FERC responded to ISO-NE’s request for rehearing on its Order 2222 compliance Friday, agreeing to delay the required timing of implementation while providing a clarification about the responsibility and role of distributed energy resource (DER) aggregators and utilities in providing ISO-NE with metering information and data (ER22-983-002).
Order 2222 directed RTOs and ISOs to remove barriers for aggregations of DERs to participate in wholesale markets. ISO-NE filed its initial compliance in February 2022, and FERC partly accepted and rejected it in March 2023. (See FERC Gives ISO-NE Homework on Order 2222.) ISO-NE requested a rehearing at the end of March.
A significant portion of FERC’s order Friday focused on its requirement that DER aggregators be responsible for reporting the necessary metering information to their respective RTO or ISO. In ISO-NE’s compliance filing, the organization proposed to task the host utility — which refers to either a transmission owner or a distribution utility — with this responsibility.
“Shifting the meter reporting role for [DER aggregations] to the DER aggregator would treat DERAs differently from all other resources participating in New England Markets and place them at a disadvantage relative to all other resources,” ISO-NE wrote in its March request for rehearing.
ISO-NE also interpreted FERC’s order in March to require the exclusion of host utilities from the flow of metering information from the DER aggregator to the RTO. ISO-NE argued that because host utilities typically are in charge of metering, giving the responsibility to the DER aggregator while excluding the utility from the process would be difficult to implement and would require new infrastructure and tariff changes.
In its response to the rehearing request, FERC maintained that the DER aggregator is responsible for providing metering information to ISO NE.
The commission said it disagreed with the “underlying interpretation upon which ISO-NE bases its rehearing request” and said Order 2222 “does not preclude metering data coming from or flowing through the host utility.”
“Metering data may come from or flow through distribution utilities if ISO-NE coordinates with distribution utilities and relevant electric retail regulatory authorities to establish protocols for sharing such metering data and explains how such protocols minimize costs and other burdens and address concerns raised with respect to privacy and cybersecurity,” the commission wrote.
FERC said this clarification would preclude the need for the significant metering changes and burdens highlighted by ISO-NE in its rehearing request.
Also in Friday’s order, FERC sustained part of the March order directing ISO-NE to explain or alter its measurement requirements for some classes of behind-the-meter DERs.
Time Change
In ISO-NE’s initial compliance filing in 2022, the RTO wrote that it would need a response from FERC no later than Nov. 1, 2022, to include distributed energy capacity resources (DECRs) in Forward Capacity Auction (FCA) 18, which is scheduled for 2024 affecting the 2027/28 capacity commitment period. Since FERC did not make a determination until March 2023, ISO-NE argued in its rehearing request that it should not be required to include DECRs in FCA 18.
FERC accepted this request Friday, noting ISO-NE has proposed a new effective date that would require DECRs to be included in FCA 19.
Commissioner Christie’s Dissent
Commissioner Mark Christie dissented with Friday’s order, as he did with the commission’s order in March regarding ISO-NE’s compliance filing.
“Today’s order represents yet another example demonstrating that Order No. 2222 has created nothing short of an incomprehensible quagmire bearing a substantial price tag that will inevitably add to the rising power costs already faced by consumers,” Christie wrote.
He expressed his concern that the order does not adequately address ISO-NE’s concerns and will require “yet another return to the drawing board for ISO-NE and its market participants.”
Christie added that the order “uses the ‘clarification’ as a sword to dispense with the rehearing request, but also as a shield from providing substantive explanation on how this ‘clarification’ addresses each of ISO-NE’s problems and concerns.”
California needs both building-focused and material-focused approaches to driving down the embodied carbon in new construction if it is to reach the state’s net zero goals, according to a new study.
Policies such as state and local building codes requiring low-carbon materials need to be adopted along with strategies such as reusing existing buildings and minimizing new construction, the Embodied Carbon Reduction Roadmap report, authored by Arup, a sustainable development consultancy, for the Natural Resources Defense Council (NRDC) found.
The study quantified the reduction potential of strategies for new residential and commercial construction in California and the state’s ability to meet its 2045 net zero goal under Executive Order B-55-18, or its more aggressive 2035 net zero goal under AB 2446. The study focused on California “due to its capacity, leverage and track record for lowering barriers and risks for others in the nation and around the world.”
A building’s embodied carbon is the emissions related to materials extracted, processed and transported to the site as well as generated by the construction process and its end of life. It does not include emissions related to operating the building, which are about three times the embodied energy over a building’s lifetime, according to a study on reducing embodied carbon emissions in the building construction sector released last week. (See New Buildings May be the Next Climate Solution.)
The NRDC report grouped embodied carbon reduction strategies for buildings by those that optimize reductions at the project level, in the building systems or at the materials procurement level. “A building-focused approach uses whole building life-cycle assessment to evaluate performance. A material-focused approach uses environmental product declarations to evaluate performance.”
The study found that in the near term, optimizing the project provided the greatest opportunity to reduce the embodied carbon of buildings, while in the long term, optimizing the building materials procured made the biggest impact. However, if new, lower-carbon materials are brought to market more quickly, then optimizing procurement will make the biggest impact in the near term as well.
The highest impact strategy to cut buildings’ embodied carbon is to use low-carbon concrete, though no single strategy will enable the state to reach its net zero goals. Minimizing new construction, reusing buildings and buying low-carbon steel and insulation are the next most effective strategies to reduce new construction’s Global Warming Potential (GWP).
As far as policies go, those that encourage clean procurement have a larger impact than building codes, though both are substantially bigger levers than zoning, climate commitments, training and education or waste and circularity policies.
Local Policies Vital
The report called for more policies to encourage design and construction practices that lower whole-building emissions.
“While many emerging policies address material-level carbon performance, it is recommended that more focus goes into policies that encourage project- and building-scale reductions. This study has shown the gap and opportunity of policies focused on planning and design of whole buildings. Advancing building-focused policy approaches at the same time as materials-focused approaches would accelerate the buildings sector towards a zero-carbon future.” the report said.
It’s not just state-level policies that are important; city and county policies can be critical to driving building improvements and can play a role in raising the bar. In 2019, Marin County was the first local jurisdiction in California to adopt embodied carbon requirements in its base building code amendments, and since then, other jurisdictions have adopted code amendments and “stretch codes” that go even further, such as requiring all-electric new construction. California has approved building changes to include mandatory embodied carbon requirements in the state’s green building code, CALGreen, which should go into effect in 2024.
“Policies impacting building embodied carbon are vast and applied ranging from the hyper-local level to the state level. Some policy types more directly prescribe embodied carbon performance, while other policy types have indirect impacts to embodied carbon. The broad range of policies presents both a challenge and opportunity, in that multiple levers can be explored to enact change.”
Policies requiring the use of lower-carbon materials impact both public and private developments, and while they influence a building’s design, often it is the contractor who is responsible for procuring materials that conform with the policy, the report noted.
VALLEY FORGE, Pa. — The PJM Market Implementation Committee endorsed two proposals intended to include multi-schedule modeling in the market clearing engine (MCE) without causing performance impact because of the large number of additional offers the engine would have to consider. (See “Discussion Continues on Multi-schedule Clearing in The Market Clearing Engine,” PJM MIC Briefs: Sept 6, 2023.)
PJM’s proposal, which would create a formula to select the offer expected to produce the lowest total dispatch cost and forward only that offer to the MCE, received the greatest amount of support and will be considered the main motion before the Markets and Reliability Committee. A joint PJM and GT Power Group proposal was also endorsed by the committee and would select resources’ cost-based offers when they fail the three-pivotal-supplier (TPS) market power test and their parameter-limited offers during emergency conditions.
The problem statement that PJM brought forward in December 2022 states that each resource schedule entered into the MCE is modeled as a logical resource. When paired with the number of configurations that combined cycle and storage resources can enter schedules for, the introduction of multi-schedule modeling would cause an exponential increase in the number of logical resources the engine would have to process, potentially leading to untenable increases in computational times. All five proposals aimed to reduce the number of schedules that are submitted to the MCE prior to the optimization process.
Three proposals from the Independent Market Monitor, including one jointly sponsored with GT Power, failed to receive majority support. During first reads in September, Deputy Monitor Catherine Tyler told the MIC that the proposal’s goal was to solve the performance issues that multi-schedule modeling is expected to pose while also improving market power mitigation. She also argued that the PJM proposal could be dispatched on schedules that don’t match the most cost-effective fuel and that it would allow generators with market power to raise energy prices by using high markups and to extract uplift using inflexible parameters.
The first Monitor proposal would combine the lowest offer points and most flexible parameters from resources’ price- and cost-based offers under certain scenarios; impose offer capping and parameter limits to all resources that fail the TPS test; and apply parameter limits to capacity resources during emergencies. The Monitor’s second package would do the same as above but would use the status quo rules for resources with multiple cost-based offers.
The joint Monitor and GT Power proposal would commit resources that fail the TPS test and have multiple offers to operate based on the fuel that the generation owner expects to use in each hour of the day. Tyler said that any generators not submitting the most efficient offer may be considered to be engaging in market manipulation.
Creation of Fifth CONE Area Endorsed
Stakeholders endorsed a joint proposal from PJM, the Monitor and E-Cubed Policy Associates to create a fifth cost of new entry (CONE) area for the Commonwealth Edison region.
The proposal is intended to allow the CONE for the ComEd region to reflect the expected shortened lifespan of the reference resource, a combined cycle unit, under the Illinois Climate and Equitable Jobs Act. (See “Fifth CONE Area Under Consideration,” PJM MRC/MC Briefs: Sept. 20, 2023.)
PJM’s Gary Helm stated that the new CONE value for ComEd will be $201,714/MW-year, compared to $197,800/MW-year in CONE area 3, from which the existing area would be broken out of under the proposal. All other variables, such as labor costs, will remain the same, but they may be revised under the next Quadrennial Review.
E-Cubed had previously sponsored a proposal to create an automated process for adding new CONE areas when local or state factors affect key parameters of the reference resource, such as asset lifespan, or when they may imply a different reference resource than the one PJM has designated.
Capacity Obligations for Forecasted Large Load Adjustments
Stakeholders approved an issue charge brought by Dominion Energy and American Electric Power to consider changes to how capacity obligations are allocated following a large change in the load in one or a small number of load-serving entities.
Josh Burkholder of AEP said that the capacity obligation accounting for such a change in load is allocated across all entities within the zone, regardless of whether they are under fixed resource requirement (FRR) or Reliability Pricing Model (RPM) rules.
Unlike standard changes in load, the problem statement argues that large load customers, such as data centers, tend to be geographically concentrated in one region that can be tied to one or a handful of LSEs. It states that the issue is isolated to forecasted loads, as once they come online, their actual consumption is accounted for in the capacity obligation assigned to the LSE.
The issue charge was revised following a first read at last month’s MIC to revise the focus from being on large load additions to adjustments, to reflect that forecast reductions in load can have a similar effect. The scope was also clarified to include the assignment of obligations between RPM and FRR markets as well as individual LSEs. The stakeholder process was also changed to the full consensus-based issue resolution (CBIR) process, instead of the abbreviated CBIR Lite pathway, and the estimated timeline was revised to four months with the goal of having changes that can be implemented in the 2025/26 Base Residual Auction (BRA) if feasible.
Burkholder said the issue charge would not change the settlements process but instead focus on how capacity obligations for identifiable forecast large loads are allocated. Settlements are in-scope only to avoid any unintended consequences.
Calpine’s David “Scarp” Scarpignato made the case that the issue extends beyond load changes in regions served by RPM entities resulting in changes to the capacity obligation for FRR resources, saying that a significant change in load within an LSE whose footprint lies in multiple transmission zones can result in that impact bleeding across zones.
PJM Reviews Board of Managers CIFP Letter
PJM Vice President of Market Design and Economics Adam Keech said the RTO is on track to make a FERC filing by the Oct. 13 deadline the Board of Managers set in a letter announcing a slate of capacity market changes resulting from the Critical Issue Fast Path (CIFP) process it initiated in February. (See PJM Board Releases Outline of Capacity Market Changes.)
To meet the aim of having changes that can be implemented for the 2025/26 BRA, Keech said FERC approval would be required by early February to leave time for pre-auction activities and for market participants to prepare. Portions of the changes being proposed involve processes that begin toward the start of the pre-auction activities, meaning an order is needed before work can substantively begin.
Keech said two approaches that PJM could take when drafting the filing would be to either ask the commission to delay the auction until an order is released, or to state that the RTO will begin with pre-auction activities under the current rules unless directed to do otherwise. Any delay to the 2025/26 auction would likely mean changes to the timeline for subsequent auctions as well because of how tightly packed together they are.
PJM is also discussing whether it is best to proceed with a single filing encompassing all of the proposed changes, or to break it into two filings, grouping together changes that staff believe would have to be made as a package. Keech said he believes that changes to performance assessment intervals would have to be linked with the market seller offer cap because there’s a connection between the two with the eligibility to receive Capacity Performance bonus payments.
PJM Senior Counsel Chen Lu said staff considered waiving the RTO’s right to preclude the commission from conditioning approval of a Federal Power Act Section 205 filing under NRG Power Marketing v. FERC, but they determined that not all of the components of the proposed changes are severable.
Keech said the board is currently deliberating the direction and best forum to hold further discussions of issues that are not expected to be resolved through the filing, such as a seasonal capacity market.
PJM last week presented a shortlist of three scenarios of transmission upgrades to address needs identified in the 2022 Regional Transmission Expansion Plan (RTEP) Window 3. (See “Update on RTEP Windows,” PJM PC/TEAC Briefs: Aug. 8, 2023.)
“There is a lot of interest in this particular planning window. … This is a major expansion of our transmission system,” PJM Senior Vice President of State Policy and Member Services Asim Haque said during an Oct. 3 meeting of the Transmission Expansion Advisory Committee (TEAC). “We’re facing some serious changes to the electric grid in this area based on increase in the electric demand and retirements of fossil fuel generators.”
All three scenarios would expand the 500-kV grid, and potentially construct the first 765-kV line in the Dominion region, to meet growing data center load and generation retirements such as the 1,295-MW Brandon Shores plant. PJM Executive Director of System Planning Dave Souder said more information about the potential of a reliability-must-run contract being reached with Talen Energy should be available around the end of the year. (See “Brandon Shores Deactivation to Require $786M in Grid Upgrades,” PJM PC/TEAC Briefs: June 6, 2023.)
PJM received 72 proposals from 10 entities, portions of which were combined to form two scenarios. Only NextEra’s proposal #175 was selected as a shortlisted scenario without PJM modification. PJM’s Sami Abdulsalam said the RTO plans to bring one of the shortlisted scenarios to stakeholders for a first read Oct. 31 and to the board for approval in December.
PJM shortlisted a NextEra and two aggregated proposals to meet transmission needs identified in its 2022 Regional Transmission Expansion Plan (RTEP) Window 3. | PJM
The 765-kV line proposed in one of the two aggregate PJM scenarios would begin at the Joshua Falls substation and run north to the data center alley in Loudoun County, Va.
One of the PJM plans would construct a 765-kV line between the Joshua Falls and Yeat substations, bringing power into Loudoun County from the south. Additional transmission capability would also be constructed to the northeast, tapping into the 500-kV grid at Peach Bottom.
PJM’s other scenario focuses on expanding the 500-kV grid by building new lines from northern Virginia out to Peach Bottom to the northeast and the 502 Junction substation to the northwest.
Both scenarios include additional 500- and 230-kV lines that would be built in the BGE zone to meet some of the expected need created by the Brandon Shores retirement.
The NextEra scenario would follow a similar 500-kV pathway between the 502 Junction and the data center alley, as well as several 500- and 230-kV lines to the northeast routing through a proposed Barthlow substation and continuing to the Conastone and New Otter Creek facilities.
Two 230-kV lines would be constructed between the Keeney substation on the Delmarva Peninsula, across the Chesapeake Bay and connecting to the Waugh Chapel substation in the BGE area.
Abdulsalam said each of the scenarios comes with positives and negatives. The NextEra scenario would avoid modifications to the Doubs substation, which has become the terminus for an increasing number of lines, while the Barthlow substation would have nearly a dozen lines tying into it. The scenario would also require significant acquisition of new rights of way and the component running a line under the Chesapeake could pose voltage concerns in BGE, as well as environmental and permitting concerns.
The 500-kV scenario offers the advantage of avoiding disruption to the Conastone substation and having strong cost containment for the component constructing a line between Doubs and Otter Creek. The 765-kV plan would relax flows in the north with the addition of the higher voltage transmission proposed in the south and would add to the backbone capability in Dominion. Siting, permitting and procuring equipment for a 765-kV line comes with higher risk, but Abdulsalam said the 500-kV components of the scenario could provide short-term relief while the 765-kV is built.
Abdulsalam said the proposals contain commonalities that demonstrate a general understanding that additional transmission capability will be needed to move energy from the east to the west, augmented by transmission either from the south or northwest.
PJM’s Nebiat Tesfa said planning staff used a combination of NextEra, Exelon, FirstEnergy and Dominion proposals as a starting point to construct its aggregate proposals, in some cases working with proposing entities to break out individual components to combine with portions of other proposals. Analysis of combining several LS Power, Transource and NextEra proposals found a larger number of violations in the 2028 case.
Of the 72 proposals, 50 involve greenfield development of new lines, while the remainder are upgrades or construction within existing rights of way.
PJM’s characterization of the impacts and risks that greenfield proposals carry was disputed by several residents who live in the communities some of the projects would pass through. They argued that expanding rights of way to construct lines paralleling existing infrastructure would have a larger impact than is represented in PJM’s analysis and that the extent of the amount of greenfield was underplayed.
The window contains models for both 2027 and 2028, with the primary differences being that the latter includes more deactivations, including Brandon Shores, and adjustments to how resource dispatch is reflected in the analysis. Both the Brandon Shores retirement and the changes to block dispatching came after PJM had released the 2027 case, but before the following year had been finalized. (See “Load Forecast for Northern Virginia Data Centers Continues to Climb,” PJM PC/TEAC Briefs: Jan. 10, 2023.)
Exelon’s Alex Stern encouraged PJM to reach out to both the relevant incumbent transmission owners and state commissions regarding any non-incumbent proposals that include underbuilding on existing lines, particularly if it could cause states to lose jurisdiction. Incumbent TOs are also likely to have more detailed insight into anticipated needs in their region and may have a use for the underbuilding capability they were planning to use in the future.
After an initial assessment of the potential of each of the 72 proposals, PJM created an initial shortlist for more detailed analysis of their cost estimate, cost containment, scheduling, constructability, brownfield and outage coordination risks. The risk assessment also considered permitting, potential environmental issues and public opposition to past projects.
BOSTON — With construction underway for the country’s first large offshore wind projects, government, nonprofit and industry representatives from across the U.S. came here to discuss the industry’s progress and prospects for the American Clean Power Association’s Offshore WINDPOWER conference.
The slogan for the conference (“STEEL IN THE WATER. PEOPLE AT WORK.”) — which was featured prominently on the merchandise, the pre-conference trailer video, and screens and posters throughout the convention center — invoked this major first step forward for the industry.
There was great uncertainty about when the next wave of steel will hit the water on the East Coast and the people these projects will employ will get to work. The developers for Massachusetts’ Commonwealth Wind and SouthCoast Wind projects backed out of their power purchase agreements in recent months: Avangrid reached an agreement at the start of this month to exit the PPAs for its Park City Wind project in Connecticut; Rhode Island’s electric distribution company rejected the only bid from its last solicitation; and four New York projects under active development are in limbo as they seek better terms for their contracts.
While developers can rebid projects that have canceled their PPAs at future auctions, the question remains whether they can find a price that states and utilities deem acceptable to pass on to ratepayers. But speakers at the conference argued that it was only a matter of when, not if.
At a panel featuring state legislators from Massachusetts and California, Massachusetts Rep. Jeff Roy (D-Franklin), co-chair of the Joint Telecommunications, Utilities and Energy Committee, urged developers to send in strong bids for the state’s solicitation and boasted about “the most robust wind in the entire contiguous United States right here off the coast of Massachusetts.”
At the same time, Roy said, the state will be faced with difficult questions around “how much are we willing to spend” when the project bids are due at the end of January.
Supply Chain, Interest Rates and Inflation
“It’s easy to focus on the doom and gloom of the moment right now,” Sam Huntington, director of climate and sustainability at S&P Global, said at a panel on global economics and offshore wind. “There’s still a lot of room for optimism. … There’s just a tremendous commitment to this.”
The industry has been hit with “a perfect storm of supply chain snarls,” Huntington said.
Walt Musial, a principal engineer at the National Renewable Energy Laboratory, said cost pressures from high interest rates and expensive commodities like steel should subside in the coming years. However, “there’s still going to be this issue around supply chain deficits and the inability of suppliers to meet demands.”
As countries and developers across the world all look to scale up offshore wind at the same time, the panelists expressed worry that delays could push the next round of projects back into the 2030s.
In the long term, Musial said he remains confident about the industry, calling it a “cornerstone” of New England’s future electricity supply.
“With climate change as a background, we have to do this,” he said.
Søren Lassen, head of offshore wind research for Wood Mackenzie, called the supply chain issues the industry’s “greatest challenge.” He said the combined issues of supply chain constraints, high interest rates and inflation hit the nation’s industry right as it was trying to make the jump from a small, subsidized industry to the commercial scale.
Lassen said these setbacks could put national and statewide clean energy commitments in jeopardy: An August report by his firm found governments across the world (excluding China) would need to invest about $100 billion in the supply chain by 2026 to meet their 2030 offshore wind goals. (See Report Quantifies OSW Supply Chain Constraints.)
“We don’t think that’s feasible, to be frank,” Lassen said.
Supply chain constraints could also be the limiting factor for the size of offshore wind turbines, which have increased rapidly in recent years. While Huntington said that larger turbines could be the key to lower costs in the long term, Musial cautioned that further increases in blade sizes will only put additional stress on the existing supply chains.
Musial said that industry should “double down” on 15-MW turbines to flatten the learning curve and bring costs down.
For context, Vineyard Wind 1 is being constructed with 13-MW turbines, while Vestas has been testing its 15-MW prototype this year, and General Electric is developing an 18-MW prototype.
“Any attempt to go larger than [15 MW] will just delay progress,” Musial said.
On a panel about installation vessels, Graham Tyson of Crowley Wind Services said that the increase in turbine size is an obstacle to investing in new vessels.
Tyson said investors need “a good eight to 10 years of life out of each turbine class” to justify investment in a new vessel, and either overbuilding or underbuilding the size of the ship poses significant risks.
“You want to know that there’s work for it,” Tyson said.
Speakers throughout the conference called for more federal support for states and developers to help overcome the industry’s recent struggles.
“States cannot do this alone,” said Catherine Klinger Kutcher, director of the New Jersey Governor’s Office of Climate Action and the Green Economy, adding that the state remains committed to offshore wind.
In mid-September, the governors of Connecticut, Maryland, Massachusetts, New Jersey, New York and Rhode Island signed a joint letter asking President Joe Biden for additional federal help for the industry. (See Northeast Governors Ask Feds to Assist OSW Industry.)
“Without federal action, offshore wind deployment in the U.S. is at serious risk of stalling because states’ ratepayers may be unable to absorb these significant new costs alone,” the governors wrote, citing the cost pressures of inflation, lingering supply chain disruptions and Russia’s invasion of Ukraine.
The governors asked Biden for updated guidance on the available clean energy tax credits, a new revenue sharing program for offshore wind leases and a streamlined clean energy permitting process.
In her keynote speech to the conference, Massachusetts Gov. Maura Healey (D) emphasized the importance of federal support, calling for additional resources while applauding the steps that the Biden administration has already taken.
“We can only control so much as states,” Healey said. “We need all parts of the federal administration to work with us to understand that this is our moment.”
Others expressed concern about the effects a new president — presumably Donald Trump, whose name was often implied but infrequently mentioned by speakers — could have on the industry and clean energy efforts more broadly.
Stakeholders should make the best possible use of the Inflation Reduction Act, said Damian Bednarz, managing director of Attentive Energy. “We cannot take any of this for granted,” he said.
SouthCoast CEO Francis Slingsby said stakeholders must specifically push to expedite clean energy permitting processes under the current administration and “make hay while the sun shines.”
Stakeholders Endorse Reserve Requirement Study Values
VALLEY FORGE, Pa. — The Planning Committee endorsed the installed reserve margin (IRM) and forecast pool requirement (FPR) values PJMrecommended in the 2023 Reserve Requirement Study (RRS), which calls for an increase in procured capacity for the 2027/28 delivery year (DY). (See “First Read of 2023 Reserve Requirement Study,” PJM PC/TEAC Briefs: Sept. 5, 2023.)
The IRM, which sets the targeted capacity level above expected loads, would rise from 14.7% for the 2026/27 DY in the 2022 study to 17.6% for the 2027/28 DY. The FPR, which includes forced outage rates, also would increase from 9.18% to 11.65% for the corresponding DYs. The figures are slated to be considered by the Markets and Reliability Committee (MRC) and Members Committee (MC) next month, followed by the Board of Managers in December.
This year’s RRS included a few differences from past analyses, including a second methodology for setting the IRM and FPR using the hourly loss-of-load modeling developed for effective load-carrying capability (ELCC) studies. PJM also included data from the 2014 polar vortex and the December 2022 winter storm, reversing a historical practice to not include the polar vortex data in the study’s modeling based on the impact of Winter Storm Elliott.
PJM’s Patricio Rocha Garrido said the main drivers for the recommended reserve margin increase are higher uncertainty in peak load forecasts and the higher forced outage rates in the winter owing to extreme weather. Shifting to hourly modeling of peak loads, separate from the ELCC analysis, also contributed to the higher margins.
Minimal coincidence between the PJM peak load period and the “world” peak — which is defined as MISO, NYISO, TVA and VACAR — more than doubled the capacity benefit of ties (CBOT) value to 2.2% from 1% in the 2022 study. To reduce volatility, PJM elected to average the CBOT values from 2017-22 and use that figure, which landed at 1.5%, instead.
The load model, which included data from 2013-19, contributed to a 2.1 percentage point increase in the IRM, while the winter peak week caused a 1.1 percentage point increase. The values were slightly lower for the FPR drivers. The 1.5% CBOT contributed to a 0.5 percentage point decline in the IRM value and 0.58 percentage point decrease in the FPR.
The hourly approach resulted in higher recommended values — an IRM of 18.3% for the 2027/28 DY and a 12.31% FPR — with much of the difference from the PRISM values arising from the load model. PJM ran both models for this year’s RRS analysis, but it plans to shift to using the hourly approach only in the long term.
During an August Resource Adequacy Analysis Subcommittee meeting, James Wilson, a consultant to state consumer advocates, calculated the recommended values would constitute an approximate 3,700-MW increase in the summer reserve margin.
More Extensive Guidelines for Load Forecast Adjustment Endorsed
Stakeholders endorsed a PJM quick fix proposal to increase the granularity of the data included in load forecasting requests, as well as how far out it should seek to adjust future load estimates. The quick fix pathway allows a problem statement and issue charge to be brought concurrent with a proposed solution. (See “PJM Presents Quick Fix on Load Forecast Guidelines,” PJM PC/TEAC Briefs: Sept. 5, 2023.)
Under the proposal, load forecast adjustments would need to include a 15-year forecast and the granularity of the load history electric distribution companies (EDCs) and load serving entities (LSEs) are asked to provide would be increased to hourly. If no load history exists, the adjustment request should include the “expected hourly behavior of load.”
Requests would be required to come with a public document detailing how the forecast adjustment was calculated. Also, the process of assessing adjustments would begin earlier, with the Load Analysis Subcommittee (LAS) initiating its work in September and October under the proposal.
PJM’s Molly Mooney said the proposal is focused on data center loads, which are difficult to capture in the RTO’s existing processes, which rely on federal labor data that doesn’t match up well with the electrically intensive data industry. Data center developments also tend to have a short period between their initial requests to interconnect and their in-service date, making advanced forecasting more critical.
Wilson said the proposed language doesn’t make it clear that PJM is seeking only to add the amount of the forecast above the embedded amount and not double count loads already captured in the existing analysis. He encouraged PJM to hire a consultant with the expertise to do a 15-year forecast of data center loads, rather than leaving it up to EDCs and LSEs to report their own expectations and data.
PJM has made some modifications to the proposed Manual 19 revisions since the proposal’s first read in September, specifying that when the RTO conducts annual information requests about significant shifts in load from electric distribution companies (EDCs), it is seeking information about changes within their service areas. The new language also states that any documentation of EDCs’ or LSEs’ internal financial or planning forecasts supplied to PJM will be confidential.
First Read of Periodic Review of Manuals 19 and 14B
PJM presented a first read of several revisions to Manuals 19 and 14B resulting from the documents’ periodic review.
Revisions to Manual 19 added information reflecting the change to hourly peak load modeling in the load forecast and sought to clarify the procedure when forecasting price-responsive demand.
The changes to Manual 14B are intended to clarify that the 300 MW load loss criteria — which is meant to address load loss impacting a large number of customers — would be expanded to specify that it covers numerous customers, rather than single large-load customers such as data centers. PJM also would be granted the ability to review instances of the rule case by case. The criteria is a consideration when modeling outages in the Regional Transmission Expansion Plan (RTEP).
Both sets of manual changes are set to be considered for endorsement by the PC at its Oct. 31 meeting.
Transmission Expansion Advisory Committee
AEP Proposes $216 Million in Transmission to Support New Steel Mill
American Electric Power (AEP) proposed a $215.8 million project to construct several 345-kV lines and a new substation to serve a new industrial customer with an estimated 450 MW load near Apple Grove, W.Va.
In the first phase of the project, two new 345-kV lines would be cut into the Sporn–Tri-State line to run to a new Mercers Bottom 345-kV substation. The customer would be served by two single-circuit 345-kV feeds around 0.75 miles from Mercers Bottom, as well as a 138-kV line that would be cut into the Apple Grove–South Point line. The total phase one cost is estimated at $70.8 million with an estimated in-service date of Dec. 15, 2025, to meet the customer’s request to interconnect by the end of 2025.
Phase two would focus on meeting the customer’s short circuit strength needs under N-1 contingencies and would involve constructing an additional 26-mile 345-kV line from Sporn to Mercers Bottom, accompanied by an additional circuit breaker at Sporn. The projected in-service date for phase two is Dec. 15, 2029.
AEP said the industrial customer is a steel mill planned in the region, but it could not provide further detail at this time. Nucor is planning to construct a $3.1 billion electric arc furnace steel mill in Apple Grove with power supplied by a new Appalachian Power substation, according to an announcement from U.S. Sen. Joe Manchin (D).
Other Supplemental Projects:
Commonwealth Edison (ComEd) proposed a $149 million rebuild of its 26.4-mile Kincaid–Pana (Ameren) line, saying 56-year-old wood poles and components are at their end of life and have sustained woodpecker damage. The line also suffered outages when crossarms broke under clear weather conditions. The project, still in the conceptual phase, has an estimated in-service date of Dec. 31, 2026.
ComEd also proposed a $264 million project to replace a 345-kV straight bus with a gas insulated substation with 34 circuit breakers in a breaker and half configuration. The utility stated that 14 breakers are deteriorating and a failure of one could cause an outage on seven 345-kV lines and two autotransformers. The project is in the conceptual phase with an estimated in-service date of Dec. 31, 2028.
Dominion submitted needs for two new 230-kV substations, World Gate and Mercator, in Fairfax County, Va., to serve data centers with loads exceeding 100 MW. The needs have a targeted in-service date of June 1, 2027.
AUSTIN, Texas — The Gulf Coast Power Association welcomed a record 829 attendees to its 38th annual Fall Conference, smashing the previous high of 766. They gathered Oct. 2-4 for discussions and vignettes on virtual power plants, resource adequacy, new technologies, grid resiliency, energy efficiency and demand response.
Stoic Energy’s Doug Lewin, introduced as “a man who has commandeered a cultlike following for his insight and passion for clean power and efficient solutions for greater reliability and resiliency” and a “voice of many too nervous to speak,” keynoted the conference’s second day and its focus on energy efficiency and residential demand response.
That has been Lewin’s north star since the disastrous 2021 winter storm that nearly brought down the ERCOT grid. A prolific user of the social network formerly known as Twitter, he has consistently espoused efficiency and residential demand response as answers to ERCOT’s difficulties in meeting soaring demand.
Armed with charts, graphs, news clips and data to bolster his point, Lewin asked, “How do we create a highly reliable grid at the least possible cost that will provide abundant and cheap power to as many people as possible?
“Texas has been focused on reliability for a while now, but affordability is also a key part piece of the puzzle,” he added. “Texas ranks last in energy burden, with nearly one out of every two Texans struggling to pay their electric bills. This needs attention and hopefully, each of us also agrees the solution must include creating a grid as clean as possible. Balancing reliability, affordability and sustainability … will create good-paying jobs, profits and wealth creation, tax base and economic growth. We stand to gain a huge share of investment wealth if we can show the world how to build a reliable, affordable and sustainable grid, and especially [if] we can center that grid on customers and strategies that empower them.”
The key, Lewin said, is shaving high loads by creating flexible demand where residential consumers can use less electricity when it’s scarce and more when it’s abundant.
“And they’ll get paid for it,” he said. “No more [ERCOT] conservation calls, which is nothing but a euphemism for uncompensated demand response.”
Lewin had an ally in Octopus Energy CEO Michael Lee. His electric retailer has more than 5 million customers in nine countries and says they can access affordable power during the transition to clean energy.
“As a load-serving entity, my ERCOT bill reflects when people use power, so we need to really shift away from thinking about megawatts,” he said. “We need to really think about customers. We have the opportunity of a lifetime to consumerize electricity. We should get creative and say how do we take costs out of the system and reward people for doing so. You have to consumerize it. You have to make it approachable.”
VPPs No Longer the ‘New Kid’
The pre-conference workshop on virtual power plants, “New Kid on the Block: Virtual Power Plants in ERCOT,” may have been a misleading title, its keynoter said.
“Distributed energy resources (DERs) that go into this concept of a virtual power plant are already here. It is not actually a new kid on the block. It is one of the oldest forms of how we supply power to ourselves,” Arushi Sharma Frank, senior counsel and U.S. energy markets policy lead for Tesla, said.
“The entire grid was distributed before we actually chose to centralize it, so we are actually going kind of back in time and forward [in] time at the same time,” she said. “The reason that these things are all showing up in droves without any particular market design or incentive to get them there is because people value losing load at a much higher dollar number than what the grid thinks they value.”
Frank vice-chaired an ERCOT pilot project that spent a year studying aggregated DERs and resulted in two VPPs qualified to provide dispatchable power to the state’s grid. Eight aggregations (ADERs), totaling 7.2 MW, participated in the pilot project. Two ADERs using Tesla Electric Powerwall storage systems have completed required testing and could provide energy and ancillary services through the third quarter. (See Texas Public Utility Commission Briefs: Aug. 24, 2023.)
As a consultant experienced with the “labyrinth of ERCOT systems,” Eric Goff was asked by Texas Public Utility Commissioner Will McAdams about the project’s operability.
“The fastest way to commercialize something new, the quicker you can actually make it happen,” Goff responded. “There are so many chicken-and-egg problems that having a laboratory to get things starting to commercialize was the fastest path forward. Now, that said, the pilot nomenclature and size can scare away some investment, so the sooner we can move towards permanent rules, the sooner we can get even more investment and even more participants on this program.”
That may not be easy. Aaron Berndt, head of energy industry partnerships for Google, said the main barrier to entry in ERCOT’s competitive market is the competitive market.
“It really is as simple as either [a] state or the utility saying, ‘We have got to come up with ways to fill this gap,’ and looking at my list of options to get there. If they’re in a state where it’s in their best interest to drive energy efficiency and demand response, they can just pile it up into big numbers to scale their program,” he said. “You could be scaling Texas energy efficiency programs and just make it easier for retailers to leverage the energy efficiency incentives and stats and use those to enroll them into their demand response program. Then they definitely have the ability to dispatch in a competitive market.”
McAdams offered his own counterpart: “$5,000 a is a hell of an incentive,” he said, referencing ERCOT’s systemwide cap price of $5,000/MWh during scarce operating conditions. “That’s every reason in the world where a consumer that has the means and capability and wherewithal, or even an apartment building, that wants to install the capability to avail themselves of this market.
“This is actually providing them a healthy return on investment. I want to get us past the stage where there are all these assertions that we were going to Californiaize the ADERs. We are all in this together … if we can solve the question of how to pay for system upgrades equitably as a systemwide cost, that goes hand in glove with this conversation about bringing more and more of these capabilities to market.”
Vegas Gives ERCOT an ‘A’ This Summer
Oncor Energy’s Brian Lloyd again displayed his off-beat skills in moderating panels when he opened a conversation with ERCOT CEO Pablo Vegas and MISO CEO John Bear by asking, “So, how was your summer?”
“It was a mix of ups and downs,” Vegas said, acknowledging 10 peak-demand records, multiple voluntary conservation calls, and one energy emergency alert. “Overall, I’m really thankful for the way the summer turned out. It was a great way to learn the capabilities of the organization. I am optimistic looking ahead, that summer should hopefully get a little bit easier.”
“I was asked a couple times what kind of grade I would give the performance,” he added. “I said, ‘Probably an A,’ and they’re like, ‘An A? How can you give an A with conservation calls and emergency conditions?’ I would say, ‘When you’re tested as hard as we were this summer and you pass it, you’ve got to give it an A.’”
Later turning to Bear, Lloyd asked, “Got any plans for the winter?”
Bear responded that he wouldn’t be hosting a holiday party, as he did last year for about 100 people on Christmas Eve. He said he spent the party sequestered in his study as Winter Storm Elliott swept through the Midwest.
“We talk a lot about summers, but the summer is a lot easier than the winter now, for all kinds of reasons and challenges we’re getting into as we get under our reserve margins,” Bear said. “So, how … we figure out the balance between the summer and the winter from the transmission and generation standpoint is going to be really important.
“We’re talking a lot about electrification like that’s the miracle that happens in 2030, right? There may be some slope in that curve, right? There’s a lot of manufacturing and offshoring and things like that going on that we hear about, but where are the assets that are going to provide that energy that businesses need?”
Vegas said the winter season is a “growing risk” for ERCOT, despite its status as a summer-peaking grid, but that the grid operator is taking steps to improve reliability.
“The winter peak is growing and getting closer to the summer peaks as there’s more electrification or conversion from gas to electric heating. Since Winter Storm Uri [in 2021], the whole mindset around the winter has really changed in Texas,” he said. “The weatherization program is fantastic … It has been effective, and it was proven to help significantly during Winter Storm Elliott. We have to prioritize where we’re investing our resources so that we can partner with the generator community and work together to make sure the resources are going to be reliable.”
State Rep Offers Advice
Texas state Rep. Todd Hunter (R), chair of the powerful State Affairs Committee, complimented the state’s electric sector for its response to the 2021 winter storm. Or “Snowcane Uri,” as he refers to the deadly event that sent temperatures below freezing in all 254 Texas counties.
“That’s rare. We can point the finger, blame everybody. What came out of it? Some new, developing legislation and communication,” he said.
Much of that legislation came through Hunter’s committee this year. He encouraged the audience to stop by his office and visit or keep him updated on the latest developments in the sector.
Citing one of the state’s transmission and distribution utilities, Hunter said, “They send me all sorts of texts, which is important for me to know. I’m talking to legislators and I’m talking to other people, so we have a flow of information. Legislators rely on me because that’s how I roll. When I know ya, I hear ya.”
Hunter, who prefers to wear only black and speaks in a country drawl, implored his audience to stay engaged with state lawmakers.
“The more you talk to us, the more we can help you. Most people don’t know what you do. They don’t know what a megawatt is. It sounds like a new burger from Whataburger,” he said. “We need power, water and labor. The economy is evolving and growing. We need laws that make sense.”
He pointed to the Harbor Bridge Project in his hometown, Corpus Christi — which he managed to mention 14 times — as a sign of Texas’ booming economy. The new bridge will enable more LNG exports from the city’s harbor. When complete, it will also be the tallest structure in South Texas and the longest cable stay bridge in the US.
“When you see this area, it’s like the unveiling of a portrait,” Hunter said. “Giant demand is coming. Whether you’re hydrogen or batteries, we already have stack-ups of different businesses coming into the area. That’s happening across Texas. Electricity is big.”
GCPA’s Casey to Retire
Saying he was both “proud and sad,” MD Energy Consulting’s Mark Dreyfus and the GCPA’s board president told attendees that Kim Casey has notified the directors she intends to retire next year.
“She entered this position with a passion for GCPA and she will depart us with that passion intact. I think that’s the best possible outcome for all of us,” Dreyfus said. As Casey stood uncomfortably next to him, he said, “Kim will be with us until June 1, so there will be plenty of time to honor and further embarrass her.”
“I’ve been coming to GCPA since 1996. I’ve not missed one single conference since then, so it’s been a pleasure to be part of this and to bring all of you together and it’s meant a lot to me,” Casey said after receiving a standing ovation. “Thank you to the board for your support and thanks to all of you.”
Casey was selected as GCPA’s fourth executive director in 2019, bringing more than 30 years of industry experience with her. Under her leadership, the organization survived the COVID-19 pandemic and now has more members than ever in its 40-year history.
Dreyfus said the board will conduct an open hiring process to find Casey’s replacement, with applications accepted through Nov. 15. The organization hopes to announce her successor during its annual spring conference, he said.
“We know that there are many talented participants in GCPA who have a passion for this organization and a great Rolodex, who may be interested in taking a different role,” Dreyfus said.
The GCPA honored Octopus Energy’s Lee with its annual emPOWERing Young Professionals award, which recognizes industry individuals under 40 years old who provide leadership and contribute to the success of their employer, the power market and the development of other industry professionals.
Lee has worked on some of the earliest energy storage projects and spent more than a decade in the renewables space. A Harvard graduate, he launched Evolve Energy, an energy retailer that focused on real-time index pricing paired with load-shaping automation software and later was acquired by Octopus, now valued at $5 billion. GCPA cited his use of technology to create “demand-centric solutions” for a more resilient grid.
“I would encourage everyone to think that this is not just an empowering young professional award, but also, as an industry, how do we empower disruptors?” Lee said. “We can continue doing what we’re doing and make things more expensive and what I think is probably less reliable, or we could do something new. We have incumbents who have established business models and the status quo. But we have disruptors that can do stuff faster, better and cheaper nipping at the heels. So how do we as an industry empower the disruptors?”
SEATTLE — The Western electricity sector is at a “pivotal point in a lot of different ways,” Southern California Edison CEO Steven Powell said last week at a biannual conference of the region’s utility regulators and state energy officials.
Powell’s take on the sector was shared by many attending the joint fall meeting of the Committee for Regional Electric Power Cooperation and Western Interconnection Regional Advisory Body (CREPC-WIRAB) on the city’s waterfront. He was speaking Wednesday on a panel exploring the potential benefits of a more organized electricity market in the West, as well as the issues arising from the competition between CAISO’s Extended Day-Ahead Market (EDAM) and SPP’s Markets+ for future participants.
The outcome of that contest will set the course for the development of an RTO in the West, or two RTOs split by a seam, many in the sector think.
Powell said his utility “strongly believes that we should all be fighting for and working for getting to a single market in the West.”
“That is what is going to drive the most benefits broadly for customers and support the environment the best,” he said. He also acknowledged the challenges of getting the entire region on board for one market because of continued concerns about the lack of independence in CAISO’s governance.
Powell’s view had a lot of sympathizers in the audience, including the handful of utility commissioners who this summer proposed the West-Wide Governance Pathway Initiative, an effort to create an independently governed entity that would underpin a West-wide RTO that pointedly includes California and also contract with CAISO for market services. (See Stakeholders: Pathway Initiative Offers ‘Fresh Look’ at Western Market.)
The single-market perspective found support Friday from participants on a separate panel covering the challenges large energy customers face in procuring energy in a region fractured into 38 balancing authority areas.
Peter Ewen, regulatory strategy lead at Freeport-McMoRan — the largest copper producer in the U.S. — said his company spends $400 million to $500 million a year on electricity to power its Arizona mining operations, equal to about half the outlay of one of the largest utilities in that state.
Freeport-McMoRan operates a division to procure wholesale electricity and, like others who trade power in the West, has seen liquidity dry up in regional bilateral markets over the past five years. Ewen said the company can more cost-effectively obtain power for its operations in South America, where organized markets predominate, than in the Western Interconnection.
The company doesn’t have a “particular point of view” on whether CAISO or SPP should be the dominant market operator in the West, Ewen said. “We do think that one balancing authority as opposed to two is the best solution, but two is certainly better than 38.
“We do also see that a full RTO to provides all of kinds of benefits for the challenges that we’re seeing. … Stopping with a day-ahead market would be stopping short,” he added.
Sharing the panel with Ewen was Jordan Weiszhaar, program manager for data center energy cloud operations at Microsoft. Weiszhaar said much of the talk around organized Western markets is about reliability; she wanted to focus on how a market could encourage economic development.
“What we’re realizing is that what drove growth — economic development — over the last 10 years is going to be very different than what is driving the growth over the next 10 years. And how it’s going to be different is how it interacts with electricity — and I’m not just talking about [growth in] data centers,” she said, pointing to the increasing electrification of transportation and buildings.
In the face of that growth, Weiszhaar said, Microsoft is seeking to expand its data center operations, looking to reliably offer its customers critical services while still meeting its 2030 carbon-free energy target.
“In terms of what our largest challenges are in growing in the West … we are in such a large growth stage right now, we’re going wherever we can find capacity available on the grid,” Weiszhaar said, what Microsoft calls its “energy-first” expansion strategy.
Finding where that capacity will be in the future is especially difficult in the West’s fractured landscape of dozens of balancing authorities, where some planners can under-prepare for load growth.
“From our perspective, we can have fewer organized markets, where we have transparent price signals that show where loads are coming online, but also where the economic development has an opportunity to build … We’re going to have a much more efficient system to take advantage of the [economic development] opportunity coming in,” she said.
Speaking on the markets panel Wednesday, Western Area Power Administration CEO Tracey LeBeau said her federal agency has been exploring RTOs for about 20 years.
“There’s several that almost came together and then fell apart at the last moment,” she said.
LeBeau said WAPA’s eastern customers have differed from those farther west in their desire to jump into a full RTO without taking incremental steps such as participating in something like CAISO’s real-time Western Energy Imbalance Market. In 2015, WAPA’s Upper Great Plains-East Region joined SPP. In September, the agency issued a decision authorizing its Colorado River Storage Project, Upper Great Plains and Rocky Mountain regions to join SPP’s RTO West. (See WAPA, Basin Electric Commit to SPP’s RTO West.)
“Eight years of experience working in that [RTO] context has been very, very successful,” LeBeau said.
She noted that WAPA’s Desert Southwest Region (DSW) this year joined the WEIM and has found prices there to be lower than in the region’s diminishing bilateral market. The agency continues to study the potential for DSW to join a day-ahead market and RTO in the future. She said some of the main drivers for considering deeper market participation include the need for WAPA’s Western customers to hit renewable targets, the retirement of dispatchable generation and the impact of drought on generating resources.
Nevada Public Utilities Commissioner Tammy Cordova pointed out that her state’s Senate Bill 448 requires NV Energy to join an RTO by 2030, although the law doesn’t make it clear whether EDAM or Markets+ would satisfy the requirement.
“We need to really get engaged really fast and figure out what this means in terms of joining an RTO,” she said.
One the biggest challenges for her commission, she said, is to identify what benefits it should be assessing related to joining a day-ahead market or RTO, including those related to rates, reliability and economic development — the last of which could include the potential to sell solar output to other states.
New Mexico Public Regulation Commissioner Gabriel Aguilera brought the market conversation around to the group that utility commissions are charged with protecting: ratepayers.
“The economic, reliability and environmental benefits that we all brag about are only theoretical unless and until we design and implement a market that works for customers,” Aguilera said.
“A market needs transparency, proper oversight, competition, level playing field, good management [and] respect for state and federal policies,” he continued. “All of these elements create the customer benefits that we’re seeing. So in trying to maximize these benefits, as you’re making these decisions to design the market, think about ratepayers.”
A signatory to the Pathways Initiative proposal, Aguilera warned about the impact to ratepayers of dividing the West into multiple markets, saying, “The broadest possible energy market or RTO also offers New Mexico entities a chance to avoid creating or exacerbating significant seams that would result in new costs and burdens that will be borne for decades to come.
“Seams costs between markets are not a one-time thing but are ongoing indefinitely, incurring costs for utilities and customers and raising policy headaches for states for the foreseeable future,” he said.
Generators Cite Reasons for Low Synch Reserve Response Rate
VALLEY FORGE, Pa. — PJMpresented feedback it received from synchronized reserve resources that have come up short in their response to reserve deployments since October 2022, when PJM implemented a market overhaul that was followed by a drop in reserve response rates. (See Synchronized Reserve Pricing Falls in PJM Markets After Overhaul.)
Resources responding to outreach from PJM and the Independent Market Monitor attributed portions of their shortfall to delayed, insufficient or incorrect action at their market operation centers. Factors included missing an all-call signal; not understanding how to respond to a spin event; and incorrect parameters, such as ramp rate, being reported in Markets Gateway.
Some generation owners said they had been operating under the Intelligent Reserve Deployment (IRD) rules that PJM had proposed, but which ultimately were rejected by FERC in August 2022. The IRD proposal would have included a level of reserves being requested from generators; however, the status quo requires that resources provide their full reserve obligation unless directed to do otherwise.
PJM sought to address the diminished response rate by increasing the synchronized reserve requirement by 30% in May, overriding a Markets and Reliability Committee (MRC) vote that rejected the increase. It also proposed to create the Reserve Certainty Senior Task Force to discuss changes to several components of the reserve market and how it operates. The task force has its first meeting on Oct. 10. (See “PJM Issue Charge on Reserve Certainty Approved,” PJM MRC/MC Briefs: Sept. 20, 2023.)
The RTO has published an FAQ and guidance for synchronized reserve resources to improve resource owners’ understanding of how the market functions and their obligations during a spin event.
PJM’s Melissa Pilong told the OC that close to 100 resources responded to the outreach, accounting for approximately 75% of the shortfall by megawatts over the past year. She said PJM’s goal is to find solutions that can allow the reliability requirement to be reduced back to 100% of the single largest contingency.
The OC endorsed conforming revisions to Manual 38 to codify the outage coordination package the committee approved in June. (See PJM OC Briefs: June 8, 2023.)
The package adds coordination between utilities and PJM to identify potential extended outages, evaluate their impact and expand the outage information released by the RTO. The manual language will be considered by the MRC during its Oct. 25 meeting.
A competing proposal from the Monitor, which received 17% support in June, sought to increase transparency about late outages and impacts on transmission congestion.
PJM Proposes Quick Fix for Transmission Cut-in Process
PJM presented a quick fix proposal to allow the RTO to delay the end time of a cut-in ticket by one day if information regarding one of the “critical cut-in tasks” has not been supplied and extending the outage is not expected to pose reliability concerns. PJM will coordinate with the transmission owner to obtain the missing information prior to the line being energized.
The quick fix process allowed PJM to bring a problem statement and issue charge concurrently with a proposed solution. The OC is set to vote on the proposal Nov. 2, followed by the MRC on Nov. 15. If approved, the change would be effective upon MRC endorsement.
PJM’s Dean Manno told the OC that a one-day delay is being sought as review of the information can be done in that time once it’s received.
PJM’s Patricio Rocha-Garrido presented the recommended winter weekly reserve targets (WWRT) values for the 2023/24 winter, which call for a higher level of reserves for each month compared with last winter. The WWRT is used to inform the scheduling of planned outages during the winter to minimize the potential for maintenance to cause a higher loss of load expectation.
The recommended maximum monthly available reserves figure is 28% for December, 30% for January and 25% for February. The values for last winter were 21% for December, 27% for January and 23% for February.
Garrido said this year’s analysis included a higher forced outage rate in the historical data owing to inclusion of extreme weather during the 2014 polar vortex and the December 2022 winter storm. PJM historically had not included the polar vortex data in its analysis, but reversed that based on its experience during Winter Storm Elliott.
The WWRT is one of the three values produced through the annual Reserve Requirement Study. The Planning Committee voted on Tuesday to endorse PJM’s recommended installed reserve margin (IRM) and forecast pool requirement figures, both of which would increase the reserves PJM aims to procure for the 2027/28 delivery year. (See “First Read of 2023 RRS Values,” PJM MRC/MC Briefs: Sept. 20, 2023.)
Quick Fix for Public Conservation Request Guidelines Proposed
PJM proposed changes to its public notifications seeking reductions in electric consumption during emergency conditions to specify that the request is being made of all consumers, not just residential load, and to aim to better integrate the notification process into other emergency procedures. Additional ways that consumers can conserve energy also are included in the proposed language.
The proposed manual revisions also detail PJM’s reporting requirements to the Department of Energy, NERC and RF or SERC when a conservation request is made.
The revisions will be considered by the OC and MRC during their November meetings.
Periodic Review Revisions to Several Manuals Discussed
Stakeholders endorsed revisions to Manual 3A intended to clarify PJM’s quarterly data collection process for identifying outages that don’t yet have a network model ticket. The language also aims to clarify definitions of monitored priorities.
Revisions to Manual 3 seek to add detail around the documentation of stability limits and would add references to generation interconnection agreements when discussing interconnection service agreements.
The periodic review of Manual 10 led to recommended revisions clarifying that, when reporting outages in eDART, non-capacity resources should report their full nameplate capability unless physically derated.
PJM proposed revisions to Manual 14D requiring that all generation resources prepare for cold weather operations and expanded the guidance it provides for its cold weather checklist. The recommendations for combustion turbine operators encourage proactive action to avoid unexpected icing that could occur due to proximity to sources of warm, moist air such as rivers or cooling tower plumes. The proposal also includes recommendations for ensuring de-icing capabilities are prepared for wind turbines, liquid-cooled inverters have anti-freezing capabilities and designating a “freeze protection operator” to plan preventative measures for critical equipment.
CARMEL, Ind. — MISO last week expounded on why its late August maximum generation emergency wasn’t met with prices dictated by its emergency offer floors.
The RTO shared more of the data it collected on the event during its Oct. 3-5 Markets Week. Over those meetings, stakeholders warned the low prices could discourage market participants from voluntary actions to manage dire circumstances.
MISO dipped into its emergency procedures Aug. 24 to activate emergency pricing. Its early morning analysis showed that footprint-wide capacity would fall about 2.8 GW short of demand by the day’s peak. (See MISO: Could Have Employed Wait-and-see Approach for August Emergency.)
Although MISO enacted its second emergency offer floor at $1,411.74/MWh in this case, it ultimately didn’t use the threshold in locational marginal prices, MISO staff said. Aside from a brief spike to about $1,300/MWh around 5:20 p.m. ET, extended locational marginal prices mostly stayed below $200/MWh.
When MISO applies an emergency offer floor, it doesn’t automatically mean MISO will set locational marginal prices on emergency pricing. MISO’s pricing engine can run optimizations that dodge emergency pricing when emergency resources are readied but ultimately unnecessary to ease system strain.
Some stakeholders said members need more visibility into MISO’s price formation to know in real time when emergency pricing is being used. They said emergency resources are expensive to bring online and were forced to take relatively low locational marginal pricing Aug. 24.
On Aug. 24, MISO said it “consistently” imported power from Manitoba Hydro and PJM with a maximum value of nearly 8.5 GW. It also said market participants voluntarily self-scheduled up to 3 GW of load modifying resources in the afternoon peak hours, even though MISO didn’t order them.
Market participants’ amount of self-scheduled load-modifying resources Aug. 24 | MISO
Travis Stewart, representing the Coalition of Midwest Power Producers, said the nonemergency pricing over Aug. 24 will make market participants think twice about making themselves available in future emergency conditions.
“I think you’re hitting at the heart of the conversation we’re going to be having: what effect these voluntary actions have and what they should be compensated,” MISO’s Tim Aliff said during an Oct. 5 Market Subcommittee meeting.
MISO Independent Market Monitor David Patton said he doesn’t agree with creating an expectation that voluntary load reductions made ahead of an event should receive emergency pricing. He said MISO should put out its best information available, leaving LMRs to “make their own decision on what prices will be.”
“Even when we forecast conditions to be tight, there’s a possibility that prices might not go that high,” Patton said.
Patton said he’d like to see MISO commit turbines with 30-minute startup times closer to when they’re needed, not several hours ahead of time. MISO committed about 25 GW of combustion turbines in its day-ahead market for Aug. 24. In addition, it sent dispatch instructions in real time to another 1.5 GW of small combustion turbines to manage risk.
But Patton did say he respected MISO’s decision to cancel generation commitments when it became clear they were unnecessary.
“We haven’t seen MISO cancelling commitments at this rate ever. It saved customers about $1.6 million” in revenue sufficiency guarantee payments, Patton said.
MidAmerican Energy Co.’s Dennis Kimm said committing gas units “just in time” in the summer makes sense because gas operators are prepared. However, he said that philosophy shouldn’t apply to stressful operations in the winter. He said gas units should be committed ahead of time in the colder months to make sure they can secure fuel supplies.
“We knew this day was not going to be pretty,” MISO’s John Harmon said at an Oct. 3 Reliability Subcommittee. He said a pre-dawn load check registered higher than forecasted and MISO at the time was expecting an additional 3 GW of generation losses and derates over the day.
By midmorning, however, MISO’s in-house meteorologist noticed an isentropic lift weather pattern that had clouds covering major load centers and dampening demand.
A day earlier, MISO’s 125 GW of actual peak demand fell short of its 128-GW forecast.
Harmon said MISO dealt with heat-related system stressors for the majority of August.
“This part of August was the fifth heat wave, heat dome, heat spell of the summer,” Harmon said, adding that MISO operators until then had prepared for and tracked heat for much of the summer.
MISO merges 10 separate weather forecasts to predict conditions. Harmon said MISO wasn’t the only grid operator to encounter load forecasting challenges that day.
“Things changed in a fascinating way that generated a lot of questions,” Harmon said. He said accurately predicting cloud cover over load centers in the footprint like Detroit, Minneapolis and New Orleans remains difficult.
“We did what we could to cancel some of those starts due to the drastic change in our reserve margin,” Harmon said.
Harmon said conditions improved throughout the day and the emergency declaration lured in more imports, so MISO didn’t need to dispatch emergency capacity. Harmon said obligations were met by non-emergency resources in MISO’s pricing engine despite the emergency offer floor.
DTE Energy’s Mike Samson said MISO may be declaring emergencies too early and might want to wait until later in the operating day when it becomes clear actions are necessary.
Harmon said the other side of that argument is, “if you knew it, why didn’t you tell us?” But he said MISO could have more conversations on how best to approach early warnings.
Aliff said MISO has become more proactive over the years as emergency conditions emerge.
“I’ve been at MISO 22 years, and I remember the days at MISO where we made declarations minutes before an event,” he said.
Aliff said all told, MISO followed the procedures outlined in its tariff, which directs MISO to declare an emergency if it foresees a “significant operating reserve shortage” in its real-time reliability assessment commitment.
Harmon said MISO is investigating how wind forecasts, expected imports and voluntary load reductions can evolve going into an event. He said MISO is looking for ways to improve and takes stakeholders’ views seriously after these events.
MISO has taken to commemorating extreme weather emergencies with “flair” pins on lanyards for MISO staff. Harmon predicted the late August event might earn him a new pin in the shape of a thermometer bulb.
Relatedly, MISO continues working on what it deems its “uncertainty management” project to better quantify system unknowns. As part of that, MISO is building a new risk prediction model that will allow MISO to use a dynamic reserve requirement based on a daily risk profile.
