American Electric Power (NASDAQ:AEP) last week said it is continuing to transform its energy system for the future and de-risking and simplifying itself.
The company told financial analysts during its first-quarter earnings conference call Thursday that it expects to close the sale of its Kentucky operations by July and that it is preparing to market its 1.6-GW portfolio of unregulated contracted renewables during the second half of the year. The latter’s sale proceeds will be directed toward additional investment in AEP’s regulated businesses.
“We already have shifted $1.5 billion in capital to transmission, bringing our planned five-year capital spend to $14.4 billion in transmission and $10.4 billion in distribution,” AEP CEO Nick Akins told analysts.
The Columbus, Ohio-based company announced last October that it planned to sell its Kentucky utility and transmission companies to Liberty Utilities, a subsidiary of Algonquin Power & Utilities (NYSE:AQN), for $2.85 billion. (See AEP to Sell Kentucky Operations to Algonquin.)
AEP said during its earnings call in February that it will sell some or all of its unregulated contracted wind and solar energy resources and redirect capital previously allocated to that business to its transmission assets. (See AEP to Sell Unregulated Renewables Portfolio.)
Akins said the company is making “substantial progress” in transitioning its generating capacity to 50% renewables this decade. It recently commercialized the last of three wind farms making up the almost 1.5-GW North Central Energy Facilities in Oklahoma.
AEP reported earnings of $715 million ($1.41/share), up from 2021’s first-quarter performance of $575 million ($1.16/share). Its share price closed at $99.53 the day before the earnings call. It finished the week down 42 cents at $99.11.
Xcel Earnings up 4.7%
Xcel Energy (NASDAQ:XEL) also announced first-quarter earnings Thursday. The Minneapolis-based company reported income of $380 million ($0.70/share), compared to $362 million ($0.67/share) in the same period in 2021.
CEO Bob Frenzel told analysts Xcel had reached “constructive regulatory outcomes” on several key matters, including its Upper Midwest Resource Plan, the Colorado Power Pathway transmission project and a rate case in Colorado.
The Upper Midwest Resource Plan would add 5.8 GW of wind and solar energy to Xcel’s system, extend the life of its Monticello nuclear plant in Minnesota to 2040, and retire its regional coal fleet by 2030. The $1.7 billion Colorado transmission project would enable 5.5 GW of new renewables, Franzel said.
Xcel’s Comanche Peak 3 coal-fired plant in Colorado is out of service following a “transmission event” and is not expected to be back in service until June because of supply-chain constraints. The outage is expected to cost the company about $25 million.
Clean Attribute Procurement Task Force Established
PJM stakeholders at last week’s Markets and Reliability Committee meeting endorsed an issue charge creating a new senior task force to study a potential market construct for procuring clean resource attributes in the RTO’s markets.
The issue charge, which was developed in the Resource Adequacy Senior Task Force (RASTF) over several months of debate, was endorsed with a sector-weighted vote of 3.513 (70.2%), surpassing the necessary 2.5 threshold.
Dave Anders, director of stakeholder affairs for PJM, reviewed a revised issue charge from the RASTF, saying the first key work activity in the original called for determining whether the “forward procurement of clean resource attributes” should be pursued by stakeholders and examining the inclusion of the social cost of carbon in PJM markets. He said 70% of RASTF members endorsed pursuing a new issue charge calling for a “comprehensive discussion of market enhancements” that would enable states and other buyers to procure clean resource attributes “on a voluntary basis, through a regional and centralized procurement or market.”
Work will start in the new Clean Attribute Procurement Senior Task Force with education on the procurement of clean resource attributes, including defining clean resource attributes across jurisdictions, markets and procurement mechanisms. The second step calls for discussing the objectives of a market construct to enable voluntary procurement of clean resource attributes.
PJM and stakeholders will determine an approach to conduct analysis and select one or more market design solutions for further development. Expected deliverables in the issue charge include proposed market rules to implement the preferred design, if one is found.
“The universe of high-level approaches could vary very widely,” Anders said.
Denise Foster Cronin of the East Kentucky Power Cooperative (EKPC) proposed a friendly amendment to the issue charge, adding language delineating that “for any market design endorsed by the MRC,” stakeholders will conduct a “detailed design and develop market rules for implementation.”
“It’s not intended to be a substantive change to the work that’s going to be undertaken,” Foster Cronin said.
Greg Poulos, executive director of the Consumer Advocates of the PJM States, objected, saying that some of the advocates were “concerned” that the amendment could “add delay or extra layers of steps to the process.”
The amendment was not adopted in the endorsed issue charge.
Chris Pilong, senior director of operations planning, and Alex Scheirer, senior client manager for PJM, also provided an update on the Operating Committee’s recommendation regarding additional reliability products and services related to the issue charge. The OC approved an initial recommendation at its April 14 meeting for the evaluation of adding more reliability-based generation as greater numbers of intermittent resources are integrated into PJM’s grid. (See “Reliability Products and Services Assessment Endorsed,” PJM Operating Committee Briefs: April 14, 2022.)
Deactivation Process Timing Update Endorsed
Members endorsed a PJM proposal to update the process timing for generation deactivations, with one stakeholder voting against it.
David Egan, manager of PJM’s system planning modeling and support department, reviewed the proposal and presented the revisions to Manual 14D and the tariff.
Current tariff language provides 90 days advance notice and 30 days to complete deactivation studies, which Egan said is causing “insufficient and unsustainable” time for PJM staff to determine adverse impacts on reliability if more than one deactivation notice is made in a single study period. New state energy policies are also adding to the number of deactivations, creating more pressure on PJM staff to finish studies.
Example of a generation deactivation timeline in PJM from June-August 2021. | PJM
The proposal calls for establishing quarterly study times for requests, with periods beginning Jan. 1, April 1, July 1 and Oct. 1. PJM staff would study deactivations in batches for more accurate results for the impacts on the system. Egan said the quarterly schedule would allow enough time for additional required seasonal, interim year and short-circuit analyses; scheduling upgrades and cost estimates; and for PJM operations to identify additional needed operational measures.
Paul Sotkiewicz of E-Cubed Policy Associates thanked PJM for working with stakeholders to amend some of the tariff language that creates exemptions so that generation owners aren’t penalized if a unit is forced to deactivate through state legislation or actions by the federal government.
Stakeholders will vote on final endorsement of the proposal at the Members Committee meeting May 17. Conforming Manual 14D language will also go through the OC and System Operations Subcommittee.
Dynamic Line Ratings
PJM provided a first read of the RTO’s proposal and manual revisions supporting the interim integration of dynamic line ratings (DLRs) into its operations.
Stakeholders unanimously approved an issue charge and endorsed a proposed solution as part of the “quick fix” process at last month’s Planning Committee meeting. (See “Dynamic Rating Issue Endorsed,” PJM Operating Committee Briefs: April 14, 2022.)
A PPL helicopter crew installs dynamic line rating sensors on transmission lines. | PPL
Chris Callaghan, PJM senior business solution engineer, reviewed the proposal. PPL is tentatively scheduled to go live in June with a DLR system on some of its transmission lines, Callaghan said, and PJM wanted to “enable the operational implementation of dynamic ratings” through temporary manual revisions, which will be in place pending submission of the RTO’s FERC Order 881 compliance filing, scheduled to be finalized this month.
In December, FERC ordered transmission providers to end the use of static line ratings in evaluating near-term transmission service and required transmission providers to employ ambient-adjusted ratings for short-term transmission requests of 10 days or less for all lines that are impacted by air temperature. (See FERC Orders End to Static Tx Line Ratings.)
Some of the manual revisions include adding timeline requirements to notify PJM about any new DLR systems to be installed on the grid and to provide details on requirements for real-time and forecasted DLR submissions.
“Our goal with the timeline requirement is to provide for both PJM and other stakeholders to be aware of the implementation and be prepared for it as well,” Derin said.
Susan Bruce, counsel to the PJM Industrial Customer Coalition, said she appreciated PJM and PPL “looking at ways to get more out of existing transmission assets.”
Consent Agenda
Stakeholders unanimously endorsed several items, including manual, Operating Agreement and task force charter revisions, as part of the MRC consent agenda. They included:
revisions to Manual 14F: Competitive Planning Process resulting from a periodic review. The changes included updating language so that the Secure File Transfer Tool used to submit all proposals was replaced with a requirement to use “Competitive Planner” to submit proposals.
revisions to the OA intended to appropriately document the underfrequency load shedding (UFLS) relay requirements applicable to EKPC. A recent review of revisions showed “potential confusion” in EKPC’s appropriate UFLS requirement that needed to be corrected.
revisions to the Energy Price Formation Senior Task Force charter. The proposed charter edits relate to the delay in reserve price formation implementation, from May 1 to Oct. 1.
Members Committee
Definition of Workshops
Members are looking to add a definition of “workshops” to the PJM manual to better explain their purpose in the stakeholder process.
At last week’s Members Committee meeting, John Horstmann, director of RTO affairs at AES Ohio, presented the proposed revisions to Manual 34: PJM Stakeholder Process. The language was partially developed at the Stakeholder Process Forum.
The proposed definition states that workshops are “a series of meetings occasionally convened by PJM to discuss emerging topics and objectives as outlined in its initial communication and meeting. Workshops are non-decisional meetings and will not develop rule changes. Rather, they are formed to engage in education, foster dialogue, share ideas and gather stakeholder feedback.”
Calpine’s David “Scarp” Scarpignato thanked PJM and Horstmann for the work on coming up with a clear definition, saying it was “much needed.”
“They’re getting used more and more often, and it adds some clarity around these things,” Scarp said.
Remote Voting Endorsed
Stakeholders unanimously endorsed revisions to Manual 34 to allow for remote voting for the Board of Managers election at the PJM Annual Meeting on May 17.
Previous manual language requires written paper ballots for the elections of board members and the Members Committee vice chair. The revisions to Manual 34 strikes that language.
PJM said it identified the need to “exercise flexibility” to conduct the 2020 and 2021 board elections because of precautions surrounding the COVID-19 pandemic.
The 2020 board election was done remotely through the PJM Voting Application with special auditing provisions, and the 2021 board election was conducted through a secure, third-party online election service, Survey & Ballot Systems.PJM is continuing to use a secure third-party voting system for stakeholders not attending the Annual Meeting in person.
Maine Gov. Janet Mills on Wednesday vetoed a bill designed to limit development of transmission lines that would deliver electricity out of the state.
“The bill (LD 170) would create inappropriate barriers to the development of transmission lines, which could hinder the ability of the state and region to meet our critically important climate and energy goals,” Mills said in a veto letter.
As passed with a committee amendment, the bill sets guidelines for regulatory approval of transmission lines that are deemed “nonessential,” in that they are not needed primarily for in-state electric reliability, in-state retail electric service or meeting Maine’s climate goals.
“LD 170 does not prevent future transmission lines in Maine to serve Massachusetts and others in the region,” Rep. Seth Berry (D), House chair of the joint Energy, Utilities and Technology (EUT) Committee, said in a statement. “On the contrary, it asks that they be developed for mutual benefit and in consultation with communities and landowners who may otherwise be forced to host new infrastructure.”
Designating transmission lines as nonessential based on their functional benefit outside of Maine misrepresents the regional nature of the New England power grid and the global nature of the climate crisis, according to Mills. For Maine and other states in New England to meet their climate goals, “it will be essential to work strategically on a regional level, and this bill would seriously interfere with those efforts,” she said.
Amendments made by the EUT Committee established nonessential line approval requirements that Mills called “vague, ill-considered and unworkable.” The requirements included ensuring the developer demonstrates it has negotiated with stakeholders, attempted to work with impacted communities and negotiated for shared ownership if the developer cannot finance the project through revenue bonds.
The bill also would direct regulators to consult with municipal governments affected by the potential taking of land by eminent domain for a proposed transmission line before approving it.
“I worked hard to address concerns that the public flagged in the [New England Clean Energy Connect (NECEC)] debate so that we have a more transparent and accountable process moving forward and that our clean energy transition proceeds at the necessary pace to meet our climate goals,” the bill’s sponsor, Rep. Nicole Grohoski (D), said in a statement.
Mills has been a steadfast proponent of the NECEC project, which is planned to deliver Canadian hydropower to the New England grid via a 145-mile transmission line that would run through Maine. Voters in the state, however, approved a measure in November to halt construction of the project.
Avangrid subsidiary Central Maine Power, developer of the project, agreed to stop constructing NECEC while the courts consider its claim that the referendum is unconstitutional.
Legislators will return May 9 to consider LD 170 and other vetoed bills. Mills urged the legislature to sustain her veto.
Grohoski said she is “surprised and disappointed” by Mills’ veto and hoped her colleagues will join her in voting to override it.
CAISO on Thursday published its much-anticipated proposal to add a day-ahead market to its real-time Western Energy Imbalance Market as it tries to secure a larger share of a more regionalized Western energy landscape.
The extended day-ahead market (EDAM) plan covers key components, including transmission commitment, resource sufficiency evaluation and market-power mitigation.
“EDAM is a voluntary day-ahead electricity market with the potential to deliver significant economic, environmental, and reliability benefits for participants across the West,” CAISO said in the straw proposal. It “builds upon the proven ability of the Western Energy Imbalance Market (WEIM) to increase regional coordination, support state policy goals, and cost effectively meet demand.”
The WEIM recently surpassed $2 billion in cumulative benefits for participants since it went live in November 2014. It has 17 members and is expected to grow to 22 participants by 2023, its benefits keeping pace with participation, CAISO said. (See Western EIM Tops $2B in Benefits.)
CAISO is hoping that the WEIM’s growth record will attract new and current members to its day-ahead offering and fend off competition from SPP, which also has a real-time market — the Western Energy Imbalance Service (WEIS) — and is planning to start its own day-ahead market in the West as part of its Markets+ program, now under development. (See Western Utilities to Support SPP Market Development.)
A map in CAISO’s Q1 2022 benefits report shows transfer paths in the Western Energy Imbalance Market. | CAISO
The stakes in the CAISO-SPP day-ahead competition could be higher than in the real-time segment because real-time trades account for only about 5-10% of energy transactions in the Western Interconnection while the day-ahead market accounts for 40% or more of all transactions, according to WECC.
CAISO projects EDAM benefits, above those already seen in the WEIM, at $95 million to $400 million annually. The ability to trade greater amounts of renewable output and reduce curtailments as states transition from fossil fuels to clean energy is viewed as a primary benefit of the EDAM.
The day-ahead market will also promote reliability, a prime concern in the West, where resources have been spread thin during summer heat waves as fossil-fuel plants retire and weather-dependent wind and solar resources take their place.
“The EDAM will … enhance reliability across [its] footprint … through a robust resource sufficiency evaluation and an imbalance reserve product that accounts for a level of uncertainty … between the day-ahead and real-time [markets],” CAISO said.
The Western Power Pool’s Western Resource Adequacy Program (WRAP), covering much of the West, is aimed at the same problem — one of a number of current efforts to promote greater regional cooperation in the balkanized Western Interconnection.
Some FERC commissioners have urged the formation of one or more RTOs in the West, while CAISO and SPP have been developing their own regional market programs, including SPP’s planned RTO West. (See Changing Grid, State Policies Favor Western RTO.)
Key Components
After a pandemic hiatus, CAISO fast-tracked EDAM development starting last fall. Three stakeholder working groups met from January through mid-March to offer input on important design elements, and CAISO incorporated the groups’ results into Thursday’s straw proposal.
“First, voluntary participation is a key feature, as it is with the WEIM,” the straw proposal said. “This will allow for voluntary entry and exit, as well as resource participation.” Ensuring fair rates for EDAM participation and confidence in market transfers were additional “threshold features” determined by the stakeholder groups, CAISO said.
Transmission commitment was another must-have, the ISO said.
“An EDAM entity and its transmission customers will need to make transmission available for the market to commit supply optimally within the EDAM [balancing authority areas] and identify transfers between EDAM BAAs,” it said. “The proposal retains the transmission bucket concept previously put forward by WEIM entities, where high-quality firm or conditional firm transmission is made available to support transfers between EDAM BAAs.”
The proposal requires participants to pass a day-ahead resource sufficiency evaluation (RSE) to show they have enough supply to meet internal demand and reserve requirements to avoid “leaning” on the market for additional supply. Failure to pass the RSE could lead to transfer limits or an opportunity for the entity to cure the deficiency through residual supply for a fee.
Other elements of the straw proposal include:
Integrated forward market (IFM) and residual unit commitment (RUC)would be “two primary processes of the day-ahead market,” CAISO said. “The IFM balances supply and demand, which results in optimized supply commitment schedules and identification of market transfers. The RUC process runs after the IFM and will procure incremental or decremental capacity, as a backstop to the IFM, to ensure there is sufficient physical capacity to meet demand in real-time.”
Market power mitigation tools would ensure that, when supply is limited, “suppliers cannot exercise market power to influence prices at arbitrarily high levels,” it said. “As a starting point for consideration, we propose to extend the WEIM market power mitigation methodology for EDAM but seek stakeholder input on the need for potential enhancements to evaluate market power across groupings of BAAs, instead of individual BAAs [in the WEIM], to better account for dynamic constraints affecting the groupings.”
Convergence bidding would allow submission of financial bids in the IFM that do not represent physical supply or demand, CAISO said. “Convergence bidding is a common feature of forward electricity markets and is designed to improve price convergence between the day-ahead and real-time market,” it said.
External resource participation would let resources outside of the EDAM footprint offer supply into the market. “These resources may be pseudo-tied or dynamically scheduled into an EDAM BAA,” CAISO said. “We propose that economic bids and self-schedules continue to be supported in the EDAM.”
Transfer revenue is the “settlement difference between the revenue paid to the import transfers and the cost charged to the export transfers,” CAISO said. “The ISO will distribute the transfer revenue to the EDAM entity that made the transmission available to the day-ahead market. The distribution of the transfer revenue between BAAs depends on the type of transmission used to facilitate the transfer at the transfer point. We are proposing a transmission settlement method to ensure each EDAM BAA is equitably compensated for releasing transmission capacity at each transfer point that is optimized in the day-ahead market.”
For greenhouse gas (GHG) accounting and reporting, the EDAM proposal recommends two potential options: a “resource-specific bidding and attribution approach, an extension of the WEIM framework for GHG accounting, and the zonal approach, which allows resources to be reflected as internal to a GHG regulation area or utilizes a hurdle rate for transfers.”
“We are considering deploying the resource specific approach at the onset of EDAM because it is more developed and better aligned with the WEIM design,” CAISO said.
The 37-page straw proposal goes into greater detail on these elements and more. A stakeholder meeting on the proposal is scheduled for May 25-26, both in-person at CAISO headquarters, in Folsom, Calif., and via a virtual option.
ISO-NE is starting the process of figuring out how to solve future transmission challenges raised by a study looking at the system in 2050.
The preliminary results of the 2050 Transmission Study found that “paradigm shifts” in the region’s grid could lead to overloads on as much as half of the region’s 9,000 miles of transmission lines. (See 2050 Tx Study Finds Thousands of Miles of Overloads in ISO-NE.)
In a presentation to the Planning Advisory Committee on Thursday, ISO-NE officials laid out how they plan to begin addressing those shortfalls. Its primary set of solutions would consist of adding new transmission lines, rebuilding existing lines, and adding or replacing transformers.
The grid operator would also add specific transmission elements to deal with aligned but separate needs found by 2035 and 2040, and a specific winter peak load case that sees the region using 57 GW of energy.
Dan Schwarting, an ISO-NE transmission planner, warned that the study comes with a “certain degree of uncertainty” and that “developing detailed cost estimates for each component could be very costly and time-consuming.”
The study was done at the behest of the New England States Committee on Electricity, and ISO-NE is working with the states to fine-tune its results and proposed solutions, Schwarting said.
Cape Cod Curtailments
ISO-NE’s Al McBride also presented at the PAC a new pilot study analyzing potential curtailments that could be caused by new generation, specifically big additions of offshore wind off Cape Cod and at Brayton Point.
Looking at a scenario with up to 3,200 MW of wind injected into the Cape Cod area and up to 2,000 MW into Brayton Point, the study found that “a number of lines in the area have the potential to be binding and cause curtailment.”
In particular, the 399E line, a 345-kV line from West Barnstable to Bourne, Mass., was found to be the most limiting for injecting new offshore wind on Cape Cod.
But upgrading it would just mean that other constraints upstream would become the limiting factors, the study found.
Planning for Geomagnetic Disturbances
ISO-NE also outlined its plan for meeting a NERC standard on transmission system planning for geomagnetic disturbances (GMDs).
Transmission planning engineer Jinlin Zhang presented the outline of a 2026 needs assessment project regarding NERC standard TPL-007-4.
GMDs, caused by solar flares, can introduce new currents to the grid, driving transformer cores into saturation and leading to a number of adverse effects. A nine-hour blackout in Quebec in 1989 was caused by a GMD that hit power grids across North America and Europe, according to Zhang.
ISO-NE is weighing a number of contingencies to determine how vulnerable the region’s grid is to these events, which Zhang laid out in her presentation.
Maryland’s greenhouse gas emissions in 2020 were 32% below 2006 levels, according to the state Department of the Environment, besting its goal of a 25% cut.
The 2016 Greenhouse Gas Emissions Reduction Act (GGRA) requires the agency to publish updated inventories of statewide greenhouse gas emissions every three years. Mark Stewart, climate change program manager for MDE, disclosed preliminary figures for 2020 at Wednesday’s quarterly meeting of the Maryland Climate Change Commission.
“2020 transportation emissions were significantly lower than likely they would have been without shutdowns related to COVID,” he said. “So, backing out the COVID impacts, the reduction would probably be in the ballpark of a 28% reduction from 2006 levels.”
The agency will share final inventory numbers with the commission this summer, he added. These inventories draw on statewide activity data from agriculture, fossil fuel combustion, industrial processes, natural gas transmission and distribution, transportation, solid waste and wastewater treatment.
The Climate Solutions Now Act (SB 0528), which became law April 8, resets the state’s emissions-reduction goals to 60% below 2006 levels by 2031 and net zero by 2045. That’s half as large as the GGRA goals, which mandated a 40% reduction in emissions from 2006 levels by 2030. (See Md. Climate Change Comm. Chasing New State Law’s Ambitious Goals.)
Addressing the Climate Change Commission Wednesday, state Sen. Paul Pinsky (D) said that much of this year’s spate of climate change legislation was informed by the commission’s work. Pinsky said he and other authors of the legislation included “broad goals and examples of policies we should follow,” but he acknowledged that what’s in the text “won’t get us there.”
“We need bold actions,” he said.
Expanding on this point afterward, Pinsky said in an email, “We’ll need to: move large numbers of people out of their cars; make a huge jump in EVs [electric vehicles]; likely increase existing building emission reductions; hope for advances in improved battery storage, among other things.”
During the meeting, he noted that the question of building electrification, which is the focus of one of the commission’s working groups, “was a center of the discussion in Annapolis.”
Requiring all future buildings to be electrified “was debated hotly and for a very long time,” though it didn’t end up being included in the text, he said. Instead, the new law calls for the Building Codes Administration to study and make recommendations on the building electrification. (See Md. Climate Bills Become Law Without Hogan’s Signature.)
“That issue won’t go away,” Pinsky cautioned.
Commission Has Its Work Cut Out for It
The 60% reduction goal “will not be an easy lift, as Secretary [of the Environment Ben] Grumbles has said,” Pinsky added. “The bill wasn’t as strong as I may have liked, but does put us in the top tier, the top two, three or four states in the country.” Other states will be looking to copy features of the 2022 law, he predicted.
Pinsky and Del. Dana Stein (D) both stressed the need to focus on transportation in future years. Collaboration and partnership will be necessary “to help us meet our aggressive but necessary climate goals in terms of transportation,” R. Earl Lewis, Jr., Maryland’s deputy transportation secretary for policy, planning and enterprise services, said.
The new law requires the commission to establish four new working groups: Just Transition Employment and Retraining; Energy Industry Revitalization; Energy Resilience and Efficiency; and Solar Photovoltaic Systems Recovery, Reuse and Recycling.
Michael Powell, co-chair of the commission’s Mitigation Working Group, said there is a “need for coordination” among the increased number of working groups because “there is a lot of overlap, or at least actions that could come into conflict.” Overlapping group membership could help prevent a situation where working groups might differ on whether certain actions are possible or not, he suggested.
MISO last week warned that even a normal amount of demand and generation outages will likely send it into emergency procedures this summer.
The RTO also didn’t rule out summertime load shedding during combinations of high demand and high generation outages.
At a summer readiness workshop Thursday, MISO said it projects “insufficient firm resources” to handle summer peak forecasts. The grid operator said it will probably rely on a combination of emergency resources and non-firm energy imports from neighbors to maintain system reliability in June, July and August.
MISO Resource Adequacy Coordination Engineer Eric Rodriguez said the RTO’s projections square with the 1.2-GW capacity shortfall across the Midwest that was exposed in last month’s Planning Resource Auction. (See MISO’s 2022/23 Capacity Auction Lays Bare Shortfalls in Midwest.)
The RTO said all summer months will require emergency resources to meet peak load conditions. Using a probable peak load forecast, MISO said it has 116 GW of firm resources to cover a 116-GW peak in June, an insufficient 119 GW to tackle a 124-GW peak in July and another 119 GW that will be no match for August’s 121-GW peak forecast.
Rodriguez said that while June is “pretty tight,” July and August contain significant reliability risks.
“Hopefully, with careful management of emergency resources, we’ll be able to navigate through the summer,” Rodriguez said.
MISO has about 12 GW worth of load-modifying resources (LMRs) and operational reserves that can only be accessed if it first declares an emergency.
The RTO said it could be in even worse shape if it encounters higher-than-normal temperatures coupled with a high level of generation outages. The grid operator said it’s possible it will find itself depleting all emergency resources and still coming up a few gigawatts short over all three months. In a worst-case scenario, MISO could have a little less than 114 GW in firm capacity and a daunting 131-GW demand during the July peak. In that case, it would be about 5 GW short after all firm and emergency resources are factored in.
MISO staff didn’t rule out the possibility of load shedding if it exhausts all its firm resources, emergency reserves and LMRs and emergency energy purchases from neighbors.
In a press release, Executive Director of Market Operations J.T. Smith said MISO Midwest is “at increased risk of temporary, controlled outages to preserve the integrity of the bulk electric system.”
“We exhaust every last megawatt before us before we get to that point,” Smith assured stakeholders at the workshop.
Smith also acknowledged that MISO is heading into summer without its usual 1,000 MW of firm capacity between Midwest and South, which also poses an additional, if small, risk when it and its neighbors experience heavy demand simultaneously. (See MISO Midwest-South Transfer Service on Outage until July.)
This summer, MISO expects above-normal to slightly above-normal temperatures in Midwest and South. The grid operator is also bracing for a lively Atlantic hurricane season and a “potentially active” storm pattern in the Midwest.
MISO Shift Manager Dan Munson said members should now expect maximum generation procedures during any season, even in spring and fall when temperatures spike.
“The thing to remember as we inch toward the summer is it could happen at anytime now,” Munson said. “The risk tolerances are changing.”
Since 2016, MISO has spent more than 40 days under a maximum generation alert, warning or event. Prior to 2016, it had not experienced any grid emergencies.
Over 2021, MISO spent 29 days in conservative operations mode for some or all of its regions; nine days were from hot weather, while 13 were from Hurricane Ida’s late August strike and recovery, limited to MISO South only.
Faced with a capacity supply shortage in the 2022/23 planning year, MISO is considering broadening its generator retirement studies to consider resource adequacy.
During an April 27 Planning Advisory Committee meeting, MISO’s Sydney Yeadon said the grid operator is considering changes to its Attachment Y process — the procedures it uses to study whether retiring generation needs to stay online longer under a System Support Resource agreement.
MISO’s current evaluation process focuses solely on the reliability impacts of the retirement to the transmission system.
“A trend of increased retirements is developing quickly across the footprint,” Yeadon said, adding that while MISO respects states’ jurisdiction over resource adequacy decisions, the retirements are causing the Midwest footprint to feel a supply squeeze.
According to the Institute for Energy Economics and Financial Analysis’ 2022 U.S. Power Outlook, 99.2 GW of coal-fired generation in the U.S. is expected to retire or be converted to natural gas from 2021 through 2030. The nonprofit said it expects more closure announcements on top of that.
“I completely disagree with MISO blaming coal retirements … on EPA regulations and state goals,” Sustainable FERC Project attorney Lauren Azar said.
Azar said even during her time as a Wisconsin Public Service Commissioner more than a dozen years ago, it was “abundantly clear” that coal plants were going to retire at an unprecedented rate while renewables were poised for growth.
“Instead, I would look in the mirror,” Azar said to MISO staff. “We are unable to connect generators in much of MISO because of insufficient transmission capacity. … I’m less than articulate right now; I’m pretty wound up.”
MISO’s Andy Witmeier said MISO wasn’t trying to blame regulations for the poor resource adequacy showings.
Minnesota Public Utilities Commission staff member Hwikwon Ham pointed out that five years ago, MISO ended its regional transmission overlay study with some members convinced that federal regulations weren’t on the horizon. That 2017 study was designed to identify long-term transmission needs under a shifting resource mix; MISO did not recommend any transmission projects from the study.
All the while, Ham said, Wall Street was trending toward decarbonization.
“We really need to pay attention to money,” he said.
America’s Power CEO Michelle Bloodworth said MISO’s retirement studies must consider resource adequacy.
Bloodworth said EPA regulations are “putting pressure on dispatchable resources to retire when they still have economic life left in them.” She asked for MISO to “send signals for those resources to stay as long as they’re needed.”
Stakeholders asked if MISO will simply conduct deeper analysis and share the results with states, which have final say over resource adequacy decisions.
MISO staff said the first discussions will focus on how it can improve its retirement studies, which are becoming more frequent.
MISO plans to hold discussions on improvements in meetings of the Planning Subcommittee through summer; however, stakeholders said the topic might be better left to the Resource Adequacy Subcommittee.
WPPI Energy’s Steve Leovy said assigning the initiative to the Planning Subcommittee was “confusing” given MISO’s many references to resource adequacy. Nevertheless, he said he agreed with the Planning Subcommittee as the starting forum.
PJM stakeholders overwhelmingly endorsed the RTO’s proposal for a new interconnection queue process and a related transition plan after several hours of debate and procedural motions at Wednesday’s Markets and Reliability Committee and Members Committee meetings.
The proposal, which was developed at the Interconnection Process Reform Task Force over the last year, was endorsed with a sector-weighted vote of 4.37 (87%) at the MRC and 4.52 (90%) at the MC. The new interconnection process was nearly unanimously endorsed at the January Planning Committee meeting, while the transition proposal received 91% support at the February PC. (See “New Interconnection Rules Endorsed,” PJM PC/TEAC Briefs: Jan. 11, 2022 and PJM Planning Committee Endorses ‘Fast Lane’ Criteria for Gen Projects.)
PJM said it plans to file the proposal with FERC before the end of May.
In a statement issued after Wednesday’s meetings, PJM CEO Manu Asthana thanked RTO staff and stakeholders for developing the proposal.
“These changes represent a landmark accomplishment for PJM stakeholders and staff that establishes a better process to handle the unprecedented influx of generation interconnection requests and is critical to clearing the backlog of projects,” Asthana said. “We remain committed to our strategy of facilitating decarbonization policies while preserving reliability and cost-effectiveness and will continue to work on issues raised by stakeholders during deliberations that were not part of the package.”
Jack Thomas of PJM’s Knowledge Management Center reviewed the RTO’s proposal, which includes moving away from the concept of “first come, first served” projects in the queue to a “first ready, first served” concept. PJM said the change will ensure projects that are ready to be built are prioritized instead of allowing speculative projects to fill the interconnection queue.
The number of generation projects entering the interconnection queue has nearly tripled over the last four years as more renewable projects are planned in PJM. The RTO started the year with almost 2,500 projects under study in the queue, and about 95% of the more than 220 GW is from renewables, storage or a combination of the two.
The proposal also adds language indicating that if a project doesn’t require a facility study or network upgrades it could move to the final agreement stage early, speeding up the process. The study window for projects is proposed to be 710 days, or just under two years.
PJM’s proposal includes a two-year transition to wade through the backlog of projects in the queue by prioritizing more than 1,200 projects submitted into the queue before 2021. The transition also includes a “fast lane,” which will seek to complete about 450 projects (Queues AE1 through AG1) with upgrade cost allocations up to $5 million within 18 months.
“This has really been a tremendous body of work by our staff and all of our stakeholders to come together to find consensus to some very difficult and complex issues,” said Ken Seiler, vice president of PJM’s planning department. “This is an opportunity today to control our own destiny and really represents a large step forward towards providing our region and the whole industry with more certainty.”
Clean Grid Alliance is asking MISO to develop a means to see late-stage generation projects through the interconnection queue when they’re dogged by uncertain and delayed affected-system study results.
The request comes as MISO and SPP have filed to enact a new relative interconnection queue priority for generation projects that stand to affect the seams for the purposes of system impact studies, affected-system studies and cost assignments for network upgrades.
MISO and SPP’s ongoing Joint Targeted Interconnection Queue transmission planning study compelled them to pivot from a “first-come, first-served” queue priority approach to a “first-ready, first-served” method. The RTOs have a filing before FERC to apply the new prioritization (ER22-1533).
MISO is processing queue applications that were submitted in 2019 and 2020, while SPP is working on interconnection requests submitted in 2017. In some cases, MISO interconnection customers that entered the queue in 2018 are already signing generator interconnection agreements, the final step before grid access.
Andy Witmeier, MISO director of resource utilization, has said it “doesn’t make sense” for MISO interconnection customers to be held up by projects in SPP’s queue that may have entered earlier but have yet to be sited. SPP’s Neil Robertson has also said the RTOs must “evolve” beyond the instinct that whoever lines up first must finish first. (See Midwest Energy Policy Series Addresses JTIQ Projects.)
But in MISO, batches of projects that entered the queue in 2018 and 2019 were left out of the new priority. The RTO said those cycles of projects are destined for generator interconnection agreements (GIAs) before the changes have a chance to take effect.
CGA’s Rhonda Peters said those projects in the late stages of MISO’s interconnection could also use a solution from the RTO to ensure they clear the queue.
Speaking to stakeholders at the Planning Advisory Committee’s meeting Wednesday, Peters said the generation projects are approaching GIAs without “final or accurate” upgrade costs from MISO’s and SPP’s affected-system studies. She said these interconnection customers don’t have a complete enough picture of the affected-system studies or the upgrades they could be on the hook for “to commit significant capital in a GIA or other construction contracts.” She said many are considering filing GIAs unexecuted — “not an ideal solution” for either them or MISO.
CGA’s Natalie McIntire called for a way to help interconnection customers’ advanced-stage projects with uncertain affected-system studies.
“I’m not aware of other industries where you have to sign on the dotted line [while] not understanding what your costs are going to be,” McIntire said.
Both EDF Renewables and Invenergy have protested MISO and SPP’s FERC filing based in part on similar arguments. EDF said it is “often faced with having to execute a GIA 12 to 18 months before obtaining clarity on final affected-system costs.” Invenergy called the affected-system study process “broken.”
Peters said advanced-stage interconnection customers in the 2018 and 2019 cycles have already spent millions that could be passed on to ratepayers even if the projects don’t reach commercial operation. “These projects are the rule-followers and ones that have gone by the book,” she said.
If the projects don’t ultimately connect to the grid, it could impact MISO’s reliability models and resource adequacy. “As the age-old saying goes, an ounce of prevention is worth a pound of cure,” she said.
In February and again in early April, Peters tried to submit a presentation on the topic but was blocked by MISO and the stakeholder leadership of the Interconnection Process Working Group (IPWG). Several stakeholders insisted MISO add the presentation to its website and devote time to stakeholder discussion on the 2018 and 2019 projects.
Future discussions on the topic are likely to take place at IPWG meetings.
