Oil companies are increasingly resisting climate change measures, Washington Gov. Jay Inslee (D) and a panel of climate experts told a group of University of Washington (UW) engineering students Friday.
“They realized they are starting to lose, “said Leah Stokes, professor of environmental politics at University of California, Santa Barbara, one of four virtual panelists in the discussion. She noted that on Thursday the Wall Street Journal published an in-depth story on Exxon privately opposing climate change efforts while publicly supporting those same efforts.
“Some energy companies like to talk the talk, but they are not doing anything,” said Leah Missik, senior policy manager for Climate Solutions, a Seattle-based think tank.
“There are going to be some industries not interested in this transition because it is not in their financial interests,” Stokes said.
“I don’t have patience with people not wanting to build a clean air economy, when you look at the costs of not having a clean air economy,” said Inslee, speaking from the UW classroom.
Lisa Graumlich, dean emeritus at the UW College of the Environment, said a massive Pacific Northwest heat wave in 2021 that killed about 650 people in the U.S. and Canada will become a routine occurrence with climate change.
Washington’s cap-and-trade program went into effect earlier this year. Since then, fossil fuel companies and some economists have linked high prices for carbon allowances to gasoline price increases of 40-50 cents per gallon in the state. Cap-and-trade critics, including Republican legislators, have slammed Inslee and state Democratic leaders for those price hikes. (See Cap-and-trade Driving up Washington Gasoline Prices, Critics Say.)
LAS VEGAS — Utilities and customers both benefit when proactive hosting capacity planning is used to get ahead of the rising demand for distributed energy resources, said panelists at the RE+ conference, held last week at the Venetian Expo and Caesars Forum.
Looking ahead at the potential for distribution circuits to handle high penetrations of DERs not only prevents unfair allocation of upgrade costs but also enables utilities to prioritize upgrades where they are needed most.
Transparency is an essential part of proactive hosting capacity planning, said Erin Ankeney, director of interconnection at residential solar installer Freedom Forever.
“Utilities should be mandated to have their information public about hosting capacities and their availability on the grid. It shouldn’t take a customer and the contractor to get through the whole contract to find out that the system size that was submitted or proposed is not eligible to be installed in that area without a costly upgrade,” she said.
Utilities need to end today’s practice of reviewing one interconnection application at a time and expecting the customer that triggers the need for a distribution grid upgrade to pay the full costs, said Radina Valova, regulatory vice president at the Interstate Renewable Energy Council.
With proactive hosting capacity planning, the utility “would begin by estimating the hosting capacity of distribution circuits in advance of setting any particular project, then analyze the circuit’s ability to accommodate the anticipated DER growth and would determine where any potential infrastructure upgrades have to happen,” Valova said. “The utility would proactively undertake those upgrades and then apply optimal recovery.”
Ankeney said antiquated rules and procedures are “not keeping up with the growth of the DERs and the scale of complexity that we’re seeing in today’s market.” She said challenges ranged from administrative pain points, to engineering screens, to grid transparency.
The result is a slow and frustrating process, Ankeney said. “We’re seeing anywhere from 20 to 30 business days just to get [a residential system] approved to install, whereas on the commercial side, we’re talking hundreds of days or years.” After the project is built, “we have to also go through those same timelines to get jobs interconnected and fully operational with permission to operate,” she said.
Utilities’ application systems are also antiquated, and delays can stem from something as petty as mis-entering a customer’s address, a problem easily eliminated by the kind of simple address validation used on every ecommerce site.
Interconnecting the DER Dots
Some states — but not enough — are already beginning to explore proactive hosting capacity planning, said Samantha Weaver, director of interconnection and grid integration policy at the Coalition for Community Solar Access. While 21 have an active proceeding on distribution system planning requirements, “only a handful of those states are looking at distribution system planning in the proactive hosting capacity planning concept. This is not a widely practiced concept yet.”
Weaver said New Jersey, Maryland and Massachusetts are engaged in the preliminary discussions. “What they all have in common is that they are all seeking to develop a framework for utilities to recover investments in distribution infrastructure in advance of projects seeking to interconnect.
“For example, both Maryland and New Jersey have proposals in the early stages that would require utilities to forecast congested areas on the distribution system and propose system upgrades accordingly. Then you get into questions around how much those upgrades cost and who pays for them. The way that Maryland and New Jersey are looking at this is they’re proposing a $1/kW hosting capacity upgrade fee. Each interconnecting customer who comes along will have to pay to interconnect under this framework.”
Weaver said both states’ proposals fail to solve one key problem related to cost allocation: “Eventually these upgrades reach a point where they become too expensive for a single project or even a group of projects to support. So even if these high costs to upgrade a substation are shared among all future interconnecting customers, they’re still too high, and nobody’s going to build a project there.”
Studies in Maryland have shown realistic hosting capacity fees would be $500 to $1,000/kW, Weaver said. “Those are project-killing costs.”
DERs with Ph.D.s: An Explainer
The grid is an ecosystem, not a science experiment: It’s impossible to hold everything constant while changing only one variable.
This means that utilities cannot assume everything else stays constant on a distribution circuit as one variable — the number of buildings with rooftop solar, for example — changes. The evolving nature of DERs means that there are many changes happening simultaneously: rooftop solar adding to the grid in the day; batteries sopping up the excess and storing it for when it’s needed; and electric vehicles plugging in and not only charging during the night, but possibly feeding into the house during peak demand.
The intersection of big data and small energy has resulted in sophistication well beyond reacting to simple demand response requests. A home battery management system, for example, may layer customer-defined parameters (always having at least 30% charge at the end of an evening) with forecast inputs (tomorrow will be sunny), predicted demands (weekend road trips mean the EV will drink a lot of electrons Saturday night) and scenario planning (hot dry summer means more likelihood of a planned blackout to lower fire risk).
Add to that the increasing sophistication of the many players in a home’s DERs, such as a bidirectional charger that can tap into an EV’s many Powerwalls worth of energy storage, or a hybrid hot water tank that can act as a thermal battery, and capacity planning isn’t simply additive. Modeling capacity today needs to account for the potential of some DERs to help smooth out or even negate the rising demand coming from electrifying homes and transportation.
In a move expected to boost offshore wind development, the California legislature has passed a bill that would give the state authority to buy certain types of clean energy.
Assembly Bill 1373, by Assemblyman Eduardo Garcia (D), was passed late Thursday, the final day of the legislative session. Gov. Gavin Newsom has until Oct. 14 to sign it.
Under AB 1373, the state Department of Water Resources would be authorized to buy clean energy if the California Public Utilities Commission determines additional clean energy resources are needed to meet the state’s renewable energy goals.
Earlier versions of the bill referred specifically to procurement of offshore wind and geothermal resources. The final version of the bill replaced mentions of offshore wind and geothermal energy with “eligible energy resources.”
Those are resources that don’t use fossil fuels or combustion to generate electricity and that have a lead time of at least five years for development and construction. In addition, the CPUC would make sure load-serving entities aren’t planning to buy substantial amounts of the resource.
“Having DWR be able to buy these resources when our utilities haven’t been able to or have chosen not to is the cheapest and most efficient way to get these needed resources online,” Garcia said during a Sept. 6 meeting of the Senate Energy, Utilities and Communications Committee.
The DWR’s procurement authority would expire in 2035. As an urgency statute, the bill would take effect immediately, and a two-thirds vote was required to pass it.
The Senate also amended the bill to include a provision intended to facilitate development of transmission needed to tap the resources being procured.
“This bill would require the PUC, in a proceeding evaluating the issuance of a certificate of public convenience and necessity for a proposed transmission project, to establish a rebuttable presumption with regard to need for the proposed transmission project in favor of an Independent System Operator governing board-approved need evaluation if specified requirements are satisfied,” the provision states.
Unlocking Investment
The American Clean Power Association and other groups supporting AB 1373 said in a letter to lawmakers that the bill would provide market certainty “at a time when offshore wind developers are evaluating whether and how to make the next major investments in project development.”
On Friday, offshore wind industry groups applauded the bill’s passage.
Adam Stern, executive director of Offshore Wind California, called AB 1373 “an important milestone” that will “provide a clear path to market for large-scale clean energies like offshore wind.”
“Passage of this legislation shows California is serious about going big on offshore wind and positioning itself as a leader and global hub of this important clean energy resource,” Stern said in a statement.
The Business Network for Offshore Wind called the bill “key to unlocking new investments.”
“This new procurement authority is essential to unlocking the billions in new investments needed for port redevelopments, vessels, supply chain expansions and manufacturing facilities,” Liz Burdock, the network’s founder and CEO, said in a statement Friday.
Lawmakers who opposed AB 1373 included Sen. Brian Dahle (R), who noted that biomass, hydrogen and carbon capture technologies would be excluded from state procurement.
Dahle was also concerned about the impact to ratepayers of the state’s energy procurement.
“Every single ratepayer in California is going to pay,” Dahle said during the Sept. 6 committee hearing.
Garcia noted that utilities would still be able to buy energy from sources such as biomass.
Clean Energy Goals
AB 1373 is seen as a way to help meet California’s clean energy goals while maintaining grid reliability. The state has set a target for all retail sales of electricity to California customers to come from renewable and zero-carbon resources by the end of 2045.
Last year, the California Energy Commission adopted the nation’s most ambitious long-term offshore wind goals, targeting a buildout of up to 5 GW by 2030 and 25 GW by 2045. (See Calif. Adopts Country’s Most Ambitious OSW Targets.)
In an initial proposal early this year, Gov. Gavin Newsom proposed giving the state authority for procurement of wide-ranging types of energy. The idea sparked concerns from some utilities about competing with the state for buying energy, and the legislature revised the proposal to narrow down the type of energy the state could procure.
On Aug. 31, the governor announced he had reached an agreement with the legislature on the bill.
“This legislation will help us achieve a 100% clean electric grid and phase out the very pollution that causes extreme weather in the first place,” Newsom said in a statement. “We’re taking action to build the clean energy we need, faster.”
Below is a summary of the agenda items scheduled to be brought to a vote at the PJM Markets and Reliability Committee and Members Committee meetings Wednesday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be covering the discussions and votes.
Markets and Reliability Committee
Consent Agenda (9:05-9:10)
B. Endorse proposed revisions to Manual 01: Control Center and Data Exchange Requirements that would specify that entities may have multi-layered communication methods and are required to notify PJM of a failure only if all modes have failed and only alternates remain. The revisions arose from the manual’s periodic review. (See “Stakeholders Endorse Manual Revisions Related to Communication Failures,” PJM OC Briefs: Sept. 7, 2023.)
C. Endorse proposed revisions to Manual 12: Balancing Operations that aim to clarify that reserve resources should respond to a synchronized reserve deployment when they receive notification through any of the existing Energy Management System datalinks. (See “Stakeholders Endorse Quick Fix on Synchronized Reserve Dispatch,” PJM OC Briefs: Sept. 7, 2023.)
D. Endorse proposed revisions to Manual 28: Operating Agreement Accounting adding clarifying language, grammatical updates and removing terminated business rules.
Endorsements (9:10-10:30)
1. Enhancements to Deactivation Rules Issue Charge (9:10-9:45)
PJM’s Chris Pilong will review a problem statement and proposed issue charge that address possible enhancements that can be made to deactivation rules. The problem statement lays out concerns PJM has identified with how compensation is determined under reliability-must-run contracts and the timeline for when generation owners must notify PJM of their intent to retire a unit. (See “Stakeholders Defer Vote on Generation Deactivation Issue Charge,” PJM MRC Briefs: Aug. 24, 2023.)
The committee will be asked to endorse the proposed issue charge.
2. Reserve Certainty Issue Charge (9:45-10:30)
PJM’s Donnie Bielak will review a problem statement and proposed issue charge that would create a new senior task force to explore reworking several areas of the reserve markets, including performance and penalties, aligning offers with resource capability and fuel procurement and reserve procurement targets. (See “PJM Provides First Read on Reserve Certainty Issue Charge,” PJM MRC Briefs: Aug. 24, 2023.)
Independent Market Monitor Joseph Bowring and Deputy Monitor Catherine Tyler will review an alternative version of the issue charge, in which the Monitor has removed several key work areas and added specificity to others.
The committee will be asked to endorse one of the proposed issue charges.
Members Committee
Consent Agenda (1:20-1:25)
C. Endorse a proposal, with corresponding tariff revisions, addressing the amount of credit market participants must maintain to satisfy their peak market activity requirement. (See “Peak Market Activity Credit Changes Endorsed,” PJM MRC Briefs: Aug. 24, 2023.)
PJM’s Dave Anders will review the sector nominees under consideration for election to the 2023-24 Nominating Committee. The committee will be asked to elect the sector representatives upon first read.
MINNEAPOLIS — Amid the Independent Market Monitor’s denunciation of MISO’s fleet assumptions for long-term transmission plans, MISO lead planners last week defended their approach to planning for 2040.
Stakeholders, meanwhile, continued to debate whether it’s proper for IMM David Patton to deviate from markets to weigh in on MISO transmission planning.
MISO Vice President of System Planning Aubrey Johnson said MISO is seeking an “optimal, cost-effective expansion” in its second, multibillion-dollar long-range transmission plan (LRTP) portfolio that can hold up under several hypothetical circumstances.
That comes two weeks after Patton repeated criticisms of MISO’s future fleet assumptions behind its second LRTP portfolio. The IMM has alleged MISO is overestimating renewable additions and baseload generation retirements while underestimating future battery storage. He has said a transmission overbuild stands to harm market functions. (See Market Monitor Questions MISO Fleet Assumptions in Long-term Tx Planning.)
“We are not the resource planners,” Johnson told board members at a Sept. 12 System Planning Committee of the MISO Board of Directors meeting. “But what we do is take these plans and goals from our members and make a path that shows how they can be accomplished.”
Johnson said MISO “has not seen any indication” that members’ plans have changed. It remains that 70% of MISO load is associated with members’ decarbonization commitments, he said.
MISO hasn’t yet recommended any transmission projects under the second LRTP portfolio. That’s set to happen next year.
“This whole process has tension in it,” Johnson said, referring to “standing-room-only” stakeholder workshops full of members with differing views on generation and transmission expansion. He promised that MISO will run several analyses and stress tests against multiple planning scenarios and the IMM’s idea of the resource mix before recommending lines.
“We recognize that the portfolio we recommend, the state commissioners today might not be the commissioners that approve those projects,” Johnson said.
Some stakeholders said the IMM’s opinions on MISO’s future fleet deserves research.
Alliant Energy’s Mitch Myhre asked MISO to take the time to perform a sensitivity analysis that includes the IMM’s view of the future and “arrive at a set of projects that have good business cases.”
North Dakota Commissioner Julie Fedorchak said the expected second LRTP portfolio price tag at $20 billion to $30 billion warrants careful examination. She also said North Dakota supports MISO taking a deeper look at its battery storage projections.
“We are talking about extreme amounts of money, and that’s not even taking into account the generation, that will be borne entirely by ratepayers,” she said.
WEC Energy Group’s Chris Plante said while the first $10 billion LRTP portfolio was “low-hanging fruit” of known choke points on the system, the second LRTP portfolio is a more drastic investment.
But some MISO members took to the Sept. 12 Markets Committee of the Board of Directors to condemn Patton’s disapproval of MISO’s planning assumptions.
ITC’s Brian Drumm said the IMM has “repeatedly invoked the authority of his office in an attempt to force MISO and its stakeholders to implement one person’s vision for MISO’s energy future.”
“The IMM’s attempt to influence LRTP tranche two regional transmission planning is neither necessary, impartial, effective, market monitoring [nor] within the scope of the plan,” Drumm said.
Drumm said Patton’s “out-of-scope intervention” in LRTP planning is “disruptive.” He asked that MISO’s board intervene and prevent the IMM from attempting to undermine MISO’s fleet assumptions that “economically incorporate the letter and the spirit of the decarbonization and renewable energy goals of MISO’s members and states.”
Other stakeholders characterized the IMM’s recent involvement in the fleet assumptions underpinning the LRTP as an 11th-hour attempt at circumventing MISO’s second portfolio of long-term transmission planning.
Clean Grid Alliance’s Beth Soholt said she believed MISO and members are adequately capturing the most likely range of future fleet mix possibilities.
“We need a grid that can support all this uncertainty and all of these changes,” she said.
Soholt added that Patton’s inappropriate foray into transmission planning comes as MISO is reupping the IMM’s annual contract. She advised MISO not to expand monitoring duties to include planning.
Patton did not respond to RTO Insider’s request for comment on the divide. He did not respond in real time during the Markets Committee.
Sen. John Hickenlooper (D-Colo.) and Rep. Scott Peters (D-Calif.) on Friday introduced the Building Integrated Grids With Inter-Regional Energy Supply (BIG WIRES) Act, which would require minimum levels of interregional transfer capability between regions.
The two have been working on the bill for months. It was discussed during the debt ceiling negotiations earlier this year, but ultimately not included in the package that passed. (See Debt Ceiling Bill Provides ‘Mini-deal’ on Permitting.)
“If we want to maintain our national security amidst growing international conflict, make our power system more reliable and cut high energy costs for Americans, we can’t have a faulty, outdated electric grid,” Hickenlooper said in a statement. “Our bill advances two priorities simultaneously: Make electricity more affordable and build a power grid fit for the 21st century.”
The bill would direct FERC to better coordinate construction of an interregional transmission system by requiring each of its transmission planning regions (that date from Order 1000 and include jurisdictional ISO/RTOs) to be able to transfer 30% of their peak electric loads to their neighbors.
The lawmakers compared the current development of the transmission grid to building new highways that crisscross the country every time two towns need to be connected. They say their bill would close current gaps in the transmission network by doing the equivalent of “building new exit ramps off the existing interstate.”
“During a heatwave, hurricane or other natural disaster, the last thing you want is for the power to go out. It can be the difference between life and death,” said Peters. “There is no reason neighboring electrical grids should not have the capacity to share power during these situations to avoid blackouts. The associated buildout of electric transmission lines would greatly improve reliability and keep costs down for consumers. BIG WIRES will help get clean, reliable energy from where it is produced to where it is used by people, but above all else, it is an American energy security and independence bill.”
On top of the reliability benefits, the legislation also would reduce energy costs by allowing regions where power prices are cheaper to sell into regions where it’s more expensive and by allowing all regions to connect new, low-cost resources to the grid.
The bill aims to be technology neutral, allowing all types of generation to connect to the grid and relieve grid congestion where needed. The lawmakers said it would prioritize regional flexibility by allowing the FERC planning regions to decide how they will upgrade their systems.
The bill has a section devoted to ERCOT, which never has had much interconnection with the Western and Eastern Interconnections, giving the Texas PUC authority over its wholesale markets and transmission planning. The PUC “may, at its sole discretion” choose to support the reliability and affordability of the Texas grid by voluntarily complying with a minimum transfer capability equal to a percentage, determined by ERCOT, of its coincident peak load, the bill said.
The two offices released a suite of supportive quotes from clean energy groups, transmission supporters, environmentalists and some former regulators who were on the FERC-State Joint Task Force on transmission, where the idea of interregional transfer capacity was widely supported. (See States Back FERC Interregional Transfer Requirement.)
Former FERC Chairman Rich Glick noted that recent years have seen extreme weather test the grid and the bill would help deal with those situations by increasing interregional transfer capability.
“Utility customers are at greater risk of losing access to power during extreme weather events, and they are often forced to pay much more for electricity than they otherwise would with a more efficient electric grid,” Glick said in a statement. “Senator Hickenlooper and Congressman Peters deserve credit for elevating this important subject with the introduction of the BIG WIRES Act.”
The legislation also won praise from Glick’s former colleague from across the aisle, former FERC Chairman Neil Chatterjee.
“By requiring that FERC establish a minimum interregional transfer capability standard, this important legislation will dramatically improve our country’s ability to move power between regions where and when it’s needed most, enhancing grid reliability for all Americans,” he said in a statement.
Former Maryland PSC Chair and FERC-State task force co-chair Jason Stanek also gave the proposal a supportive quote.
“Increasing interregional transmission capacity will be critical to maintaining reasonable utility rates and sustaining a reliable bulk power system,” Stanek said. “This bill builds upon recent discussions by the Joint Federal-State Task Force which highlighted the important role that interregional transmission will play as we strengthen our nation’s power grid.”
Other backers of the legislation include Americans for a Clean Energy Grid, American Clean Power Association, American Council on Renewable Energy, Advanced Energy United, Business Council for Sustainable Energy, Clean Energy Buyers Association, the Electricity Consumers Resource Council, Environmental Defense Fund, Natural Resources Defense Council, Rocky Mountain Institute, the R Street Institute and the Solar Energy Industries Association.
The bill could become part of a broader effort on permitting, which has a chance of passing this year. On Thursday, Senate Energy & Natural Resources Committee Chair Joe Manchin (D-W.Va.) and Ranking Member John Barrasso (R-Wyo.) released a joint statement saying they agreed on the need to change permitting laws and regulations generally.
“We are in agreement that we must act to accelerate our permitting system and are committed to reaching a bipartisan solution that prioritizes American energy security, reliability and affordability,” the two said.
Members to Vote on Whether to Place Former Ford Exec on Board
MINNEAPOLIS — MISO’s Board of Directors next year likely will include a former Ford executive, directors announced last week.
MISO’s Nominating Committee interviewed eight candidates and two incumbents to fill three open slots on the board beginning in January. Current members Jody Davids, Theresa Wise and Robert Lurie are rounding out three-year terms and were up for re-election.
Davids ultimately decided not to seek a second term on the board. She joined the board at the beginning of 2021.
The opening likely will be filled by Jeff Lemmer, the former vice president and CIO at Ford Motor Co.
Jeff Lemmer | Jeff Lemmer via LinkedIn
The Nominating Committee — comprising two MISO members and three MISO directors — worked with search firm Russell Reynolds to select candidates for interview.
MISO Director Phyllis Currie said while at Ford, Lemmer supervised the inclusion of EVs in production.
Otherwise, current directors Wise and Lurie will stand for election.
MISO members now have about a month to vote electronically on the new appointment and incumbents; candidates must earn a majority of member votes to be confirmed.
MISO and its board still must decide which directors it might retain for an extra term through a waiver that allows them to stand an additional three-year term beyond the three-term limit.
The board has said it has multiple directors who will hit their three-term limit beginning next year and it may use waivers to preserve institutional knowledge. (See “Waivers May be Necessary to Retain Directors Past Term Limits,” MISO Board of Directors Briefs: March 23, 2023.)
MISO’s board consists of nine independent directors and the RTO’s CEO. The independent directors are limited to three three-year terms, but its bylaws allow some board members to serve an additional term under certain circumstances.
Directors Currie and Mark Johnson were re-elected to their final terms that began in 2022. They will hit their three-term limit at the end of 2024. Todd Raba, H.B. “Trip” Doggett and Barbara Krumsiek also were re-elected late last year. Their final terms conclude at the end of 2025.
Finally, the board selected Raba, the current board chair, to continue leading the board in 2024. Raba said the MISO board will remain his only professional commitment.
“Basically, I’m all in,” he said.
MISO Pursues $400M Budget for 2024
MISO says it likely will spend nearly $400 million over 2024, continuing a trend of budget increases year-over-year.
MISO is proposing a $370 million 2024 operating budget, which contains a nearly 15% increase in base operating spending over 2023. It also is eyeing approximately $27.3 million in capital spending.
MISO likely will up its $0.44/MWh tariff rate for members to $0.47/MWh next year.
MISO CFO Melissa Brown said increases to the member rate remain below nationwide inflation trends.
Brown said MISO’s total increase for 2024 is 9.1%, higher than the estimated tariff rate increase of 7%. The extra percentage over the tariff rate is from revenues MISO receives from the studies it performs for its generator interconnection queue and fees it collects to evaluate competitive transmission project applicants.
MISO said much of the jump in base operating expenses boils down to hiring and retaining employees.
The RTO said it soon will add nine new employees specializing in system planning and five new staff members to concentrate on MISO’s ongoing market redefinition, or how MISO will adapt its market design for more complex operations.
MINNEAPOLIS — MISO officials last week said they probably could have held off their decision to call a summertime emergency in late August.
MISO declared its lone summertime emergency and instated maximum generation procedures Aug. 24. (See MISO Calls 1st Summertime Emergency amid Systemwide Heat Wave.) However, the 123-GW peak under the widespread heat dome wasn’t the 127-GW peak MISO anticipated that morning. It also didn’t amount to the grim possibility MISO warned about ahead of summer, where it could exhaust all of its emergency reserves.
MISO’s summer peak demand of 125 GW interestingly arrived Aug. 23, a day before MISO called the maximum generation event. Intense heat struck multiple major cities in MISO simultaneously Aug. 23-24.
During a Sept. 12 Markets Committee of the Board of Directors meeting, Executive Director of System Operations Jessica Lucas said on Aug. 24, MISO worked to de-commit previously signed-on resource as load outlooks improved during the day. Lucas said in hindsight, MISO could have waited longer to make resource commitments to make sure they were necessary.
MISO CEO John Bear said it’s important to judge control room operators on what they saw in the moment and not by perfect hindsight. Multiple MISO executives said load forecasting and unit commitment during extremes is difficult, especially when fuel supply issues, low wind and other environmental limits related to heat hinder resource performance.
“We walked into that day knowing we had a high load forecast,” Executive Director of Market Operations J.T. Smith said.
Smith said a more sophisticated forecast might better anticipate coming “cloud cover in Detroit” so operators aren’t forced to commit as many resources on the mornings of pervasive heat waves.
Lucas said it was the hottest summer — and resulted in the highest demand — in MISO South since its integration in 2013. Southern demand hit a new high of 35 GW on Aug. 23.
Heat map of departures from 30-year normal temperatures Aug. 23-24 | Midwestern Regional Climate Center
“This summer was marked by five major heat waves,” Lucas said.
Despite that, Lucas said MISO used its emergency procedures only once. She said average temperatures in MISO Midwest shook out about normal, while MISO South was above normal.
Independent Market Monitor David Patton said MISO’s forecast model overestimated load between 2-8 GW on the hottest days in July and August. He said the model may not be picking up voluntary actions of MISO market participants to reduce load and behind-the-meter solar generation that likely spikes as demand soars on hot days.
Patton warned MISO about creating “artificial surpluses” during hot days that mute real-time prices. He reminded MISO leadership that MISO has short-term reserves and often experiences a “wave of imports” from neighboring regions when its prices rise. He urged them to let MISO’s market dynamics do more of the lifting in a heat dome.
However, Patton lauded MISO operators for having the foresight to cancel resource commitments Aug. 24 when it became clear they would be unnecessary. He said the move saved MISO customers about $1.6 million, though some MISO suppliers were unhappy because they purchased gas in anticipation after being selected to generate.
“It’s much better that you do that instead of ride it out and have more resources than you need,” Patton said.
Patton urged MISO to hold out longer on resource commitment decisions and declaring emergencies. He said MISO shouldn’t allow its market “to work against us” in tight operating conditions. Committing so many resources that prices stay low at about $45/MWh might lead some resources to export their output, Patton said.
MISO Director Barbara Krumsiek asked if MISO would have enough transmission capability if “decisions were made differently” and MISO were more confident in imports. Patton assured her MISO is flush with import capability.
Patton also acknowledged that for control room operators, overseeing the situation in real time is much tougher than delivering after-the-fact analysis.
“I can sit here and say, ‘have faith in the markets,’ but when you’re an engineer sitting in the control room, that’s a hard thing to accept,” Patton said.
“Thank you! Thank you for saying that; I don’t think I’ve ever heard you say that,” MISO Director Phyllis Currie said, eliciting laughs from the audience.
MISO again prepared for near-record electricity demand and tight conditions this month as a lingering September heat wave settled on its Midwest region. It enacted a hot weather alert for its North and Central regions Sept. 3-5 when temperatures again exceeded 95 F in some parts of MISO Midwest. The grid operator handled those days without emergency procedures.
Executive Director of Market and Grid Strategy Zak Joundi said until recent years, MISO and members have been “fortunate” to preside over smooth operations and manage them with simpler market tools. However, he said a multitude of renewable resources and increasingly unstable weather is poised to further drive volatility and riskier operations.
“The world that we are operating is a lot more complex, so to maintain the reliability we’ve become accustomed to, we will need to adjust our markets and processes,” Joundi told board members.
Joundi said the weather years MISO has experienced recently are more indicative of what’s to come and should be assigned more weight in loss of load prediction modeling than other historic years.
Smith said MISO has a goal to set dynamic reserves, so the markets determine a greater share of the operations, rather than control room operators.
Smith said MISO is headed into a future where operators can’t feasibly consider all the “various inputs” to mitigate risk. He also said MISO is conducting “toes in the water” testing of machine learning in its markets to forecast risk.
VANCOUVER, British Columbia — Stakeholders got to enjoy sweeping views of Vancouver’s downtown and harbor from a top-floor conference room during WECC’s two-day annual member meeting, which on Thursday featured an election to fill the board’s two top spots. Following is some of what we heard.
WECC directors elected current board Vice Chair Ric Campbell to serve as the new chair. Campbell replaces Ian McKay, who finished his three-year term in the top role.
Campbell previously served as chair of the Utah Public Service Commission and director of the Utah Division of Public Utilities. He worked for Shell before joining state government.
Speaking of Campbell, McKay said, “I consider that we’ve been a great team together, and he’s taught me a lot as we’ve gone through the last few years. I’ve valued his guidance and sage advice.”
Campbell returned the compliments, saying McKay “served as chair during a very unprecedented time, because we had to deal with a pandemic and how we were going to operate as a board. He did a fantastic job with that. He’s a man of great integrity.”
The board also elected Director Jim Avery as vice chair. Avery previously worked for San Diego Gas & Electric, most recently as chief development officer.
Talent Competition
Branden Sudduth, WECC vice president of reliability planning and performance analysis, told the board that, while his staff was on track to complete certain transmission studies due later this year, staff turnover represented a “strain” on meeting deadlines.
“We do have new people in place to take over some of the studies that were left behind by my other employees, but that’s my only concern at this point,” Sudduth said.
CEO Melanie Frye added that WECC is struggling to retain staff because of the industry’s attention on transmission, in part because of recent funding from the federal government.
“There is a huge competition for talent in that space. I think it’s now a hot skill,” she said, noting that it added to the broader challenges in finding the right workforce over the next 15 years.
“In that area in particular we’re in an intense competition to attract and retain talent,” Frye said.
But Frye also noted WECC “is fortunate to have some very tenured employees” on staff. With employees now spread across almost 20 different states, WECC is trying to navigate the “new realities and expectations” among workers in the post-pandemic world, she said.
The RE recently brought all its staff together at its Salt Lake City headquarters for “WECC Week.”
“It was a combination of self-awareness training, relationship-building, employee recognition and discussion around the vision and mission of the organization so that we’re all aligned going forward,” Frye said.
More Robust Oversight
Staffing isn’t a problem for WECC’s Oversight department, according to Steve Noess, vice president of reliability and security oversight. Noess, who joined WECC from NERC in April 2022, said his staff has doubled over the past year.
In August, Noess said, Oversight “retooled” how it presents registered entity compliance metrics by providing a quarterly report to the board instead of just making a presentation. The new report is more “robust” with the inclusion of more metrics and will be posted to WECC’s website to make the information available to a wider set of stakeholders.
“We think this also serves this drive to be more transparent because it’s hopefully easier to find and to access and reach a broader audience,” he said.
Noess said his team has grown to include “good analysts and engineers and lawyers” to help develop “a more case management approach” to WECC enforcement responsibilities. The team recently reached an “inversion point,” where it is processing more enforcement cases than it is receiving per month, chipping away at a large backlog.
“We targeted 30% reduction in cases that are two years old and older [in] the last several years,” Noess said. “We’ve come close, but we’ve not quite been able to meet that metric, and I’m happy to say that I’m confident that this year, we’re on track to meet that. Our target was 20% by the end of the third quarter … and 30% by the end of this next quarter.”
Noess also noted that NERC last week proposed new rules that would require owners of smaller grid-connected inverter-based resources (IBRs) to register with the agency, follow its reliability standards and respond to its alerts. (See NERC Seeks Comment on IBR Registration Proposals.)
“We’ve taken a lot of a lot of actions to try to prepare for that already, and we anticipate that should easily add more than 100 new registrations over time,” he said.
WECC Oversight has reorganized its staff to create three different monitoring teams focusing on high-, medium- and low-risk entities, Noess said. Staff already have begun developing plans for the expected rule changes, creating outreach materials targeted at new registrants.
WECC won’t have the capacity to audit all the small entities, “but we definitely, from a holistic perspective, have an obligation to make sure that we are well aware of their capability to address risks,” Noess said.
He said WECC has encountered “two flavors” of questions and concerns from the new IBR registrants.
“One is entities that haven’t had any experience with WECC or reliability whatsoever. So that’s the new population of folks who probably haven’t thought of WECC at all … So we have a very specific kind of targeted way that we want to approach those to set them up for success,” Noess said.
The second flavor consists of existing registered entities that have other assets that will be newly swept into NERC’s administration.
“So, there’s a familiarity with requirements and standards and obligations, but they have additional assets that they’ll then have to register for this new registration. And I think they’re understandably asking about what timelines will look like,” Noess said. “And so, this is a case where we should stay close to that, because there’s a process in place once the registration changes to do the modifications to meet the standards.”
Policy Risk
“There is a push for more market development in the West, perhaps leading to an RTO, and that occupies a lot of the time in our [Committee on Regional Electric Power Cooperation-Western Interconnection Regional Advisory Body] meetings, so I like to make sure that we don’t lose sight of the reliability discussion and certainly appreciate WECC’s partnership on that,” Mary Throne, chair of both the Wyoming Public Service Commission and WIRAB, told the board.
Throne said one the most interesting parts of NERC’s 2023 ERO Reliability Risk Priorities Report, released last month, was the addition of public policy to the list of grid risks. (See ERO Adds Energy Policy to Risk Priorities List.) She cited EPA’s recent proposed new rules for reducing greenhouse gas emissions from power plants as an example of the need for better coordination among regulatory agencies.
“In the preamble to the EPA regs, EPA commented that it had coordinated with FERC, but there really wasn’t anything in the preamble to support that statement,” Throne said.
After acknowledging Wyoming’s role as the nation’s leading producer of coal and an exporter of electricity, Throne said the state “did not feel like the EPA really considered the reliability risk” of its proposed regulations. “I think I might even use the word ‘naïve,’” she said.
Director Richard Woodward asked Throne how WIRAB and WECC can address the issue of energy policy risk.
“I think a communication strategy that puts all of this in terms that people can understand, identifying the risks without creating hysteria,” Throne said. “I don’t want to see the reliability discussion being politicized too much, but just a pragmatic discussion with reason, facts. And I think it’s important that WECC remains … a neutral source of technical information, so that policy people have good advice.”
Transmission investments that could help “address reliability, congestion and cybersecurity concerns” in the nation’s electric grid are being held back by “regulatory tension” between the federal and state governments, according to a recently released report from Moody’s Investors Service.
The report, published on Monday, asserts that not only is massive transmission investment needed to keep pace with the growth of new wind and solar generation sources and aging infrastructure, but “opportunities abound” for developing transmission assets. However, in spite of support from decarbonization initiatives at various levels of government, the siting and permitting process represents a significant bottleneck for utilities with the experience and resources to carry out these projects.
North America’s grid is long overdue for an upgrade, Moody’s argues in the report, citing data from NERC showing an annual average of about 9,500 “momentary or sustained transmission outage events” between 2015 and 2021, a figure “more than double the annual average of the preceding five years.” The report attributed most of these outages to severe weather events, which have become “more frequent and severe” in recent years.
Transmission improvements could be extremely useful to help the grid absorb the impact of such events, Moody’s said, citing a report from consulting firm Grid Strategies studying the winter storm of February 2021. More interregional transmission capacity could have saved nearly $1 billion in impact — and kept the lights on for 200,000 homes — for each gigawatt added, the report said.
Transmission improvements also could help with high congestion costs, which Moody’s said “have emerged as a major problem” in recent years; the firm cited data from the U.S. Energy Department’s draft National Transmission Needs Study indicating congestion costs in the Mid-Atlantic region surged from $529 million in 2020 to $953 million the following year. Additional investment is needed to bring the transmission system in line with mandatory cybersecurity requirements adopted in response to mounting threats from malicious online actors around the world.
FERC has sought to encourage transmission investments, the report said, noting “limited revenue risk [and] counterparty risk” on the part of transmission owners thanks to the commission’s cost recovery framework and transparent process for setting return on equity for transmission assets. The report considered revenue collected under FERC’s regulatory framework to be overall “more stable and predictable than” under state regulations and called the commission’s approach “favorable to transmission owners.”
While FERC has tried to cultivate a positive environment for TOs — particularly large utilities such as Duke Energy and Exelon, which Moody’s called “best positioned to take advantage of” these opportunities — challenges remain in the approval process. The report noted that authority over transmission siting and permitting largely remains in the hands of state and local governments, which “can be slow and impede the pace of transmission development.”
This regulatory dilemma is illustrated by the slowing pace of transmission capacity upgrades, Moody’s said, pointing to data from FERC that shows an average of around 600 miles of high-voltage transmission lines completed annually in the U.S. since 2017, far below the 2,000 average annual miles completed between 2012 and 2016. The slow pace of construction, in spite of steadily rising transmission investments since 2017, has resulted in long lead times for such projects, with Moody’s estimating up to 10 years is needed from preliminary planning to end of construction.
Moody’s said efforts are underway in the federal government to help with the permitting issue, citing Sen. Joe Manchin’s (D-W.Va.) Building American Energy Security Act as an example of the kind of work that could help get transmission projects moving. Among other reforms, the bill would set maximum timelines for permitting reviews and set a statute of limitations for court challenges to projects.
“Measures like these at the federal level, as well as improved coordinated planning at the state and regional level, could facilitate the nation’s transmission development and help meet long-term greenhouse gas emission goals,” Moody’s said.
