MISO has enacted conservative operations orders, a hot weather alert and a capacity advisory for its Midwest region ahead of the season’s first widespread heat wave set to bake much of the U.S. this week.
The grid operator said a combination of hot weather and load forecast uncertainty is forcing a conservative operations declaration Tuesday through Friday for MISO Midwest. The capacity advisory is effective beginning Wednesday “until further notice,” per MISO.
The National Weather Service anticipates dangerous heat that has been simmering in the West, Texas and Florida will expand this week into the eastern two-thirds of the country, starting in the north-central states and Plains.
MISO has asked its generation and transmission owners to consider revoking or deferring maintenance outages. It also has asked generation owners to notify it of any fuel restrictions and environmental limitations of equipment. MISO said members should be prepared to enter maximum generation emergency procedures, which involve calling on load-modifying resources.
Spokesperson Brandon Morris said MISO and members are preparing for the extreme heat, which could drive 2023’s annual peak demand in the footprint.
“The potential for higher-than-normal demand and tight operating conditions could lead to a system peak for the year. MISO issued alerts and advisories in anticipation of the heat wave to provide situational awareness and notify our members’ utilities to prepare in case additional actions are needed to ensure reliability,” Morris said in an emailed statement to RTO Insider. “We are coordinating with our neighboring grid operators who expect similar conditions. Because of our large, diverse footprint, MISO has several options to obtain power and send it to where it is needed.”
Ahead of the season, MISO predicted July would hold its greatest chance of enlisting the help of its load-modifying resources and leaning on neighbors for exports during blistering temperatures. (See MISO: Little Firm Capacity to Spare This Summer.)
MISO last issued conservative operations instructions in late June, when it struck a rough patch of storms and hot temperatures that also spawned capacity advisories and hot weather and severe weather alerts June 22-30. The RTO also issued a hot weather alert July 19-20 for much of its South region.
AUSTIN, Texas — Texas commissioner Will McAdams, chair of SPP’s Resource and Energy Adequacy Leadership (REAL) Team, set the tone from the outset when he shed his blazer and rolled up his sleeves as the group gathered for its meeting Wednesday.
“It’s July in Texas. Let’s get started,” he said.
For the next nine hours of what McAdams called a “crusher” of a meeting, the REAL Team discussed issues ranging from flexibility and ramp associated with capacity obligations to maintenance outages and their effect on capacity obligations. A central theme emerged around how SPP compensates load-responsible entities for availability or penalizes them for lack of availability during critical hours.
“It’s a lot of ships that we hope are moving in the same direction now, but it’s a lot to coordinate,” McAdams told fellow commissioners during an open meeting the following day.
The team met its first objective when it endorsed a winter resource adequacy requirement (RAR) approved recently by the RTO’s Markets and Operations Policy Committee. The revision request (RR549) will go before SPP’s state regulators and its Board of Directors this week for final consideration. (See “Members Endorse Winter Resource Adequacy Requirement for 2024-25,” SPP Markets and Operations Policy Committee Briefs: July 10-11, 2023.)
The measure applies the same level of validation, study and assessment requirements to the winter season (December through March) that is applied to the summer season, including a deficiency payment for capacity shortfalls. It also assigns an annual deficiency payment to prevent duplicate payments for the same capacity within an annual timeframe.
RR549 is not without its detractors. It barely met MOPC’s approval threshold and cleared the REAL Team with two votes to spare, 9-5. Members removed one of two revisions added during the MOPC discussion over confidentiality concerns.
The measure is effective for the 2024/25 winter season (December through March).
“It was a hairy deal,” McAdams told the Texas Public Utility Commission. “It’s a real shootout. Just trying to provide the mechanisms that ensure resource adequacy is not an easy thing. These are not easy decisions.”
SPP’s board and state regulators created the REAL Team, comprised of 14 independent directors, members, and regulators and their staff, earlier this year. The team has been meeting every three weeks since May. (See SPP’s REAL Team Swings Into Action.)
“I think the REAL Team is a bit of a fusion center,” McAdams told RTO Insider after the team’s first in-person meeting in May. “It’s bringing together corporate members, components of the Members Committee, the stakeholder components of SPP together with [Regional State Committee] leadership as well as board leadership … so that topics can be flagged and, frankly, polled to a degree in terms of resistance to certain staff recommendations and or support.”
The team has created sub-groups focused on resource adequacy, markets and operations. They will lean heavily on the Supply Adequacy Working Group (SAWG), which has primary responsibility for nine of the 11 objectives assigned to the REAL Team.
Its next milestone comes in October, when it plans to consider a ramping capacity requirement, begin addressing the footprint’s need for reliability attributes in the resource mix and endorse tariff changes — RR554 and RR568, respectively — that codify performance-based accreditation (PBA) and effective load carrying capacity (ELCC) policies.
The SAWG is developing both tariff revisions. It has created limitations for catastrophic exemptions that apply to all resource types that will sunset after 10 years of historical data from the units. The working group also has simplified the ELCC tiers by using a two-tiered approach with firm and non-firm transmission service.
More important, the SAWG has prepared a system methodology for upcoming loss-of-load expectation and ELCC studies that evaluates the collective reliability contribution of all ELCC resources to ensure they are correctly accredited.
SPP is responding to FERC’s recent order admitting it had mistakenly approved the RTO’s proposal to use an ELCC methodology to accredit wind and solar resources based on historical performance. The commission has granted renewable developers a rehearing of its original order. (See FERC Grants Rehearing of SPP Capacity Accreditation Proposal.)
The grid operator’s Market Monitoring Unit said it had equity and accountability concerns over the PBA and ELCC. It recommended measuring individual performance in the PBA process against the top 3% net peak load and including all outages, whether forced maintenance or out-of-management control, in the accreditation processes.
The MMU offered two recommendations it said would improve reliability that left one commission staffer shaking his head: the PBA measurement against the top 3% net load and implementing a true-up process at the end of each season.
Keith Collins, vice president of market monitoring, shared an event his team picked up just before July 4, when SPP had issued a resource advisory and then a conservative operations call. He said the MMU became aware of several hundred megawatts of resources, accredited for the summer, that were on outages because of staffing issues.
“They were aware … that whatever they were going to do was going to be accounted for in performance-based accreditation, and they did it anyway,” Collins said. “If we want to think of the incentives and what we’re doing to keep people from making those decisions and contributing to a reliable system, particularly when we need it the most, then we’re not there yet — because they did it anyway.”
SPP’s continued integration of renewable resources over conventional or thermal resources has created operational uncertainty and shortened the staff’s ability to commit resources, according to C.J. Brown, director of system operations. On Sunday, the RTO issued a resource advisory because of high loads, load and variable energy forecast uncertainty, and resource outages; it is at least the sixth resource of conservative operations advisory SPP had called since April.
“Those are very challenging and stressful situations,” he said. “You feel like every one thing you give up could put you into a situation where you’re not able to cover a certain percentage of uncertainty. We have to do that leading up to and including real time, and that starts as much as seven days out. Typically, about four days out is our longest lead time when a decision has to be made, but that’s just a continual process these days.”
“Two years ago, we might have made that decision two or three times a year,” Brown added. “Now it seems like it’s every other week.”
To maintain current levels of capacity until sufficient resource adequacy measures are in place, staff are developing policies — likely including some form of system support resource or reliability must-run contracts used by other grid operators — that “strongly encourage” generation owners to reconsider and postpone retirements. Based on utilities’ integrated resource plans and information gleaned through the transmission process, SPP expects 6.5 GW of gas- and coal-fired resources to retire by 2030.
The problem is compounded by hints of reluctance from renewable developers about investing in an RTO where conventional resources are retained.
“What we’re hearing is some of the recommendations and activities we’re making in the SAWG space and in the REAL space might be shifting renewables to other more profitable regions,” Casey Cathey, senior director of grid asset utilization, told the REAL Team. “Are we defining the requirements at a razor’s edge to where we’re just maintaining the fleet and barely improving? I think we need more markets, we need more carrots to be able to better optimize over a longer time horizon so the LREs can kind of appreciate what kind of supply we actually better recognize … we want to make sure we’re sending the right signal that if we are retaining our conventional fleet, that we have a path forward, because right now it seems like there’s a whipsaw.”
SPP’s generator interconnection dashboard indicates solar resources account for 43% of the projects in the GI queue (45.6 GW of 105.5 GW), followed closely by wind (26.1 GW, 24.8%) and battery storage (19.9 GW, 18.8%). Cathey said solar requests exceeded those for wind for the first time earlier this year.
“We can’t wait [for the solar]. We’ve had 250 megawatts of installed solar for a long time, but we have just not seen that build,” he said. “We’ve been thinking for about six to seven years that this might be our next frontier. Wind is highly volatile, it can be helpful, but a lot of times when wind winds down, solar’s actually doing pretty good.”
Cathey said the potential 90 GW of solar, wind and batteries in the queue doesn’t give him “a lot of comfort,” however.
“If we installed all gigawatts of wind, solar and batteries and we also retired a good portion of our conventionals, we would still have C.J. describing some slides of some conservative operations, and so we need to be balanced here,” he said. “Hopefully, a lot of this gets built but we also need to make sure we’re sending the right signal to either keep resources, conventionals, online for a period of time until another technology can take over.”
RA Forum Draws Industry Interest
The REAL Team will hold its next in-person meeting Sept. 8 in Dallas, the day after SPP hosts a Resource Adequacy Summit at DFW International Airport.
What started as a meeting limited to 75 attendees has blown up into an industry event that has drawn the interest of at least two FERC commissioners, according to organizers. NERC’s and EPRI’s CEOs, Jim Robb and Arshad Mansoor, respectively, have accepted invitations.
“There’s heavy interest nationally to provide forums where the reliability standard concept can be discussed on a national basis, what that involves and what defines resource adequacy, not just within ISOs but regionally,” McAdams said.
SPP has extended invitations to its neighbors, with MISO already accepting. ERCOT also has been invited to attend.
Even without ERCOT, Texas will have a heavy presence. McAdams said PUC staff will attend and energy consulting firm E3 will discuss valuing availability. E3 proposed an LSE reliability obligation construct and several other market designs for the Texas grid operator following the disastrous and deadly 2021 winter storm.
SPP has secured a larger meeting space than originally planned to handle the increased attendance.
NYISOupdated the Operating Committee on Thursday that 89 MW of nameplate behind-the-meter solar was added onto the grid in June. The month’s peak load was 22,867 MW and the minimum was 11,999 MW.
Mark Younger, president of Hudson Energy Economics, referred to the growing megawatts of energy storage resources in New York and asked what percentage of them can sell capacity resource interconnection service. (See “May Operations Report,” NYISO Operating Committee Briefs: June 22, 2023.) CRIS rights are needed to take part in NYISO’s capacity market and can be obtained either through a transfer from a facility with existing rights or from ISO deliverability studies.
Aaron Markham, NYISO vice president of operations, responded, “I believe only half is available to sell capacity.”
Matt Cinadr, a power systems operations specialist with The E Cubed Co., asked whether NYISO has observed any issues with intermittent production and the amount of reserve fuel available.
Markham said, “we’ve definitely seen the levels of intermittent production increasing the volatility on the system, but at this point, it hasn’t been a driver of any reserve shortages.”
“As the amount of intermittents increases, however, I think we’re definitely going to see greater magnitudes of error and need to procure some market products to help manage that going forward,” he added.
DER Manuals
The OC also approved six revised manuals presented by NYISO that will support the implementation of distributed energy resources in New York’s markets.
These DER manuals include revisions to market procedures like ancillary services, control center requirements and emergency operations, and have been reviewed by all other applicable working or stakeholder groups. (See “DER Manual Updates,” NYISO Discovers Market Problem, Opens Confidential Investigation.)
NYISO still anticipates these approved manuals will become effective in parallel with other related DER tariff and market models.
The competing goals of reliability, sustainability and affordability converged Thursday as the New York state Public Service Commission wrestled with the mounting costs of the state’s energy transition.
Department of Public Service staff provided the first of what is expected to be a series of annual reports on the agency’s efforts to implement New York’s Climate Leadership and Community Protection Act (CLCPA).
The landmark 2019 law is intended to decarbonize the state over the next quarter century and simultaneously counter decades of environmental injustice.
The costs will be massive, but the details are unknown and likely unknowable at this point.
The figure $270 billion has been thrown around, which is not as big as it sounds when spread over 25 years in a state whose gross domestic product is $2 trillion a year.
But it does not reflect the rampant cost increases of late, nor the delays and cancellations being seen in New York’s renewable energy development pipeline.
Also, the costs will not be spread evenly among the state’s 20 million people.
The federal dollars everyone is counting on to help cover the cost may not last forever, and presumably someday will have to be paid back with interest by federal taxpayers, including those in New York.
Finally, the benefits from all that spending are unknown and will not be reflected entirely in utility bills. Reduced medical expenditures, prevented societal costs, energy efficiency/conservation and increased economic activity are a few of the presumed positives being counted against capital costs as the state calculates a net benefit of more than $100 billion from CLCPA spending.
The PSC and the staff of the DPS will play a key role in much of this spending, as they regulate the infrastructure by which electricity is delivered and the utility rates by which New Yorkers pay for it.
The three primary topics of discussion at Thursday’s PSC meeting all revolved around that theme, and the escalating costs entailed.
Building Electrification
The commissioners unanimously voted to adopt a strategic framework to redirect and streamline the state’s energy efficiency and building electrification efforts (Cases 14-M-0094 and 18-M-0084).
Both cases predate the CLCPA, but they are an indispensable part of any decarbonization and net-zero strategy. Thursday’s order will update the efficiency efforts to better align with the overarching goals of the CLCPA.
Efforts to date have been inadequate in meeting the needs of low- and middle-income New Yorkers, the DPS staff concluded during its review. The new framework will give greater responsibility to the New York State Energy Research and Development Authority for reaching disadvantaged communities.
The order directs NYSERDA and utilities to file within 90 days proposals totaling $1 billion a year from 2026 through 2030, and to look beyond ratepayers for funding.
“Today’s action establishes this framework where we can streamline and scale program delivery,” PSC Chair Rory Christian said, “by moving away from what we previously looked at as individual utility-level goals towards a focus on more statewide outcomes.”
Commissioner Diane Burman spoke at length about previous efficiency initiatives being a series of good-faith efforts marred by missteps and poor coordination.
Commissioner James Alesi countered with a comparison to the race to put a man on the moon. “There’s going to be failures and there’s going to be frustration,” he said.
Along the way, predicted costs will change and unanticipated costs will arise; new legislation and technology may move the goal line and the path by which it is reached. “But there will be no retreat,” he said. “There cannot be a retreat.”
Commissioner John Howard drilled down on hidden and undisclosed costs. About 20,000 housing units are being weatherized per year across the state, he noted. To meet CLCPA goals, that needs to be 200,000 a year for many years, at a cost of far more than $1 billion a year.
Nonetheless, he called it the first reality-based order he had seen in a long time.
CLCPA Update
DPS Director of Policy Implementation Jessica Waldorf summarized the agency’s inaugural report on the CLCPA implementation (Case 22-M-0149).
The staff-generated review was loaded with technical details such as greenhouse gas emission reductions since 1990 (46%) and a summary of the PSC orders that will help carry out the CLCPA.
There also was a summary of estimated costs authorized as of mid-2023 in support of CLCPA goals: $43.76 billion.
Waldorf said the figures are conservative estimates, and some of the spending was authorized before CLCPA.
The figures will evolve over time, be incurred and paid over an unknown amount of time, and be recovered through a variety of means, not just incremental costs to ratepayers.
Commissioner Tracey Edwards said: “I want to see how we can, for the next annual report, do a little bit more of a deep dive on what you expect to happen.”
Berman, too, asked for something more than a retrospective report, as costs are escalating rapidly and are disproportionately being recovered through rates.
“Folks need to understand what it means, and the challenges going forward,” she said. “We have an obligation to look at the total.”
Howard said: “New Yorkers are desperate to know what this is going to cost. The rhetoric around the CLCPA writ large is, don’t worry, it pays for itself. I think we see from our brief snapshot in 2022 … no, it doesn’t pay for itself.”
Commissioner John Maggiore said there are three enormous challenges at play: Keeping energy affordable and reliable while achieving CLCPA goals. “I don’t think achieving any of these things is going to be easy.”
Waldorf said the state has the advantage of a long head start in planning and early results.
“There’s a lot of anxiety out there about how we can actually achieve the goals of the CLCPA but I think we’ve learned a lot through the decades of work.”
The goals will be difficult to achieve, and the shift of investment will need to be significant, she added, but multiple agencies will use every means available to reduce the cost to ratepayers.
One Case of Many
Spiraling consumer costs came to fore yet again in a rate case before the PSC on Thursday, sparking some of the most passionate comments in the lengthy meeting.
The utility with the most customers in the state, Con Edison, in early 2022 sought an increase of 17.6% in delivery charges for electricity and 28.1% for gas, which it calculated would boost customers’ total bills 11.2% and 18.2%, respectively, and give it a combined $1.7 billion in new revenue (Cases 22-E-0064 and 22-G-0065).
It justified the request, in part, by saying it will be spending money on CLCPA-related projects.
This did not go over well with the public and public advocates. The two cases generated more than 7,500 comments.
After investigation and negotiation, the utility, DPS and stakeholders agreed to a pair of rate plans that will give Con Ed a revenue hike of $1.93 billion — 13.5% more than it asked for — but spread that over three years instead of one.
Edwards cast the lone vote against approving the deal.
“I have a tremendous concern about the structure and the process, because we do have a responsibility for balance,” she said, especially with CLCPA looming — “what are all the other investments that have to be made?”
Many families in New York City are still rebounding from the economic crisis wrought by COVID, and have not reached stability, Edwards said.
“My biggest concern, that I just cannot get past, is that the starting point that the utility put in here,” she said. “I just don’t get it. I don’t understand the world they are living in. … We have to change this process.”
Howard tore into the magnitude of the taxes and fees levied on utilities by New York City. (DPS says property taxes account for 21% of a Con Ed electric bill and 15% of a gas bill.)
A majority of the City Council wrote to PSC, urging it to reject the rate proposal, but the council approved without debate an increase in the property tax charged to Con Ed, Howard said.
This will only get worse as Con Ed spends billions on infrastructure needed to electrify the nation’s largest city, he said.
“There is a boomerang of even greater revenue to the city of New York for that expense. As we clean up the environment, we put in this automatic enrichment to the city of New York.”
Christian spoke in more diplomatic terms about the need to pay now for future benefits, and the pain of doing so.
The 7,500 comments are written in different tones and perspectives, he said, but share a common theme: “Recognition that New Yorkers everywhere still face economic challenges coming out of the COVID pandemic. These hardships are only going to be exacerbated further by rising prices.”
Christian added: “I have solace in the fact that these investments are being used to reinforce much of the work we’ve already done in building the system of the future … and creating a better platform from which we can attain our climate goals and maintain reliability of the system.”
Can’t Pay/Won’t Pay
Con Ed’s monthly collections reports to the DPS quantify the trends Edwards and Christian discussed.
New York City suffered significant economic impacts from the COVID pandemic and continues to have a much higher unemployment rate (5.9% in June) than the rest of the state (3.0%) or nation (3.6%).
In June 2023, 473,000 Con Ed customers were more than 60 days in arrears for a total of $1.03 billion. This compares with 327,000 customers who owed $381 million in June 2019, before the pandemic.
Also telling are the numbers from June 2022, when 453,000 customers owed $1.35 billion. A one-time post-pandemic debt forgiveness program the state implemented would soon reduce the arrears by hundreds of millions of dollars — but more of Con Ed’s 3.6 million customers are behind on their bills now than a year ago.
An offshore wind trade association last week summarized a recent record of remarkable progress in the young U.S. industry but added a caveat: There are severe economic threats to its continued momentum, with project delays and supply chain disruptions likely to continue.
The second-quarter report by the Business Network for Offshore Wind (BNOW) covers a period that contained a major milestone: The first “steel in the water” for the nation’s first two commercial-scale OSW projects — South Fork Wind and Vineyard Wind — following a decade of development work.
The report notes several other measures of progress:
An 18% increase in OSW goals backed by legislative or regulatory directive, which reached 42.8 GW nationwide;
The formation of a domestic supply chain; the first U.S.-made substation, monopile and export cables installed in U.S. waters; and groundbreaking on a component steel facility in Baltimore;
Louisiana undertaking negotiations for wind farms in state waters, which is expected to be a faster development process than in federal waters;
Total market investment reaching $21.6 billion, compared with $5 billion in 2021;
The fleet of specialty vessels built or retrofitted in U.S. shipyards reaching 36, double the number in 2021;
A total of 1,478 contracts awarded, 272% more than in January 2021; 64% went to U.S. companies and 90% went to companies with a U.S. footprint; and
29 ports are under development for manufacturing, marshaling and maintenance.
But then there are the headwinds.
The early wave of OSW projects is concentrated between southern New Jersey and southern Massachusetts, and one after another, developers in that region are saying they no longer can proceed with the projects under terms agreed to years ago because of soaring costs.
The 1,200-MW Commonwealth Wind project has reached an agreement to terminate its power purchase agreements, and the 1,200-MW SouthCoast Wind project is seeking to do the same, both in Massachusetts.
In June, developers of New York OSW projects totaling 4,200 MW told state regulators they may not be able to obtain financing without inflation adjustments.
Projects in New Jersey and Connecticut have sought concessions, as well.
BNOW called this “the duality of the industry” in its report: great strides forward, and a fallback to reassess finances. The trade organization said U.S. and foreign analyses suggest the cost structure has increased at least 20% in the past two years. It expects to start seeing project delays as a result.
In announcing the report, founder and CEO Liz Burdock highlighted the promise of longer-term growth as a new industry takes shape onshore to support the work planned offshore.
“Thanks to supportive federal and state policies, we are seeing unprecedented growth in the U.S. offshore wind supply chain across the nation,” she said Thursday in a news release.
“New contracts are signed daily with a vast majority going to small- and medium-sized American companies creating thousands of new jobs. With $7.7 billion in new U.S. offshore wind investments since the Inflation Reduction Act was signed into law, this is just the beginning. We will see many more factory openings, port revitalizations and vessels under construction in the years to come.”
Initial assessment of the offshore wind energy research lease Maine is seeking shows it would cause minimal environmental impact.
The report, by the U.S. Bureau of Ocean Energy Management, is another step toward wind power development in the Gulf of Maine but does not authorize any construction or operation. It entails only surveys, monitoring and placement of meteorological buoys.
Potential negative factors resulting from this work could include air emissions, noise, lighting, seafloor disturbance, entanglements and routine vessel discharges.
Publication of the draft assessment in the Federal Register on Friday started a 30-day comment period, during which two virtual public meetings will be held as BOEM seeks further input before finalizing the assessment.
BOEM rates potential impact at four levels: negligible, minor, moderate and major. Every effect of the research lease was projected as either negligible or minor — including on commercial and recreational fishing, which has been predicted to sustain a major adverse effect in the environmental impact studies prepared for construction and operation of the other wind farms.
Maine is positioning itself to be a pioneer in floating wind and a leader in the industry expected to develop around it. One of its state university campuses has a robust research-and-development program, and it already has floated a small-scale offshore wind turbine in state waters.
A key part of this is the research array Maine is seeking permission to build within a 10,000-acre zone 20 nautical miles offshore — up to 12 turbines with a total nameplate capacity of up to 144 MW.
The offshore wind farm proposals in the pipeline so far are all on the Outer Continental Shelf off the middle and northeast Atlantic Coast, with towers on seabed foundations in relatively shallow waters. The Gulf of Maine, like most of the Pacific Coast, is too deep for fixed-bottom development and will need to rely on floating wind technology that still is being developed and has minimal worldwide operational history.
LANSING, Mich. — One of the state’s largest municipally owned utilities, the Lansing Board of Water & Light, said last week it will invest $750 million in renewables, storage and natural gas generation over the next decade and pledged to be carbon neutral by 2040.
The utility plans to add 658 MW of renewable energy and storage and at least 110 MW of natural gas. Its current portfolio has a nameplate capacity of 581 MW. It closed its last coal-fired plant in 2022, becoming the largest coal-free utility in Michigan.
“This is the largest planned growth in BWL’s nearly 140-year history,” General Manager Dick Peffley said in a statement.
The plan will add 2.5 to 3% to customer bills.
The clean energy projects are expected to be complete between 2025 and 2027, and include 160 MW of battery storage; 65 MW of local solar; 195 MW of additional solar outside of the Lansing region; and 238 MW of wind outside of the Lansing region. The projects were selected from among 96 offers totaling 8,330 MW in response to its “all source” request for proposals.
The utility also said it will continue its energy efficiency efforts and add demand response programs.
The electric storage facility could provide as much as 16% of the 1,000-MW storage capacity called for in Michigan’s MI Healthy Climate plan, an outsize contribution for a utility that has 100,000 electric customers and serves 6% of the state’s load.
BWL received $12 million from the Michigan Public Service Commission for the construction of 10 MW of solar and 40 MW of four-hour battery storage at Delta Energy Park, the former site of the coal-fired Eckert Power Station, which was retired in 2020.
Delta also will be the site for a new 110-MW reciprocating internal combustion engine (RICE) gas plant by 2026. BWL also called for “a possible additional gas plant at a location to be determined later dependent on future load requirements and regional energy regulations.”
The projects and estimated costs “are still under negotiations with the proposed developers and are subject to change pending contract agreements,” the utility said.
When all the new generation projects are online, a company spokesperson said, BWL will generate nearly twice as much electricity as it does now.
“Once implemented, this will bring BWL’s total generational portfolio to around 58% renewable and reduce our carbon footprint by 75% compared to 2005,” Peffley said.
The utility says the additional power generation could help attract new businesses to the capital region and also could allow for sales of excess power to other utilities.
BWL provides power to several major corporate customers, including several large General Motors plants, along with state government and residential customers in Ingham, Eaton and Clinton counties. Michigan State University, in East Lansing, generates its own electricity, though most of the rest of the city is serviced by BWL.
In addition to gas-fired plants, BWL also has two wind sites and four solar sites.
Below is a summary of the agenda items scheduled to be brought to a vote at the PJM Markets and Reliability Committee and Members Committee on Wednesday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be covering the discussions and votes. See next week’s newsletter for a full report.
Markets and Reliability Committee
Consent Agenda (9:05-9:10)
The committee will be asked to endorse as part of its consent agenda:
B. proposed conforming revisions to a slate of manuals and PJM practices addressing the interconnection process overhaul approved by FERC last year (ER22-2110). (See “Manual Revisions for Interconnection Process Overhaul Sent to MRC,” PJM OC Briefs: July 13, 2023.)
C. proposed revisions to Manual 13: Emergency Operations resulting from its periodic review.
Endorsements (9:10-9:25)
1. NERC TPL-001-5.1 Manual 14B Revisions
PJM’s Stanley Sliwa will present proposed revisions to Manual 14B: PJM Region Transmission Planning Process to conform to NERC’s TPL–001-5.1 standard. The proposal was endorsed by the Planning Committee earlier this month through the quick-fix process, which allows for a problem statement, issue charge and solution to be brought concurrently and voted on in the first meeting. (See “Stakeholders Endorse Quick Fix Manual Revisions to Conform to NERC Standards,” PJM PC/TEAC Briefs: July 11, 2023.)
The committee will be asked to endorse the proposed manual revisions upon first read.
Members Committee
Consent Agenda (11:35-11:40)
The committee will be asked to endorse as part of its consent agenda:
B. proposed clarifying revisions to PJM’s tariff, Operating Agreement and Reliability Assurance Agreement, which were approved by the Governing Documents Enhancements and Clarifications Subcommittee in April.
C. a proposed solution and corresponding tariff revisions related to calculating the smooth supply curves for the Base Residual Auctions. The changes are meant to clarify that PJM will publish only smooth supply curves following BRAs and not Incremental Auctions. (See “Stakeholders Approve Tariff Clarification on Smooth Supply Curves,” PJM MRC/MC Briefs: June 22, 2023.)
PJM’s Darrell Frogg will present a proposal to create a cost-of-service mechanism for generators designated as critical to the derivation of an interconnected reliability operating limit under NERC’s Critical Infrastructure Protection standards. (See “MRC Endorses IROL-CIP Cost Recovery,” PJM MRC/MC Briefs: June 22, 2023.)
The D.C. Circuit Court of Appeals dismissed a pair of challenges Friday to FERC’s authorization of the long-contested Weymouth, Mass., compressor station. The court determined that it lacks jurisdiction over the petitions, which were filed by a group of nearby residents to the compressor.
The ruling is the latest blow to the Fore River Basin residents and environmental justice organizations that have been fighting the compressor station for about nine years. The compressor became operational following FERC’s final authorization in September 2020.
One of the petitions challenged the FERC-issued Extension Order which gave Enbridge, the owner of the compressor station, additional time to build the project following delays to construction. The second petition asked the court to review FERC’s denial of rehearing of the In-Service Authorization Order (see FERC’s Handling of Environmental Justice Issues Debated in Court.)
“We lack jurisdiction to consider either petition, so we dismiss them both,” the D.C. Circuit wrote.
Opposition to the project has centered around the cumulative health consequences and acute dangers of siting the facility near residential neighborhoods and industrial facilities, including multiple fuel storage areas, the largest hazardous waste disposal site in New England, a natural gas plant and a chemical manufacturing facility.
To make matters even more precarious, opponents argue, the compressor station was built on a flood-prone parcel of landfill that juts out into the water and is contaminated with a mix of diesel fuel, arsenic and coal ash. Opponents of the compressor expressed disappointment in the court’s ruling.
“This is a demoralizing outcome that makes it clear that health and safety play second fiddle to fossil fuels and profit,” said Braintree Town Councilor Elizabeth Maglio, a vocal opponent of the compressor.
A 2019 background health analysis conducted by the state found that communities in areas surrounding the compressor site have elevated concentrations of conditions related to air pollution, including asthma, heart attacks, COPD, heart disease and lung and bronchus cancer.
Meanwhile, a 2002 health survey of Weymouth residents found higher-than-expected levels of aplastic anemia, a bone marrow condition linked to benzene, a pollutant frequently found in uncombusted natural gas in the Greater Boston area.
Michael Hayden of Morrison Mahoney LLP, the attorney representing local residents, told RTO Insider that while the Court held that there is no jurisdiction for the appeal, “the Court’s decision does not comment upon our environmental justice concerns or arguments.”
In consideration of the first petition, regarding the Extension Order, the D.C Circuit ruling did acknowledge that the petitioners had demonstrated injuries related to the compressor station’s siting, including from air pollution and increased safety risks. However, it said FERC already reconsidered the Extension Order, and ruled “the Fore River Residents have already received all of the procedural relief they requested.”
“While we’re disappointed, we are not exactly surprised,” said Alice Arena of Fore River Residents Against the Compressor Station, one of the petitioners in the case. “This was the same court that totally ignored the fact that FERC violated its own regulations in allowing the Weymouth compressor without an [environmental impact statement].”
Hayden said he was unsure if the defendants would pursue further challenges to FERC’s approval of the compressor station.
“We need to study it and determine whether there’s any further appellate action warranted,” Hayden said, noting there’s a trial scheduled in October before the Massachusetts Department of Environmental Protection on the compressor station’s Chapter 91 waterways license.
The D.C. Circuit Court of Appeals on Friday upheld a FERC decision suspending the application of PJM’s transmission constraint penalty factor (TCPF) after it led to spiking prices that could not be addressed on Virginia’s Northern Neck Peninsula (22-1090).
The TCPF caused prices to spike on the peninsula in the Chesapeake Bay after a transmission line was taken out of service early last year so the local grid could be upgraded. Cheaper generation or demand response were not available in the area to offset its impact, so PJM requested it suspend the rule in this case as the higher prices were incapable of eliciting any kind of market response.
FERC approved PJM’s request, with a dissent from Commissioner James Danly. Energy trading firm Citadel FNGE appealed the decision to the D.C. Circuit. Judge Justin Walker (a Trump appointee) dissented from the majority in the case, saying the court should have remanded it to the commission. (See FERC Approves Pause of PJM Tx Constraint Penalty Factor in Va.)
Chief Judge Sri Srinivasan and Judge Patricia Millet (both Obama appointees) sided with FERC, saying it was reasonable to suspend the rule, which is meant to get a market response that ultimately would solve the congestion at issue.
“Because application of the penalty factor increased costs for consumers without a commensurate benefit, the commission reasonably found that its application in this context was unjust and unreasonable,” the court said.
The TCPF represents the maximum cost that PJM will incur to resolve the problem-causing congestion, with an algorithm seeking the least-cost way to relieve congestion, which if not available leads to prices of $2,000/MWh.
With the transmission line out, the peninsula’s customers could be served only by two other transmission lines and a set of combustion turbine units.
“That lack of available resources caused the local marginal price to fluctuate drastically in times of congestion,” the court said. “For example, even when the turbine units were fully operating in the early morning hours, they were insufficient to prevent congestion, so the penalty factor kicked in.”
Local solar plus those combustion turbines were able to mitigate prices when the sun was out, but the penalty factor was unable to send consistent or reliable signs about whether an investment or response to the congestion was needed.
“Material short-term investments would not occur, PJM explained, because new resources would not come online until after the Lanexa line upgrade was completed,” the court said. “At that point, the demand for the newly placed resource would evaporate.”
Citadel challenged PJM, saying the RTO failed to prove a link between the temporary $2,000/MWh prices and what consumers in the area actually paid. It also argued that PJM failed to prove that nothing could respond to the price signals and argued suspending the rule would inject regulatory uncertainty into the market.
The court said FERC was not required to show the spiking congestion costs would impact retail rates because the Federal Power Act refers only to the unjustness and unreasonableness of rates.
“The commission concluded that increased prices on one side of the balance without any value on the other side of the scale — all pain and no gain — were unjust and unreasonable,” the court said.
While customers pay a zonal rate, the higher congestion costs would go into that calculation, leading to overall higher rates, and Citadel failed to show any offsetting impacts, it added.
The firm also argued the suspension would harm the financial transmission rights market, in which it participates.
“But the temporary suspension of the penalty factor in one geographically unique area does not stop financial firms from benefiting from congestion pricing,” the court said. “Financial firms will still receive congestion costs, albeit less in one small part of the grid, during the temporary suspension of the penalty factor.”
Walker’s Dissent
Judge Walker said the court should have remanded the order to FERC for further proceedings, with Citadel’s arguments having convinced him. Transmission expansion was sped up after FERC’s order, which Citadel argued showed the constraint was working.
“Yet when FERC was later given evidence that the penalty factor was incentivizing transmission investment, FERC moved the goalposts,” Walker said. “Instead of reasoning, as it had before, that the rate was providing no benefit, FERC instead said any benefit it provided wasn’t big enough.”
That shift in standards was arbitrary and capricious, so the order should have been remanded, he added.
