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November 5, 2024

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NYISO Business Issues Committee Briefs: Sept. 14, 2023

Seasonal Demand Curves

RENSSELAER, N.Y. — NYISO on Thursday secured Business Issues Committee approval of the ISO’s proposal to create separate capacity demand curves for summer and winter beginning with the 2025/2026 capability year.

The ISO proposed the tariff revisions to better reflect winter and summer reliability risks and send clearer signals to the market about the value certain resources have in each season. It also said the changes are necessary to accommodate moving from annual capacity accreditation factors to seasonal ones in the future.

The changes are part of the latest demand curve reset, conducted every four years to update the parameters for NYISO’s capacity market. The revisions now go to the Management Committee for approval Sept. 27.

NYISO/PJM Joint Operating Agreement

The BIC also recommended approval of proposed revisions to the Joint Operating Agreement between NYISO and PJM.

The revisions are intended to improve the coordination and data accuracy between the grid operators, particularly in the areas of resource adequacy and transmission planning.

A provision NYISO considers key would remove a list of interconnection tie facilities between the ISO and PJM out of the JOA and publish it on each of their websites, which the ISO argues would make it easier to adjust and increase transparency.

Stu Kaplan, partner at Troutman Pepper, asked if the changes made to the list could in any way change who has operational control over a New York facility.

NYISO did not have an immediate answer but responded that its proposals apply mostly to low-level equipment like substations, though it added that it will consider the issue moving forward.

The MC will consider revisions at its meeting this month. NYISO anticipates implementation by the first quarter of 2024 if the Board of Directors and FERC approve them.

August Market Operations

NYISO Senior Vice President Rana Mukerji presented the August market operations report, noting that average energy prices were lower than both the previous month and August of last year. (See “July Market Performance,” NYISO Business Issues Committee Briefs: Aug. 16, 2023.)

The month’s average energy cost was 56% lower than last year, declining from $93.42/MWh to $40.13/MWh. Mukerji said lower temperatures led to lower loads.

Eclipse Preparation

At a separate meeting of the Installed Capacity and Market Issues working groups the same day, NYISO updated stakeholders about its preparations for two upcoming solar eclipses, including how it is coordinating with solar forecasters and its neighbors to mitigate the impact on New York’s energy production.

The ISO said October’s annular solar eclipse — which will most impact Texas and the Western U.S. — could reduce solar output in parts of the state by 15 to 30%, with statewide behind-the-meter solar generation declining by as much as 700 MW and front-of-the-meter down 30 MW.

Path for total solar eclipse April 8, 2024 | NYISO

Next April’s total solar eclipse will cause even greater disruption, as it will pass directly through New York. During the roughly 2.5-hour eclipse, NYISO forecasts that solar production could decline by more than 3,000 MW at the peak, as some areas of the state will be completely obscured for nearly four minutes.

The ISO also said that wind generation could be impacted by the eclipses, both because of cloud cover and the expected localized cooling that will lower wind speeds when the sun is obscured.

NYISO has said it expects to have enough resources available to cover potential shortfalls. (See “NYISO Updates & Eclipse Prep,” NY State Reliability Council Executive Committee Briefs: Sept. 8, 2023.)

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Northeast Governors Ask Feds to Assist OSW Industry

Governors of the states that have procured all the offshore wind power contracted to date in U.S. waters are asking the federal government to help the struggling industry regain its momentum.

The governors sent a letter to several ranking officials in the Biden Administration saying that offshore wind development is in danger of failing or becoming unreasonably expensive for ratepayers amid a confluence of challenging factors.

They asked for three forms of relief:

    • Updated clean energy tax credit guidance from the Internal Revenue Service — including on the Domestic Content and Energy Community bonus credits to the Investment Tax Credit and Production Tax Credit — that will ensure offshore wind developers are fully eligible for them.
    • A new revenue-sharing program so that money generated by offshore wind leases does not go only to the federal government. Developers will pass those lease payments on to ratepayers, the governors reason, so some of the resulting revenue should come back to the states where those ratepayers live.
    • Expedited clean energy permitting. Slow timelines are hampering efforts to build a clean energy economy and meet decarbonization goals to protect the climate.

The governors of Connecticut, Maryland, Massachusetts, New Jersey, New York and Rhode Island sent their letter to the secretaries of Treasury and Energy, the IRS commissioner, a deputy Energy secretary and two top energy and climate advisers to President Biden.

Offshore wind power development is a signature initiative of Biden, who has set a national target of 30 GW installed by 2030. There are just two projects totaling 42 MW in operation and two projects totaling 932 MW under construction off the New England coast.

Thousands more megawatts are in the pipeline; two major wind farms have gained final federal approval for construction and operation this year and a third may soon follow.

However, these projects all face strong headwinds from inflation, interest rates and supply chain constraints. Two developers have canceled their power purchase agreements and others are threatening to walk away from projects without more money.

Also, developers’ recent bids for state contracts apparently have come in at a very high cost. The world’s leading offshore wind developer, Ørsted, saw its stock price tank after it warned of major cost impairments on its U.S. projects.

“These pressures are affecting not only procurements of new offshore wind but, critically, previously procured projects already in the pipeline,” the governors wrote.

“Absent intervention, these near-term projects are increasingly at risk of failing. Without federal action, offshore wind deployment in the U.S. is at risk of stalling because states’ ratepayers may be unable to absorb these significant new costs alone.”

Clean energy industry advocacy group American Clean Power endorsed the governors’ request.

CEO Jason Grumet said in a prepared statement: “This letter comes at a pivotal time, with the industry seeking to scale up rapidly but meeting headwinds due to inflation, supply chain constraints and permitting delays. The success of offshore wind development in these states will go a long way towards determining whether we achieve the Biden Administration’s 30 GW of offshore wind by 2030 objective.”

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WAPA, Basin Electric Commit to SPP’s RTO West

SPP said last week that recent announcements by the Western Area Power Administration (WAPA) and Basin Electric Power Cooperative have rounded out the group of western utilities that plan to pursue membership in the grid operator’s Western Interconnection RTO market.

The announcements give SPP seven utilities interested in becoming the SPP RTO West’s inaugural full members when it begins operations in 2026. SPP will become the first U.S. grid operator to provide RTO services in both the Eastern and Western Interconnections.

CEO Barbara Sugg said on X, the social network formerly known as Twitter, “I am excited for these commitments to continue growing the RTO in the West and look forward to working together to keep the lights on!”

WAPA Administrator Tracey LeBeau issued a decision letter Sept. 8 authorizing three of its four regions — Colorado River Storage Project (CRSP), Upper Great Plains (UGP) and Rocky Mountain — to pursue final negotiations with SPP for RTO West membership. A federal agency, WAPA had to first file a recommendation report in the Federal Register and solicit public input.

LeBeau said participating in SPP RTO West is consistent with WAPA’s commitment to develop alternative ways to retain and increase the value of its resources and services.

“Taking under careful consideration our customers’ and our industry’s collective movement to adapt to a rapidly changing energy environment, I am pleased at the progress we have made as WAPA takes a further thoughtful step in pursuing final negotiations with SPP,” she said in a statement.

As part of the final negotiations, WAPA will develop implementation details to pseudo-tie CRSP customers from the Western Area Colorado Missouri balancing authority area to the Western Area Lower Colorado BAA. It said this will address CRSP customer concerns about the potential effects of RTO membership for entities outside the footprint.

If the final negotiations with SPP are successful, CRSP and Rocky Mountain will execute membership agreements and UGP will expand its participation in SPP’s eastern RTO.

Basin Electric alerted SPP of its intent to pursue RTO membership on Sept. 12. It must execute a signed commitment agreement by Oct. 10.

WAPA and Basin Electric already are members in SPP’s Eastern Interconnection footprint. Both were part of the Integrated System, which joined SPP in 2015. (See Integrated System to Join SPP Market Oct. 1.)

WAPA annually markets and transmits more than 28,000 GWh of renewable power from 57 hydroelectric power plants in 15 western and central states. Basin Electric is a generation and transmission association with 141 member cooperative systems across nine states serving 3 million consumers.

Other interested RTO West members include:

    • Colorado Springs Utilities;
    • Utah’s Deseret Generation and Transmission Cooperative;
    • Municipal Energy Agency of Nebraska;
    • Platte River Power Authority in Colorado; and
    • Tri-State Generation and Transmission Association.

SPP has been working with the utilities for almost three years to evaluate the benefits and requirements of RTO membership. A Brattle Group study has identified at least $49 million in annual savings for members of SPP RTO West.

The western RTO’s success hinges on SPP’s use of three DC ties between its two footprints to optimize energy markets and create new opportunities for energy transfers and improved system resilience for both current and future members.

“Creating multiple market options for new members will enable market designs that align with the unique needs of one or more geographic regions and provide opportunity for all to benefit,” Bruce Rew, SPP’s senior vice president of operations, said.

The potential members currently are participating in the grid operator’s Western Energy Imbalance Service (WEIS) market. SPP says the WEIS provided an estimated $31.7 million in net benefits for its participants last year and reduced wholesale energy costs by $1.35/MWh through real-time dispatch.

SPP expects RTO West to add additional members, beginning in 2027. They have a March 1 deadline to indicate their interest in membership.

The RTO has 110 member companies in the Eastern Interconnection.

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Oil Companies Resisting Climate Action, Inslee, Climate Panelists Say

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.)

But Democratic leaders have struck back at those critics, accusing oil companies of taking advantage of cap-and-trade to gouge consumers and pad their profits. (See Inslee Challenges Cap-and-trade Role in High Wash. Gas Prices.)

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Proactive Hosting Capacity Planning is Essential for Evolving Grid

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.

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New California Law to Give State Power to Procure Renewable Energy

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 December, the West Coast’s first offshore wind auction brought in $757.1 million for five lease areas off the California coast. (See First West Coast Offshore Wind Auction Fetches $757M.)

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.”

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PJM MRC/MC Preview: Sept. 20, 2023

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.)

Issue Tracking: Peak Market Activity Credit Requirement

Endorsements (1:25-1:35)

1. Nominating Committee Elections (1:25-1:35)

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.

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MISO Promises Analyses on Long-range Tx; Stakeholders Divided on IMM Involvement

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.

MISO IMM David Patton | © RTO Insider LLC

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.

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Hickenlooper and Peters Introduce BIG WIRES Act

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.

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MISO Board of Directors Briefs: Sept. 14, 2023

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.