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November 8, 2024

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Stakeholder Soapbox: Midwest Lessons on the Value of Transmission Independence and Competition

By Devin Hartman

Devin Hartman (R Street Institute) Content.jpgDevin Hartman, R Street Institute | R Street Institute

The Midwest has become ground zero for the future of transmission policy. Reliance on incumbent transmission owners to dictate state policy and regional transmission practices in MISO has led to higher costs, stifled innovation and a backlash to grid expansion. By extension, the reliability and environmental benefits of grid expansion hang in the balance. Implications for state legislatures, utility commissions and FERC are clear: inject more independence into transmission practices and enable competition to flourish.

The Midwest’s economy has succeeded when good governance and fair competition prevail. Transmission is no different. Upon the national introduction of transmission competition, competitive projects averaged 40% below initial cost estimates, whereas non-competitive projects averaged 34% above initial estimates.[1] An independent assessment found a 22 to 42% cost savings from competition in MISO specifically.[2] The problem is that competition and advanced technologies are hardly used because incumbents evade an incomplete regulatory framework that they helped design.

Methods and technologies that expand grid capacity and lower costs are sternly opposed by cost-of-service utilities eager to maximize rate base. For example, an upper Midwest pilot on topology optimization, which reroutes grid congestion, could scale up to save regional consumers hundreds of millions of dollars annually, improve grid resilience and increase wind integration.[3],[4] Unsurprisingly, expanding this technology is attracting interest from consumers, clean energy interests, the Organization of MISO states and the MISO independent market monitor (IMM).[5],[6] Yet one obstacle remains: incumbent utilities, which actively suppress efforts to use existing rate base more efficiently.

FERC issued a rule last December to address a similar problem: utilities were failing to implement best practices in transmission line ratings. A key motivator of the decision was analysis by MISO’s IMM saying that such practices would have saved MISO customers over $100 million in 2019 and 2020 alone.[7] Such analyses are the exception, not the rule, and speak to the imperative of more robust independent transmission oversight.

IMMs are also noting that incumbent TOs hold outsized influence in transmission planning processes, such as shaping planning inputs to their advantage, not actual values.[8] This contributes to planning processes that are short-sighted and do not reflect future generation.[9] Incumbents’ influence is further evident in the technical exclusions of transmission projects from competition solicitations. This has enabled incumbents to evade regional planning processes subjected to competition and build local projects instead, where they face neither competition nor economic regulatory scrutiny.

FERC-jurisdictional transmission investments (The Brattle Group) Content.jpgFERC-jurisdictional transmission investments with full and limited stakeholder review within ISO/RTO regional planning processes (2013-2017) | The Brattle Group

 

Unfortunately, this has led some to blame competition for the lack of regional transmission development, rather than the faulty regulatory framework that encourages problematic incumbent behavior. Make no mistake, reverting to exclusive incumbent control will undermine transmission expansion. Those tempted to believe that incumbents streamline transmission development need only examine MISO South, where incumbent utilities obstructed plans to build transmission that would boost severe weather resilience and enable cleaner, lower-cost energy access.[10]

Given the advantage of competition, it may seem paradoxical that some Midwest legislatures have passed anti-competitive “right of first refusal” (ROFR) laws to grant incumbents exclusive rights to build, own and operate transmission assets. But the recipe for this is no surprise; the concentrated interests of incumbent utilities exert a lobbying effort that overwhelms the voices of dispersed interests, namely consumers. In Michigan, the most recent state to pass a ROFR, incumbents overrode opposition from the Michigan Chemistry Council and conservative Mackinac Center for Public Policy.[11] Incumbent utilities are also behind new proposed ROFR legislation in Wisconsin, which the Wisconsin Industrial Energy Group has called “really terrible public policy” with billions at stake for customers.[12] As noted by Americans for Tax Reform, ROFR is effectively “a regressive tax hike on individuals, families and employers” in the Midwest.[13]

States have the right to shoot themselves in the foot. But they cannot harm their neighbor. ROFR for regional transmission projects unquestionably harms interstate commerce. The Wisconsin chapter of Americans for Prosperity remarked that state ROFR likely violates the Dormant Commerce Clause of the Constitution.[14]

Tellingly, out-of-state groups resist other states’ ROFRs. For example, the Iowa Department of Justice Consumer Advocate filed a legal brief challenging Minnesota’s ROFR.[15] Given the recency of most ROFRs, few developments have transpired to demonstrate the harm it causes, which limits court challenges under the Dormant Commerce Clause. But MISO’s new transmission cost sharing filing before FERC may illuminate ROFR’s premium.[16] This will amplify the legal case against ROFR and seed stakeholder resistance to anti-competitive grid expansion.

As resistance mounts, it is clear that ROFR increasingly undermines the interstate cooperation needed for regional projects. States like Illinois have resisted paying for the burdens of other states’ anti-competitive transmission laws.[17] Left unresolved, more litigation and controversy is unavoidable. And it is about to get a whole lot worse: MISO’s new Long Range Transmission Planning process is poised to unveil over $10 billion in transmission expansion, which may verifiably place ROFRs’ price tag in the billions.[18]

As the clock ticks, MISO stakeholders and FERC should call for a more independent planning process and robust Monitor oversight while dramatically narrowing the technical exclusions for competitive projects. What exclusions remain, such as a voltage exemption for local projects, should be subjected to regulatory scrutiny under demonstrated prudence reviews with equivalent rate treatment for incumbent and non-incumbent suppliers.[19] This will improve the quality of local projects and reduce incumbents’ use of regulatory arbitrage between regional and local project selection.

State legislatures should prevent and repeal ROFR laws to benefit themselves and their neighbors. If this does not eradicate ROFRs outright, FERC will have to step in to prevent interstate harm. The law is straightforward. The politics are not. Yet state commissions have already broken the ice by calling on FERC to encourage transmission competition.[20] FERC need only ask them how.

Devin Hartman is director of energy and environmental policy for the R Street Institute.

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FERC-State Transmission Task Force Debates Allocation, Benefits

The second meeting of a federal-state task force convened to spur transmission buildout exposed differences among regulators over how FERC could expand the menu of recognized transmission benefits when allocating costs for new projects.

The stickiest topic during Wednesday’s Joint Federal-State Task Force on Electric Transmission meeting in D.C. was how to divvy the costs of regional transmission projects that advance state public policy goals.

“We decided to go with the non-controversial, easy subject: transmission cost allocation,” FERC Chairman Richard Glick joked as he opened the meeting. “Everyone wants more transmission; no one wants to pay for it.”

A collaboration between FERC and the National Association of Regulatory Utility Commissioners, the task force could produce recommendations for new regulatory language or initiatives to improve transmission development. The team first met in November. (See FERC-State Tx Task Force Begins Work.)

Glick said FERC is interested in whether regions are fully assessing all the benefits associated with new transmission. Although the commission has broad authority in prescribing cost allocation, state cooperation is vital, he said.

“It would be foolish to think that we could do whatever we want and go home,” Glick said, noting that states wield authority over siting. “It’s vital that we go into this arm-in-arm and find something we can live with.”

Maryland Public Service Commission Chair Jason Stanek, task force co-chair alongside Glick, likened the discomfort with discussing allocation to the situation when a single bill arrives for large party of diners. He said the task force is focusing on how to split more nebulous transmission benefits like societal benefits, economic gains and cleaner air.

Matthew Nelson, chair of the Massachusetts Department of Public Utilities, said he saw nothing wrong with dividing a dinner bill based on who had a “more expensive meal or had a beverage with their dinner,” given that some states have more ambitious emissions-reduction and renewable energy targets.

But Glick pushed back against that idea. “It isn’t just the public policy goals that are achieved when projects are built in part to satisfy those public policy goals. There are other benefits — resilience, reliability, economics and so on,” he said.

The FERC chair also reminded the task force that quantifying benefits for allocation is both an “art and science.” He expressed optimism that the task force can isolate benefit measurements with a degree of certainty.

Stanek shared optimism that many benefits have “a price tag associated with them” and said sharper forecasting capabilities and better modeling tools are available today. He suggested that regulators solicit NERC’s input to conduct regional analyses “in order to award potential transmission projects with some quantifiable benefits.”

Glick agreed with that approach. “We need to figure out ways to expand the list of benefits that we are looking at … to be more granular in terms of type of benefits we are looking at, but also in terms of being able to better assess the value of those benefits and, more importantly, who benefits.”

IDing Necessary Tx Projects

The task force also pondered whether the three major drivers for building transmission — reliability, economics and public policy — should be expanded.

California Public Utilities Commissioner Clifford Rechtschaffen requested FERC issue guidance on additional types of benefits and methods for assessing them.

He suggested the reliability category should be opened to grid hardening projects; the economic category should include projects that facilitate improved connectivity to lower-cost generation and reduce market power; and the public policy category should be extended to projects that further a clean energy transition.

Rechtschaffen also argued that FERC guidance should extend the time frame for measuring benefits to 15 or 20 — or longer. “This better corresponds to longer-range goals such as renewables integration and emissions reduction targets,” he said.

Glick said the traditional, siloed approach to transmission cost-sharing makes less sense going forward. He said projects earmarked for one benefit often deliver other benefits once built.

“This idea that we can just plan for and allocate costs for transmission based on one particular set of benefits is probably a little bit outdated and doesn’t mix with reality,” he said.

Riley Allen Mark Christie (NARUC) Content.jpgVermont Public Utility Commissioner Riley Allen (left) and FERC Commissioner Mark Christie | NARUC

 FERC Commissioner Mark Christie cautioned that defining benefits too generally risks the construction of unnecessary transmission projects and extraneous costs to ratepayers. He also said directing RTOs to plan on a 15-year horizon seems uncomfortably close to the states’ integrated resource planning (IRP) processes.

“I would caution [that] looking at a 15-year holistic plan sounds like an IRP, and states are set up to do IRPs, and I don’t know the RTOs are set up to do IRPs,” Christie said. “Do you want RTOs to become integrated planners?”

In that scenario, Christie said, “money would begin to flow” on projects in an RTO’s regional plan before states had a chance to weigh in. As an example, he said Indiana ratepayers should not pay for a portion of a billion-dollar transmission line that serves a Virginia renewable portfolio standard.

In recapping the meeting, Stanek noted several members had brought up the importance of grid resilience and adding that as a new category in allocating costs.

“There’s a lot of benefits that are hard to quantify, but perhaps resilience is one topic where we could have some asymetrics on a regional basis, as opposed to a one-size-fits-all in terms of resilience for the country,” he said.

Consent Role for States

Christie asked state commissioners whether they should have a role in approving grid operators’ cost-allocation methodologies.

Kansas Corporation Commission Chair Andrew French recalled the praise he offered SPP during the first task force meeting.

“[SPP] offers the broadest, or one of the broadest, sets of rights to its state regulators and involves them in the cost allocation process, resource adequacy process and other items,” he said. “We have primary authority for setting the basis of any regional cost allocation.”

French said the RTO typically defers to decisions of the Regional State Committee (RSC), as it did last month when the RSC and the board approved fixes to FERC-identified deficiencies in the local facility cost-allocation process that had previously been contested by stakeholders. (See SPP Board of Directors/Members Committee Briefs: Jan. 25, 2022.)

“To the question of whether there should be a rigid consent of the states for cost allocation, that is tough,” French said. “I would exercise caution in saying our region, or any region, should have to reach consent of every single state before agreeing on cost-allocation methodology. There are going to have to be a lot of discussions and negotiations between lots of different counterparties to figure out what works and, ultimately, it would be ideal to come up with a framework that you could put in place for multiple iterations of similar planning processes in the future.”

North Carolina Utilities Commissioner Kimberly Duffley said that FERC should consider giving states a consent role but reminded her peers that not every state is the same.

“I think the concern for states is that they would have no control over their own destiny and their own costs,” she said. “We also need to think about equity issues and energy burden issues when you’re looking at this problem, because there are many states that have a much higher energy burden than other states. Asking them to take on another state’s public policy goal when they’re struggling to maintain the costs when reliability is the main driver is a hard pill to swallow.”

Thad LeVar Willie Phillips (NARUC) Content.jpgUtah Commission Chair Thad LeVar (left) speaks to Western needs as FERC Commissioner Willie Phillips listens.

 French cautioned against using “lists of dozens of different benefits that transmission can provide” as justification for a plethora of projects.

“I think that we should exercise a little bit of caution [rather than] just saying, ‘We are going to plan on using all of these benefits and we are going to build every single project,’” he said.

Arkansas Public Service Commission Chair Ted Thomas called for a “rigorous review” of benefits identification instead of relying on postage stamp rates.

“To make this process work, one of the things we need is common ground between those who see a policy imperative for building transmission and those who are worried about a fair deal and fuzzy benefits on the other side,” he said. “How you bridge that gap, I think, starts with identifying these benefits.”

FERC’s Willie Phillips said that as a new commissioner he’s interested in balancing energy sustainability with affordability. “Having grown up in rural Alabama, I know firsthand how any cost increase can affect customers and that affordability is a critical backbone to economic development.”

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NERC Standards Committee Fast Tracks Cold Weather Project

In a sign of the urgency with which members view NERC’s latest cold weather standards development project, NERC’s Standards Committee voted Wednesday to give its executive committee the power to approve the project’s next steps.

The discussion on Project 2021-07 (Extreme cold weather grid operations, preparedness and coordination) garnered the most attention of any item at the committee’s truncated monthly meeting. Members agreed to delegate to the Standards Committee Executive Committee (SCEC) authority to accept the revised standard authorization request (SAR) for the project when the SAR drafting team finishes it, and to appoint the SAR drafting team as the project’s standard drafting team (SDT).

Under normal circumstances, these actions are undertaken by the full committee at its regular meetings, the next of which is scheduled for March 23. NERC Manager of Standards Development Latrice Harkness told the committee that SAR drafting team members expect to finish revising the SAR before that meeting, and “due to the time-sensitive nature of the project,” they wanted to move on to drafting the standard as quickly as possible and “build on the momentum and discussions” from previous meetings.

“It may not seem much, but this action would give the team several additional weeks that … they would not otherwise have, to have these robust conversations on the best path forward and how to best put pen to paper for this project,” Harkness said.

Work on Project 2021-07 has proceeded quickly since the Standards Committee approved the draft SAR at its November meeting. (See NERC Standards Committee Agrees to New Cold Weather Project.) After being seated at the committee’s January meeting, the SAR drafting team met multiple times a week in late January and early February as it considered industry comments on the draft SAR.

NERC initiated the project to carry out the recommendations of its joint inquiry with FERC into last February’s winter storms that knocked thousands of megawatts of capacity offline in Texas and left households across the state without power for days. (See FERC, NERC Release Final Texas Storm Report.) Among the report’s proposals were requiring generator owners and operators to identify and protect cold weather-critical components, build or retrofit generating units to operate to specific ambient temperatures and weather, and perform annual training on winterization plans.

The project team’s quick pace of work is also, in part, a response to prodding from NERC’s Board of Trustees, which at its November meeting expressed frustration at the Standards Committee over the project. (See “Frustration at Cold Weather Delay,” NERC Board of Trustees/MRC Briefs: Nov. 4, 2021.) At the time the committee had not yet approved the SAR; at its October meeting members voted to delay approval until the final report was issued. (See NERC Standards Committee Delays Action on Cold Weather SAR.)

Concerns About Limited Feedback Opportunities

Most committee members supported delegating authority to the SCEC. The only attendee to speak out against the move was Marty Hostler, reliability compliance manager for the Northern California Power Agency, who argued that “the entire [committee] should be looking at this” so that members could hold the SAR drafting team accountable for their response to industry comments, which he felt was especially important for such a potentially far-reaching project.

“I’d be supportive of comment phases being shorter or things like that to help speed up the timetable, but not just having only a few people looking at this,” Hostler said.

NERC staff did not address Hostler’s objections directly. However, in response to questions from other attendees, Howard Gugel, NERC vice president of engineering and standards, assured the committee that the SCEC’s teleconference would be open to the public with at least five days’ advance notice. Chair Amy Casuscelli of Xcel Energy further clarified that members of the full committee will be able to make comments at the SCEC’s meeting in addition to listening in.

While these arguments did not persuade Hostler to vote for the measure, he did not vote against it, choosing to abstain along with Venona Greaff of Occidental Chemical. All other committee members voted to approve the delegation.

SDT Expansions Approved

Also at Wednesday’s meeting, the committee authorized the solicitation of additional members to the SDT for Project 2021-03 (CIP-002 Transmission owner control centers), along with assigning the project an additional SAR and request for interpretation, both relating to the CIP-002-5.1 (BES cyber system categorization).

The team for Project 2021-03 is preparing a field test to help guide further development projects relating to the standard, and the measures approved on Wednesday are intended to consolidate all projects relevant to CIP-002 under a single team to avoid duplication of effort. Harkness said the solicitation of more participants — NERC hopes to expand the team to up to 14 members, from its current eight — will allow the project to stay on schedule.

Committee members also approved the appointment of additional members to the teams for Project 2019-04 (Modifications to PRC-005-6) and Project 2020-02 (Transmission-connected dynamic reactive resources). Respectively, the appointments will add six and two members to the teams.

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Panelists Discuss Obstacles to Rooftop Solar Installation

The nation’s regulated electric utilities are an obstacle to the growth of home and community solar and will be an obstacle to the Biden administration achieving decarbonization of the nation’s electrical grid by 2035, a major solar developer charged Wednesday.

“I think you’ve got the 20th century playing against the 21st century, quite frankly,” Jeff Weiss, executive chairman of the D.C.-based Distributed Sun, said during a webinar produced by OurEnergyPolicy. It was the launch of a broadside attack on utilities about three-quarters into the hourlong discussion, which was focused on distributed generation and its developing role on the grid.

“I think the utilities are playing a stacked deck of cards because of the way the regulatory system works in most states, Weiss said. “In most states the public service commissions do what the utilities ask them to do. That’s a bad game. It’s not going to help the environment. It’s not going to help environmental justice. It’s not going to build renewable energy. It’s going to slow everything.

“I think that they, writ large, hire a well known advisory services firm … called ‘Stall Hinder & Delay.’”

That utilities may be reluctant to completely transform the nation’s generation and distribution system in less than 15 years is not a revelation. The Edison Electric Institute, a trade group for the industry, pointed out how extraordinarily difficult such a change would be as early as a year ago. (See EEI: Net Zero by 2035 ‘Incredibly Difficult’.)

The straight-from-the shoulder assessment from Weiss came in response to more gentle discussion that began with a comment from Marilyn Brown, interim chair of the School of Public Policy at the Georgia Institute of Technology, on the problem of low-income households not being able afford the cost of home solar.

Discussion moderator Michael Dorsey, a partner with IberSun North America in Michigan, responded, “I’m glad you flagged … some of the dissonance in some approaches with utilities with respect to distributed energy resources. Where do you see this dissonance between [distributed energy] managers playing out?”

Brown said the problem “is all about return on investment when it’s an investor-owned utility,” and added that utilities in vertically integrated markets “have to have a business case for getting engaged and supporting this effort.”

“It’s got to be clear and profitable, or at least neutral, if others are going to take the business and run with it. So I’m very sympathetic to this problem of incentives. I don’t have an answer,” she said.

Looking to delve deeper into the problem, Dorsey asked for a comment from Weiss and from a fourth participant, Garrett Nilsen, acting director of the U.S. Department of Energy’s Solar Energy Technologies Office.

“Does the business case trump the overhang of the climate catastrophe?” asked Dorsey. “We wouldn’t want to have only a business outlook and forget about this other existential crisis.”

Nilsen said he would not weigh in on either side of the argument, except to say that the problem is “one of lots of headaches.”

“These are not going to be easy conversations, given the number of parties that are impacted, the number of interests that are entrenched and the number of new interests that want to be playing in the game,” he said.

“It’s not something that’s going to be solved this year or next year, maybe by 2030,” he added. “What’s great is that now we can move to a point from having emotional conversations to trying to figure out how do we dig into the actual data? What does the data tell us about how this works?”

One forecast to which the panelists agreed is that solar will continue to be added to the grid and that the cost of solar technologies will continue to fall.

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New Jersey Lawmakers Push for Equity in Solar, Wind Energy Benefits

New Jersey legislators have advanced legislation to create an Office of Clean Energy Equity and to fund a $20 million a year financing program for state and local government energy efficiency programs.

The Senate Environment and Energy Committee voted 5-0 on Thursday in favor of a bill that would create an office to “promote, guide and oversee the equitable deployment of clean energy, energy efficiency and energy storage programs and technologies” (S336). The program would focus on giving greater access to “overburdened communities,” those that have low-income, minority or tribal residents, or have a large population with limited English proficiency.

The legislation requires the office, located in the New Jersey Board of Public Utilities, to create solar and community solar programs that by 2030 benefit 250,000 low-income householders or 35% of the low-income households in the state, whichever is larger.

The bill also would require the board to create 1,600 MW hours of energy storage in overburdened communities and take steps to ensure that clean energy and the process by which it is developed should be accessible to overburdened communities. The legislation requires creation of clean energy workforce development programs for those communities, outreach and recruitment grants to local organizations, and establishing an advisory board that includes representatives of overburdened communities. The office would be funded with 10% of the state’s annual clean energy budget, or at least $50 million.

The bill, which would need the backing of the full Senate and Assembly to get to the governor’s desk, drew the support of a variety of environmental groups, along with the New Jersey State Chamber of Commerce, the Solar Energy Industries Association and the New Jersey State NAACP.

Anjuli Ramos-Busot, director of the New Jersey chapter of the Sierra Club, called it “critical for New Jersey to include equity as part of its clean energy work.”

“This is imperative so that everyone in our state can fairly access the benefits of renewable energy like solar and wind,” she said. The act, she added, “will help reduce greenhouse gases and co-pollution while saving people money and creating green jobs in communities that are disproportionately affected.”

Funding Energy Efficiency

The committee also backed a bill that would enable the New Jersey Infrastructure Bank to provide loans and financial assistance that state and local governments can use to finance “cost-effective” energy efficiency improvements in government buildings (S419).

The BPU would fund the program, to be known as the Renewable and Efficient Energy Financing program, with an annual allocation of $20 million from the state’s societal benefits charge.

Committee Chairman Bob Smith (D) encouraged his colleagues to see the investment potential of the bill.

“The more renewable [projects] and efficient energy financing that we do, the better off the state’s going to be,” he said. “This is not a freebie; it’s a loan. So, the money comes back to the state.”

In a separate action, Smith re-introduced a bill Thursday that would codify into law parts of Gov. Phil Murphy’s 2019 Energy Masterplan (S1336). They include the goal of putting 330,000 light-duty vehicles on New Jersey streets by 2025; producing at least 35% of the state’s electricity through renewables means by 2025; and ensuring sufficient storage to provide 2 GW of electric power for at least 24 hours by 2035.

Smith introduced the bill in the last legislative session, but although it secured approval of the Senate and the Assembly Environment and Solid Waste Committee and Science, Innovation and Technology Committee, it did not get a full Assembly vote before the session ended in January. The bill was seen as a way to ensure that the state would continue pursuing a clean energy strategy even under future administrations that may be less enthusiastic about the policies in the masterplan. (See Lawmakers Back Putting NJ’s Clean Energy Plan into Law.)

Leaders Urge Haste

Before the advance of the two bills Thursday, BPU President Joseph L. Fiordaliso, in testimony unrelated to the bills, told lawmakers that the threat of climate change is so serious that the cost of fighting it must be accepted. Fiordaliso spoke at a section of the committee hearing set aside for state officials to outline their view of the threat of climate change and what should be done to mitigate it.

“Is clean energy expensive?” he asked. “Yes. But how expensive would it be if we did absolutely nothing?” He added that the benefits of the clean energy “revolution” should be spread across all communities.

“Regardless of location, it is extremely important that all of us have the opportunity to participate,” he said. “Because to mitigate the effects of climate change requires the efforts of each and every one of us.”

Department of Environmental Protection (DEP) Commissioner Shawn LaTourette echoed Fiordaliso’s call for urgency.

“We should be doing [clean energy and mitigation programs] and we should be doing them faster,” he said. “Because depending on how fast we do those things, it will determine just how bad it is after 2050.”

In a separate initiative, the Senate Economic Growth Committee on Thursday backed a bill that would require the New Jersey Economic Development Authority to develop a Request for Proposals (RFP) on plans for creating microgrids to support fleets of medium- and heavy-duty electric vehicles (S787). Microgrids could allow the vehicles to continue operating even if the main grid is disabled because of extreme weather events or other disasters.

The RFP, to be developed in consultation with DEP and the BPU, would seek proposals for at least one microgrid in each of the regions served by the state’s five electric utilities Each micro-grid should be designed to support “very high coincident peak vehicle electric load,” the legislation states.

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MISO, SPP Take on 2nd Interregional Planning Effort

MISO and SPP will begin a smaller interregional planning study this year along with their ongoing joint interconnection queue study, stakeholders learned this week.

The study will come in the form of a targeted market efficiency project (TMEP) approach instead of the usual coordinated system plan (CSP), the RTOs announced during Tuesday’s Interregional Planning Stakeholder Advisory Committee. TMEPs are smaller, congestion-relieving cross-border transmission projects already in use between MISO and PJM.

The grid operators last performed a CSP in 2020. Their joint operating agreement requires an interregional study no less than once every two years.

MISO and SPP have undertaken four CSP studies since 2014. Each time, their planners have come up empty in agreeing on beneficial projects despite increasing congestion at their seams. (See 4th Time No Charm for MISO-SPP Interregional Study.)

This year, however, the RTOs will juggle the TMEP study alongside the Joint Targeted Interconnection Queue (JTIQ) study, which last month rolled out a $1.755 billion portfolio of suggested projects. (See MISO, SPP Roll out $1.755B Joint Tx Portfolio.)

The JTIQ is meant to increase system capacity and ease the grid operators’ overcrowded interconnection queues amid shifting resource mixes. It was announced in 2020, around the time that the fourth CSP failed to produce an interregional project.

Missouri Public Service Commission economist Adam McKinnie said his commission appreciated the JTIQ study’s work but pointed out several congested areas remain along the MISO-SPP seam that could use more precise upgrades.

McKinnie and other state regulators have advocated for the smaller-scale TMEP study process for more than a year. (See MISO, SPP Regulators Call for Pancaking Fix, Smaller Projects.)

Evergy’s Katy Onnen asked that the interregional study modeling contain high wind generation scenarios, something the RTOs’ modeling doesn’t currently consider.

SPP’s Neil Robertson reminded stakeholders that the proposed JTIQ portfolio will likely resolve the need for some projects that might otherwise be pursued under a TMEP process.

“I want to remind everyone that we have multiple efforts working in parallel right now,” he said. “With multiple parallel efforts in the interregional planning sphere in play, there’s going to be some overlap.”

Robertson said MISO and SPP have yet to decide how they will model the JTIQ projects in the TMEP process.

“I just really hope you don’t consider the JTIQ a done deal,” McKinnie said, noting that its cost-allocation discussions are not very far along and imply that disagreements might derail projects.

“I’m fine with solutions competing against each other,” he said. “I just urge you to look at issues rather than say, ‘It’s in the JTIQ, therefore it’s a third rail that we can’t touch.’”

Robertson said staffs will not consider JTIQ projects as certainties to include in a base-case model for another interregional study.

Some stakeholders said MISO and SPP might want to pursue smaller TMEP fixes while waiting on big-ticket JTIQ projects’ construction.

The RTOs said they opted for a TMEP study over a CSP partly because neither is performing an economic study as part of their 2022 transmission planning. TMEPs don’t require staffs to conduct production cost modeling.

“We don’t have that synergy this year,” MISO engineer Ben Stearney explained.

Stearney said the grid operators have a framework “starting point, given the existence of the MISO-PJM TMEP.” He said the RTOs and their stakeholders will settle on a TMEP study scope and criteria throughout 2022. The process will be memorialized in their joint operating agreement.

PJM’s and MISO’s version of TMEPs must cost less than $20 million, be in service within three years of approval and, within four years of operation, provide congestion relief equal to or greater than the construction cost. MISO’s and SPP’s TMEP criteria could look different.

The grid operators also said the TMEPs’ targeted study style and smaller transmission projects will help ease their interregional workload, given the ongoing JTIQ. The study is not considered part of either a CSP or TMEP study.

“The reality is that developing the cost allocations around the JTIQ are going to be complex, and we don’t see that happening until 2023,” Stearney said.

MISO and SPP plan to schedule more joint planning meetings in the second quarter.

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New England’s Duck Curve Days Chart Solar Growth

On two mild, sunny days in New England last week, energy demand was at its lowest in the middle of the day, when the thousands of megawatts of mostly behind-the-meter solar installations in the region were at their most effective.

It’s the latest example of the phenomenon first noticed in California and known as the “duck curve,” named after the duck-shaped pattern that occurs from charting power demand and the availability of solar.

Increasingly common “duck sightings” in New England are a signifier of the growth of solar in the region that doesn’t show any signs of slowing down.

On Feb. 11, load dipped to 11,207 MW at 12:55 p.m., according to ISO-NE. LMPs were negative for some of the mid-day period on Friday, hitting a low of $-63.83. Two days earlier, load had hit a low for the day of 11,890 MW at 12:30 p.m.

Midday load in NE 2022-02-09-11 (ISO-NE) Content.jpgMidday load in New England dropped below overnight load on Feb. 9, above, and Feb. 11. | ISO-NE

New England has seen more of these mid-day minimum load days each year since 2018, when it first occurred, according to ISO-NE data. 2019 saw three such days, with 13 in 2020 and 18 in 2021. This year has seen three so far, marking the first time the phenomenon has occurred so early.

The duck curve and solar’s intermittent nature have been known to bring operational challenges to other regions. Grid operators have to quickly ramp up dispatchable resources when the sun goes down and solar output falls, and they might have to curtail solar generation in the case of excess capacity. ISO-NE launched an enhanced real-time fast-start pricing feature in 2017 to try to incentivize resources that can quickly ramp up their output to help address the sharp rise in demand when the sun sets.

ISO-NE spokesperson Ellen Foley said in an email to RTO Insider that the existence of duck curves is notable, but it “doesn’t really define how the system is operated.” The grid operator optimizes commitment and dispatch using the day-ahead market; it then develops an operating plan and manages the power system based on that plan, she said.

Solar Boom

Because of the distributed nature and less predictable qualities of solar, it’s tricky to forecast on a day-to-day basis.

“Forecasting that [load] reduction continues to be a challenge for the ISO; going into the day, we could be forecasting high production from solar PV, only to see more cloud cover or snow lingering longer than expected, which results in the ISO using more traditional generators to replace that energy. Therefore, we are continuously working on updating and improving our PV forecasts,” Foley said.

Solar growth in NE (ISO-NE) Content.jpgSolar growth in New England has repeatedly outpaced forecasts. | ISO-NE

 

But its long-term projections, based on historical trends and state policy, show that solar production will continue to be an increasingly significant presence in New England over the next decade.

ISO-NE’s latest draft forecast of solar development, published on Monday, estimates 11,298 MW of solar generation in the region by the end of 2031, nearly 2.5 times the 4,767 MW installed in New England at the end of 2021.

The RTO’s changing forecast itself is another sign of the rapid solar ramp-up, with this year’s projections for 2030 more than 830 MW above the 2021 forecast.

Massachusetts remains the driver of solar growth in the region, with more than two-thirds of New England’s installed capacity in the Bay State.

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NWPP Rebrands as Western Power Pool

In a move that signifies its expanding reach across the Western Interconnection, the Northwest Power Pool has rebranded itself as the Western Power Pool.

What was once a member-run organization focused mainly on grid reliability in the Pacific Northwest and Intermountain regions, Portland, Ore.-based NWPP (now WPP) has spent the past two years going south — and east.

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Since 2020, WPP has been developing the Western Resource Adequacy Program (WRAP), an initiative conceived to address concerns that Northwest utilities have been increasingly — and unknowingly — drawing on the same shrinking pool of reliability resources. Participants used its interim “matching service” for entities either long or short in the electricity market four times last year, mostly during a record-smashing heat wave in the Pacific Northwest.

But interest in the effort spread quickly to other areas of the West. The WRAP, which is slated to launch a “nonbinding” iteration in the third quarter of this year, has attracted participants from an area spanning British Columbia, south to Arizona and east into South Dakota. Stage 1 of the WRAP will include 26 participants that together represent a summer peak load of about 67,000 MW and a winter peak of more than 65,000 MW.

“With the addition of new participants from the Southwest and the expansive footprint of our existing programs, we are excited to announce a name change that demonstrates our vision,” WPP COO Gregg Carrington said in a statement last week. “The Western Power Pool will continue to offer the excellent services our customers rely on while creating a more inclusive space for Western coordination and collaboration.”

In creating the WRAP, WPP has also been forced to repurpose itself as an organization. Once the WRAP enters its “binding” phase in 2023, the market — and WPP — will become subject to federal oversight and FERC rules.

Anticipating those requirements, WPP has already moved to restructure its governance and prepare to adopt some elements of an RTO, such as the appointment of an independent board of directors. WPP will also establish an RA Participants Committee as well as a Committee of States to ensure that utility regulators have a voice in discussions related to the WRAP. (See RA Program will Require Restructuring of NWPP.)

And while WPP has not signaled intentions to expand the WRAP’s offerings beyond resource adequacy, the market looks increasingly like a possible platform for incrementally developing a Western RTO — one that would compete with CAISO’s stalled regionalization efforts, the ISO’s well established Western Energy Imbalance Market, and SPP’s nascent RTO West and Western Energy Imbalance Service.

WPP last year selected SPP to operate the technical aspects of the WRAP, providing the market’s forward-showing functions, modeling and system analytics, and real-time operations.

In December, SPP revealed plans for broader engagement with WRAP participants through its Markets+ program, a “conceptual bundle of services” that includes day-ahead and real-time commitment and dispatch, and “hurdle-free” transmission service. Those services would be packaged in a way designed to appeal to utilities still unready to commit to a full RTO, SPP said. (See SPP Aspires to Increase its Western Footprint in 2022.)

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Massachusetts Legislators Call for Fossil Fuel Ban in Net-zero Building Code

Massachusetts legislators expressed disappointment Tuesday that fossil fuel use would be allowed under a net-zero building code straw proposal introduced by regulators.

The proposal “didn’t go far enough,” said Sen. Cynthia Creem (D), chair of the Massachusetts Senate Committee on Global Warming and Climate Change.

“The draft net-zero code would not represent a path for cities and towns to restrict the use of fossil fuels in new development,” she said during a committee hearing on the implementation of the state’s climate roadmap enacted last March.

A specialized net-zero code will be part of a three-tier system of building codes authorized by the law. Existing tiers include a base building code and a municipal opt-in stretch energy code. The state is updating the stretch code in consultation with the Board of Building Regulations and Standards, which is responsible for regular updates to the base code. In addition, the law calls for development of a municipal opt-in net-zero code as a third tier.

Tiers 2 and 3 — which apply to new building construction, additions and major retrofits — offer progressively more stringent compliance pathways for energy efficiency beyond the base code. The Department of Energy Resources (DOER) released a proposed update to the stretch code and the proposed specialized code last week for comment.

Compliance with the tiers will be based on the Home Energy Rating System (HERS) index, which scores efficiency between zero and 150, with 150 being the least efficient. Buildings complying with the base code must achieve a HERS rating of at least 55, while Tier 2 compliance ratings would be 42 for buildings that use fossil fuel heating and 45 for buildings with electric heating.

Net-zero code compliance would have the same Tier 2 ratings for buildings with fossil fuel and electric heating, but buildings that include fossil fuel heating must also have rooftop solar where feasible and be pre-wired for electrification.

About 85% of Massachusetts’ municipalities already opt in to the stretch code, and many are interested in upgrading to the net-zero code. A group of 30 town and city representatives sent a letter to the Executive Office of Energy and Environmental Affairs (EEA) last fall in support of a net-zero code that gives municipalities “clear authority to prohibit on-site combustion in new buildings and major rehabilitation.”

Without the option for communities to “actually experiment with going net zero,” the proposed code is a “reversal of legislative intent,” Sen. Michael Barrett, committee vice chair, said during the hearing.

“We wrote language that permitted communities to have a vigorous local debate … before opting in, but we imagined that once they made that decision, they would do so knowing that new construction without a backup fossil-fuel hookup was an option that they could pursue,” he said.

The purpose of the new code, as written, is to “encourage construction of all-electric buildings,” Kathleen Theoharides, secretary of the EEA, said in hearing testimony.

“Dictating certain fuels be used or certain things be banned is not innovation; it’s a requirement,” she said. “What we’re doing is creating a code that requires the most energy-efficient building envelopes possible, as well as additional things that … allow for experimentation.”

Creem would like to see the administration update the proposed code so that it is a “fossil-free option” for municipalities. But the proposal, Theoharides said, balances energy efficiency, cost and emission reductions, while seeking to ensure an orderly transition.

“The challenge with letting some people come off of gas … is that you leave customers on the gas system who are the least able to make the change and end up bearing the brunt of the cost for the remaining gas system as we transition away from it,” she said.

The DOER will accept comments on the straw proposal for the updated stretch code and new net-zero code through March 9, followed by public hearings over the summer. The final language for both codes is due in the fall.

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Biden Admin Launches Drive to Decarbonize US Industrial Sector

The White House on Tuesday continued its execution of the Infrastructure Investment and Jobs Act (IIJA) with a new group of requests for information (RFIs) and guidance documents, this time aimed at hard-to-decarbonize industrial products, including steel, aluminum and concrete.

The Department of Energy issued two RFIs, one on the IIJA’s $8 billion allocation to develop four clean hydrogen hubs across the country, and a second on the $1.5 billion in funding for research and development for clean hydrogen manufacturing and recycling.

The White House Council on Environmental Quality (CEQ) also issued draft guidelines for federal agencies on “responsible deployment” of carbon capture, utilization and sequestration (CCUS) projects. The IIJA provides $3.5 billion for CCUS demonstration and pilot projects and another $2.5 billion for low-interest loans for CO2 pipelines.

Other initiatives outlined in a White House fact sheet include:

  • the creation of a Buy Clean Task Force to “harness the federal government’s massive purchasing power to support low-carbon materials made in American factories”;
  • a new Technology Innovation Advisory Committee charged with “creating a comprehensive strategy to lower the carbon footprint of America’s industrial base”; and
  • trade policy being developed with the EU to keep “dirty steel” out of U.S. and European markets and limit steel dumping.

“The industrial sector is … central to tackling the climate crisis, as it is currently responsible for nearly a third of domestic greenhouse gas emissions,” the administration said. “By helping manufacturers use clean energy, efficiency upgrades and other innovative technologies to reduce emissions, the administration is supporting cleaner industry that can produce the next generation of products and materials for a net-zero economy.”

“With industries moving quickly to adopt and deploy carbon capture technologies, federal agencies can play a key role in ensuring that projects are done right and in a way that reflects the needs and inputs of local communities,” CEQ Chair Brenda Mallory said. The new guidelines are a first step toward CCUS “deployment in a manner that is environmentally sound and that cuts cumulative pollution in nearby communities.”

The hydrogen RFIs are part of DOE’s Hydrogen Shot, another initiative aimed at reducing the cost of clean hydrogen by 80% over the next decade, from the current price of about $5/kg to $1. According to the RFI on hydrogen hubs, “co-locating large-scale clean hydrogen production with multiple end uses can foster the development of low-cost hydrogen and the necessary supporting infrastructure to jumpstart the hydrogen economy in various market segments, create both near-term and long-term jobs and tax revenues for regional economies, and realize emissions-reduction benefits.”

The IIJA requires that the four hubs must each be located in different areas of the country; use different fuels, including natural gas, renewable energy and nuclear; and demonstrate applications in different industries: electricity, transportation, industry, and residential and commercial heating.

“Clean hydrogen is key to cleaning up American manufacturing and slashing emissions from carbon-intensive materials like steel and cement.” Energy Secretary Jennifer Granholm said in a statement. The goal is to help make “scaling up this clean, affordable energy source a reality for the United States.”

CEQ Guidelines

The guidelines for carbon capture and storage recognize the complex challenges that will be involved in permitting these projects. A demonstration project on federal land could trigger environmental assessments under the National Environmental Policy Act, Endangered Species Act and the Clean Air Act.

For example, to streamline permitting, the guidelines suggest that agencies develop “programmatic environmental reviews … where such analyses can facilitate more efficient and effective environmental reviews of multiple projects while maintaining community engagement.”

For building out a network of pipelines for CO2 transport and sequestration, the guidelines call for “close monitoring and enforcement of existing regulations and development of new tools to monitor and improve safety while also reducing the number of incidents that result in leakage of carbon dioxide.”

Jessie Stolark, policy and member relations manager for the Carbon Capture Coalition, said the clean industry initiatives reflect “broad, bipartisan support for the economywide deployment of carbon management technologies and further [underscore] President Biden’s commitment to utilizing carbon management as a critical tool to decarbonize heavy industry and manufacturing.”

“Federal investment in industrial decarbonization is key to American prosperity and to putting domestic industry firmly on the path toward deep emissions reductions, retaining and creating high-wage jobs, and continued technology leadership and economic competitiveness,” Stolark said.

On Thursday, DOE and the Department of Transportation announced the first round of state allocations for the $5 billion in the law to help states deploy electric vehicle chargers along main transportation corridors. (See States to Get $615 Million for EV Charging from IIJA Funds.)

DOE also released state guidelines for applying for the money, and the White House has issued a 465-page guidebook to help the states navigate all the IIJA funding opportunities.