT board vote for ultimate recommendation for commission approval,” the commission said. “The ultimate authority for all of these and any additional decision points lies with the commission.”
The commission also tasked ERCOT with evaluating “bridging options” to retain existing assets and build new generation until the PCM can be fully implemented. It said the grid operator should report at the commission’s Jan. 26 open meeting with a proposed date for delivering a report detailing the options ERCOT considered, its board’s preferred solution and implementation steps.
“I think this reflects a deliberative process on the part of the commission,” Commissioner Will McAdams said. “I said a year and a half ago that I think our finest hour is to come, and this is part of it. It’s a good product, and we need to be able to defend it.”
“It was difficult to know what they were talking about,” Katie Coleman, who represents Texas Industrial Energy Consumers, said after the meeting but before the edited memo was posted. “The PCM they voted on today is not the PCM in [the consultant’s November] report.”
Coleman, who has testified several times before lawmakers and the commission about market designs, noted various legislative committees have requested in multiple hearings that they be given a construct they can consider.
“They’re trying to redesign a market that’s been in place for two decades on the fly in an open meeting. It needs a lot more work and thought than what’s been put into it so far,” Coleman said. “This proposal … seems to have changed substantially behind closed doors since [November].
“All of the things they discussed today are hallmarks of a capacity market. It’s turning into a game of semantics,” she added.
Stoic Energy’s Doug Lewin labeled the mechanism a “Pretty (much a dressed up, overcomplicated) Capacity Market.”
“ERCOT will have a capacity market replacing the only competitive energy market in the U.S.,” Demand Control 2 founder Chris Hendrix tweeted. Demand Control works with market participants to help them access the wholesale market.
“My other concern with pushing some decisions to ERCOT is that Chairman Lake and the ERCOT board and senior staff do not have any retail electricity expertise,” he told RTO Insider.
TIEC last week asked the PUC to reconsider its December order approving ERCOT’s amended and restated bylaws. The changes limited the ability of corporate members and market participants to recommend policy and procedural changes and to vote on governance matters. (See ERCOT Board of Directors Briefs: Dec. 19-20, 2022.)
Demand Control 2, San Antonio’s CPS Energy and generation investor Eolian on Tuesday also filed a joint rehearing request with the PUC (54444).
The Texas Association of Manufacturers said it was “concerned with today’s action by the PUC to approve a novel proposal that is not well understood, and has not been modeled, but appears to be designed to ensure a certain profit level for existing generation.”
The group has proposed additional state-backed financing for dispatchable development, temporary property tax cuts for new or modernized dispatchable facilities and a reliability service that “directly rewards” new, flexible generation. “Specifically, we support proposals that ensure market revenues would remain performance-based, consistent with the current deregulated market design, and would avoid a government-mandated capacity market or other similar electricity taxes or fees to support incumbent generators,” it said.
The Texas Competitive Power Advocates, representing large generators that have promised to build 4.6 GW of additional capacity if the PCM is adopted, commended the commission’s work. In a statement, Executive Director Michele Richmond said the mechanism will make it “economically viable for companies to invest in the new dispatchable generation needed during periods of low renewable output in ERCOT.”
“The PCM builds reliability into the successful competitive market in Texas,” Richmond said. “Paying for the reliability that ERCOT needs to power Texas when the wind isn’t blowing and the sun isn’t shining, but without paying resources for merely existing.”
PUC Coalesces Around PCM
The commissioners signaled their intentions in a filing made Wednesday evening. Lake, McAdams and Kathleen Jackson expressed their outright support for the mechanism, but Lori Cobos and Jimmy Glotfelty offered a little pushback.
“My hesitation with the [PCM] is … we will shift up to $5 billion per year more for something we are getting today: a reliable system. Rising and falling prices are not inherently crisis-based models, but economic principles,” Glotfelty wrote, referencing Lake’s frequent comment that “the cure for high prices is high prices.”
“Over the last 25 years, high prices have led to new investment in transmission and generation all over this state to the benefit of consumers and the environment,” Glotfelty added. “Our ERCOT market has become, arguably, almost too efficient for the value of this much needed commodity.”
During Thursday’s work session, Glotfelty pushed to include evaluating best practices to mitigate market manipulation and guarding against self-dealing and market power abuse in the centrally cleared market.
Cobos focused her comments on “near-term actions to help retain our existing long-duration, dispatchable thermal generation fleet” needed to maintain reliability during multiday extreme weather events. She pushed for replacing reliability unit commitment practices and letting the operating reserve demand curve work “to send market signals for new dispatchable generation investment.”
FERC on Thursday approved the New York Power Authority’s transmission rates for the Smart Path Connect transmission project (SPCP) after the utility showed it received state approval for the project (EL22-15-001, ER22-1014-002).
The commission had approved NYPA’s request fthe abandoned plant incentive (API) in March 2022 — as well as a 50-basis-point return on equity adder and performance-based ROE incentive later in July — but on the condition that the New York Public Service Commission grant the project a certificate of environmental compatibility and need, and approve its environmental management and construction plan (EMCP). These approvals, FERC said, would show the project addresses reliability and congestion, required for the incentives under Federal Power Action 219.
The PSC granted the project, which aims to rebuild about 100 miles of old 230-kV transmission lines in northern New York as 345 kV, the certificate in August 2022 (21-T-0340). But NYPA told FERC that the New York commission has only approved an EMCP for part of the project.
“NYPA explains that, because of the expedited nature of the project, and in consultation with staff from the New York Department of Public Service, the EMCP approval process for NYPA’s part of the project was broken into two segments to enable a timely start to construction of the project,” FERC said in its order. NYPA expects approval of the second segment this February.
NYPA, however, argued that “the EMCP has no bearing on whether the project reduces congestion and saves consumers money,” as those issues were addressed in the certificate. Furthermore, the remaining EMCP approval only relates to how the project will be physically constructed, versus whether the SPCP is needed.
FERC agreed with NYPA. “Upon review of the EMCP approval included with [a] supplemental filing, we agree with NYPA that the EMCP approvals are related to physical construction and do not address reliability or congestion criteria,” it said.
Construction recently began on the project, with an anticipated in-service date of fall 2025, though significant work remains.
NYPA estimates the total capital cost will be $1.1 billion, with the utility responsible for $641.3 million. The PSC found that the project will produce congestion cost savings of approximately $450 million, as it “represents an upgrade to the transmission backbone system of New York that will improve reliability throughout the state.”
The New York State Public Service Commission ordered changes Thursday to improve and standardize the community choice aggregation (CCA) program used by dozens of municipalities.
The PSC said the changes are broadly designed to increase transparency and consistency by clarifying program requirements, imposing commodity price caps, creating an enforcement mechanism to ensure fair and principled operation and ensuring consumer outreach and education efforts are in place.
At the end of 2021, four CCA administrators were serving nearly 100 municipalities with about 200,000 residents, the order said. Many dropped out, however, because of energy market volatility, voided energy service company (ESCO) contracts and utility billing issues.
Many of the changes the PSC ordered Thursday to make CCA participation easier and improve the process are drawn from an April 2021 whitepaper proposal by state Department of Public Service (DPS) staff. The changes include:
All customers in a given CCA program will be charged the same product price, regardless of enrollment date.
The price-to-compare information for the CCA market will be made consistent across all CCAs and utilities by using the 12-month trailing average of the utility rate plus a merchant function charge and any defined adder that applies to utility supply customers but not ESCO customers.
Fixed-rate supply products will be limited to 105% of the 12-month trailing average utility supply rates, and variable-rate products must offer a guaranteed savings, while renewable products will not have a price cap because of limited ability to determine a reasonable price.
Department staff will prepare a proposal for a statewide solar-for-all program like the one created by National Grid in its upstate New York service area.
Any distribution utility with tariffed provisions providing for CCAs in its territory must add a dedicated CCA page to its website.
Standardized templates and guidelines for CCA administrator compliance filings will be created.
The CCA administrator, utility and ESCO and must notify each other and DPS staff within 48 hours of learning of a billing error that affects 50 or more customers.
CCA administrators must maintain a list of customers that have opted out of the CCA to prevent the customers from receiving future opt-out notifications.
Additionally, DPS staff must define a competitive solicitation for ESCO service to a CCA and propose ways to promote it. Very few ESCOs respond to requests for proposals now.
“This has led to instances where only one bid was received, and that bid was subsequently accepted even though it was a much higher rate than previously, and no customer benefit could be demonstrated,” the order said. “There should never be a case where a contract is signed because it was the only choice in order to keep the program going. In other words, the continuance of the CCA program should not take precedence over the benefit to customers.”
Thursday’s PSC vote was 5-2, with commissioners John Howard and Diane Burman opposed.
Burman said too much was packed into the order with too little deliberation.
Howard questioned the premise that local governments are capable of making utility supply purchases for constituents and said the lack of participation by residents in CCAs is troubling. He said the measures in Thursday’s order will improve the program but do not go far enough.
In a news release after the vote, PSC Chairman Rory Christian said, “CCAs provide local governments the opportunity to support the energy and environmental needs of their constituents by expanding the choices of energy options available. Eligible customers have the opportunity to have more control over their overall energy costs, to spur clean energy innovation and investment, to improve customer choice and value, and to protect the environment, thereby fulfilling an important public purpose.”
Maryland’s new governor, Wes Moore (D), did not promise new climate goals in his campaign, instead endorsing the goals of the Climate Solutions Now Act of 2022, which Democrats enacted without the signature of former Gov. Larry Hogan (R).
But Moore may bring new urgency to addressing one of the key obstacles to reaching those goals: workforce development.
Moore, who was sworn into office Wednesday, pledged during his campaign to bolster the state’s career and technical education (CTE) programs by increasing funding and ensuring that “that partnerships with local governments, community colleges and specific employers … better link students to in-demand careers.”
Moore expanded on his plans in his inaugural address outside the Maryland State House on an unseasonably warm afternoon. Moore, the state’s first Black governor, was introduced by Oprah Winfrey.
“While Maryland is home to some of the best and some of the greatest institutions of higher education in this country — something we should be very, very proud of — we must end this myth that young people must attend one of them in order to be successful,” Moore said. “That’s not the path for every student. To be clear, it wasn’t my path. I joined the military when I was 17 years old. I went to a two-year college. And I think things worked out pretty well.”
Moore graduated with an associate degree from Valley Forge Military College before graduating Phi Beta Kappa from Johns Hopkins University. He later led a poverty-fighting foundation and a Baltimore-based business that helped underserved students.
His platform called for expanding access to CTE programs and investing in dual-enrollment programs that allow high school students to obtain college credits prior to graduation. He pledged to increase funding for apprenticeships and work with labor and businesses to “drive students into high-demand and high-paying jobs.”
He also supports a service year option for high school graduates in exchange for job training, mentorships and college tuition support, and he set a goal of producing 150,000 science, technology, engineering and math (STEM) graduates by 2027.
The Inflation Reduction Act signed by President Biden last year could create nearly 537,000 jobs a year for a decade, according to a study commissioned by The Nature Conservancy. But where those workers will come from is a major concern for policymakers.
Moore’s education plans are central to his vow to address the people “left behind” amid Maryland’s prosperity. “We know it is unacceptable that while Maryland has the highest median income in the country, one in eight of our children lives in poverty,” he said, rejecting the notion that “in order for some to win, others must lose.”
He also dismissed those who say climate change is not an urgent problem.
“We’re often told that climate change is a problem for the future, or something that you only have to worry about if you live in farmland or in a flood zone. But climate change is an existential threat. And it is happening now in our communities. And so confronting climate change represents another chance for Maryland to lead,” he said.
“Clean energy will not just be a part of our economy. Clean energy will define our economy and Maryland. But that requires everybody — companies, communities, state and local governments and the people — to take bold and decisive actions.”
Before being sworn in, Moore named his cabinet secretaries, including former California regulator Serena McIlwain as secretary of the environment, and Josh Kurtz, Maryland executive director for the Chesapeake Bay Foundation, as secretary of natural resources.
McIlwain had served as undersecretary of the California Environmental Protection Agency since 2019 after stints at the U.S. EPA, where she was director of the Office of Continuous Improvement and assistant regional administrator at the agency’s Region 9 office in San Francisco.
Kurtz worked previously at The Nature Conservancy.
Speakers at a SERC Reliability-hosted webinar on Tuesday credited changes to the regional entity’s compliance monitoring and enforcement process for helping build a stronger connection both within the RE and between it and other industry stakeholders.
Presenting at SERC’s 2023 Open Forum, General Counsel Jimmy Cline, said that the RE’s Risk Assessment and Mitigation (RAM) and Enforcement departments realized in 2020 that their approach to violation processing needed an overhaul, resulting in the move to a risk-informed violation processing procedure. The first step was for the two departments to work more closely to clear the mounting backlog of violations.
“Our old process was a siloed approach, where RAM [and] Enforcement worked separately, resulting in duplication of work,” Cline said. “We replaced that siloed approach with a collaborative team approach to create alignment between RAM and Enforcement throughout all processing phases.”
Ted Franks, SERC | SERC
Ted Franks, SERC’s director of reliability assurance, discussed the way the RE’s new internal information-sharing practices have improved the efficiency of violation processing. It starts with its Inherent Risk Assessment (IRA) and Entity Risk Profile (ERP), which are produced as part of SERC’s regular risk-based monitoring program every three years; recently the organization stepped up its monitoring of higher-risk entities, for which it now produces an enhanced ERP about every 18 months.
When the RE receives a report of an entity’s potential noncompliance, the RAM team shares the most recent IRA and ERP with the Enforcement department, along with records of any previous audits involving the utility. RAM Manager Todd Beam told attendees this sharing helps investigators get up to speed quickly, both on the entity’s compliance history but also “how it functions within the” bulk power system.
“The prior audit information is helpful; it allows RAM and Enforcement to assess how audit information is used within an entity, and if it is indeed being used as a point of information regarding risk,” Beam said. “Discovery of issues by acting on an [information] provided through audit, or perhaps a recommendation, shows a willingness and a drive by the entity to act on the information and to do the investigative process. This is exemplary behavior; it shows a keen interest by the entity in ferreting out and eliminating risk.”
Between February 2020 and November 2022, the number of violations waiting to be resolved by SERC fell from 500 to 231; by the same month their average age had dropped to 6.2 months, down from 13.7 months in August 2021. | SERC
Cutting down on internal duplication of effort allowed SERC staff to dispose of violations more quickly and created the chance for deeper collaboration between the RE and registered entities that do need more attention. In its interactions with utilities, SERC aims to identify frequently violated reliability standards and help entity staff set up better internal practices to reduce noncompliance issues.
Revamping the enforcement process paid big dividends, Cline asserted, pointing to statistics that showed SERC’s inventory of unresolved violations fell from 500 in February 2020 to 231 in November 2022, while the average age of the RE’s inventory fell from 13.7 months in August 2021 to 6.2 in November 2022. Clearing out the inventory and reducing the processing time gave the department “much more time to conduct thorough risk assessments and work with entities on mitigation,” he added.
OLYMPIA, Wash. — Washington’s home construction industry and Realtors said this week they oppose a bill to make climate change a part of local governments’ land-use planning, saying it would make it difficult to build homes in the “wildlife-urban interface.”
Senate Bill 5203 would amend the Growth Management Act to require comprehensive proposals, development regulations and regional plans to support state greenhouse gas emission targets and improve resilience to climate impacts and natural hazards. A similar bill is working its way through Washington’s House.
“It would chart a course for our communities over time,” bill sponsor Sen. Liz Lovelett (D) told the Senate Local Government, Land Use and Tribal Affairs Committee Tuesday.
She added that bill would encourage density over urban sprawl, which was an intention of the GMA when it was enacted in 1990. The law sets land use designation and environmental protection requirements for all Washington counties and cities.
Josie Cummings, representing the Building Industry Association of Washington, told the committee that adding climate change to the Growth Management Act would codify wildfire risks to the point where that factor would handicap new housing. Washington has experienced an increase in wildfires, which has been largely blamed on climate change. Wildfires have frequently threatened Washington’s small towns and villages in rural areas.
“This would reduce housing,” said Bill Clarke, representing the Washington Realtors.
In contrast with the industry groups, a large majority of the public testimony and sign-in sheets favored the bill, with 1,218 signed up at the hearing in favor of the bill without testifying, while 15 signed up opposing the bill without testifying.
Nineteen of 23 people testifying Tuesday supported the bill, and two were undecided. Supporters included state agencies, environmental groups, some individual small town council members and three disabled people, who argued the cities will improve their public transit authorities if trimming emissions leads to more bus service.
John Flanagan, a senior policy adviser to Gov. Jay Inslee, said climate change should be a factor in land use decisions at all levels of government. “We cannot rely on the actions of a few. We need to be all in,” Anacortes city council member Ryan Walters said.
“It only makes sense that the [Growth Management Act] align with other state laws,” Leah Mission of Climate Solutions said. She was referring to state law requiring Washington’s carbon emissions to be trimmed by 95% by 2050.
“If we passed this 10 to 20 years ago, we wouldn’t be in this dire climate situation that we are right now,” Redmond City Council President Jessica Forsythe said.
“We need to plan for rising tides,” Adam Maxell of Audubon, Wash. said. Washington has an extensive coastline.
Some argued that if trimming emissions leads to more bus service, then the state government needs to provide money to support expanded public transit. “If you move forward, it is critical you provide funding for this as well,” said Paul Jewell, representing the Washington Association of Counties, which has not yet decided whether to support or oppose the bill.
This is the third year that this bill has worked its way through Washington’s legislature.
The House passed it in 2021, but it stalled in a Senate committee. In 2022, both the Democrat-controlled House and Senate teetered on the edge of passing the bill before Republicans in the Senate and House used parliamentary maneuvering to kill the bill on the final day of the session.
MISO’s emergency declaration during the December winter storm has ignited a debate over whether the RTO should issue the alert to sustain its neighbors during extreme weather.
The grid operator in December made the emergency declaration as a wintry blast forced generation outages and higher than forecasted load in the system, pushing MISO into a three-hour maximum generation emergency to use its collection of load-modifying resources. It lifted a maximum generation warning for its South region a few hours before the evening peak. (See FERC, NERC Set Probe on Xmas Storm Blackouts.)
Jason Howard, MISO’s director of operations and risk management, said during a Reliability Subcommittee meeting Tuesday that staff and members “successfully managed through the event.”
However, he said the emergency was necessary to manage reliability while the RTO provided a “significant amount of exports” to its neighbors. Howard said staff was able to access additional capacity once they declared the emergency.
“There wasn’t a concern for capacity,” he said. “It was a matter of maintaining reliability and helping our neighbors out. [There was] no disruption of power to the MISO footprint.”
Howard said staff felt “very comfortable” with its capacity position ahead of the storm but that MISO and the industry “struggled” with forecasting an “unanticipated, drastic increase in demand. He said the gas generation fleet began depleting its supply as the system entered the evening peak on Dec. 23.
The emergency decision was ultimately necessary to “get at emergency reserve to maintain sufficiency and export upwards of 4 to 5 GW to help our neighbors,” he said, referring to SPP, the Tennessee Valley Authority, Associated Electric Cooperative, Inc., and the Southeast planning region. Howard said MISO had a responsibility to act because some of its neighbors were either facing or actively in load shed.
Director of Market Administration John Harmon said MISO was simply “assisting in an emergency,” as it would want to similarly be aided during an emergency.
Independent Market Monitor David Patton said he was still reviewing the event, adding that his initial conclusion is MISO should define what lengths it’s willing to go to in helping neighbors at the expense of its own markets.
“I will say that I totally appreciate and agree with the notion of wanting to help your neighbors, but you should be following your operating procedures,” Patton said. “The action that any RTO takes to help a neighbor can have serious financial impacts for customers.”
Stakeholders debated whether the grid operator should call on load-modifying resources to support non-firm exports. Patton said LMRs to support exports can trigger shortage pricing “that could cost millions.”
Hwikwon Ham, with the Minnesota Public Utilities Commission, pointed out that MISO’s risk assessments depend on imports from PJM and Canada to help keep the footprint afloat.
Minnesota Power’s Tom Butz said that had MISO not helped TVA during its emergency, the ramifications might have been more dire than a matter of “economic convenience.”
“This is a first for MISO,” Howard said of MISO’s status as a net exporter during the weather event. He said staff is going to have to determine its “operational philosophy” regarding emergency procedures in aiding neighboring regions.
MidAmerican Energy Co.’s Dennis Kimm argued that MISO’s issue in December wasn’t a gas supply one, but a timing problem. He said staff didn’t commit gas generators ahead of time, thus failing to provide them enough time to secure additional supplies. Kimm said gas purchases are especially challenging to procure during a holiday weekend and after 5 p.m.
Stakeholders asked whether MISO might consider clearing additional gigawatts of gas generation in the day-ahead market to serve as a buffer when extreme temperatures are forecasted.
Staff said MISO’s five-year plan includes devising methods to better manage uncertain conditions. Howard said they are working on providing its members better situational awareness so they can make more informed decisions on fuel procurement.
Howard acknowledged “issues” with sending notifications to market participants on Dec. 23 and said that the RTO is examining the communication issues to see what went wrong.
He said the winter storm’s high pressure kept MISO’s wind production high, unlike the February 2021 winter storm that brought in a low-pressure system. “These are unique differences that we have to manage that makes the planning challenging,” he said.
Staff said their first report on the storm contained only preliminary findings but promised more discussions on the system’s performance in December. The Resource Adequacy Subcommittee is planning to discuss the storm and its implications on capacity accreditation during its March meeting.
MISO issued a cold-weather alert and conservative operations instructions for its South region Dec. 22 through Dec. 26. It also declared conservative operations for its North and Central regions and two local transmission emergencies due to congestion on Dec. 23.
Staff said the South region’s warning was necessary because of a request by joint parties to the regional transmission transfer between the Midwest and South regions that MISO reduce flows across the link. Staff said they were still in discussions with the utilities to understand why the request was made.
Factoring in exports, MISO served peak demand of 111 GW on Dec. 23. Its load averaged 78 GW during December.
