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November 20, 2024

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Nevada Plots Approach to Building EV Charging Network

The Biden administration last week launched a $2.5 billion program to fund EV charging stations across the nation, but the state of Nevada doesn’t plan to apply.

Instead, the Nevada Department of Transportation will support applications from local governments and other entities that apply for the funding.

The new funding, through the U.S. Department of Transportation’s Charging and Fueling Infrastructure (CFI) discretionary grant program, is a complement to the federal National Electric Vehicle Infrastructure (NEVI) program. (See DOT Opens New Round of IIJA Funding for EV Chargers.)

All 50 states plus Puerto Rico and D.C. submitted NEVI plans last year, which the Federal Highway Administration approved in September. The goal is to create a national network of public EV charging stations. Nevada is receiving $38 million in NEVI funds.

“At this point, Nevada is looking to spend the NEVI funds. We are not looking to apply for discretionary grants,” said Kandee Bahr Worley, NDOT’s division chief for sustainability and emerging transportation. “We’re hoping that our MPOs, [metropolitan planning organizations] our cities, our counties and other entities would be reaching out for those funds for projects that they’re putting together.”

Bahr Worley said NDOT is willing to write letters of support for funding applicants, offer grant-writing assistance “and hopefully win those grants and bring that money into Nevada.”

Bahr Worley’s comments came during a Southwest Energy Efficiency Project (SWEEP) webinar last week on funding opportunities for EV infrastructure in Nevada.

Travis Madsen, SWEEP’s transportation program director, said that Nevada is one of the top 10 states when it comes to EV market share. Last year, nearly 10% of light-duty vehicle sales in Nevada were EVs. Close to 50,000 light-duty EVs will be on Nevada’s roads by the end of the year, he projected.

“Nevada is well on its way in the journey toward transportation electrification,” Madsen said.

Interstates, U.S. Highways

With the growing number of EVs comes the need for more public charging. Efforts to build a statewide charging network in Nevada got underway with the Nevada Electric Highway program, which funded about 30 EV charging stations.

The NEVI program will build on that work, and Bahr Worley gave an overview of Nevada’s NEVI progress. In the first year of funding, NDOT will focus on the state’s six interstates: I-15, I-80, I-11, I-580, I-215 and I-515.

Two new charging stations are planned — in Carson City and in either Jean or Primm along the I-15 corridor. Three other stations, in Moapa, Carlin and Wells, will be upgraded to meet NEVI standards. The program requires at least four charging ports per station with a power output of at least 15 kW each.

The second year will focus on U.S. highways 50, 395, 95 and 93. Those highways, along with the interstates, are designated alternative fuel corridors, which are the NEVI program’s priority.

In some cases, NDOT is requesting exceptions from NEVI program requirements to space charging stations 50 miles apart and locate them no more than a mile away from the highway. Bahr Worley noted that Nevada highways run through some unpopulated areas.

“Not only do we not have population, we do not have electricity at certain areas,” she said.

And NDOT is concentrating its efforts on areas outside of NV Energy territory. The utility, whose territory covers much of the state, has its own transportation electrification plans, mandated by Senate Bill 448 of 2021.

Nevada is also talking to Tesla about its plans, announced last month, to open some of its charging stalls to non-Tesla EVs.

One listener asked whether NEVI funds would be available for charging stations along state highways, some of which are heavily traveled.

Bahr Worley said that’s a possibility, if money is leftover after the charging network along U.S. highways and interstates is built out.

CFI Flexibility

The newly launched CFI discretionary grant program is another possible funding source for charging sites on state highways.

The program has two components. In the Corridor Program, funding is reserved for EV charging infrastructure along alternative fuel corridors, such as interstates and U.S. highways.

But the Community Program provides more flexibility, with funding available for EV charging stations on any public road, at public buildings or parks, or at publicly accessible parking facilities owned or managed by a private entity.

Entities that are eligible to apply include states, local governments, MPOs, special districts or authorities with a transportation function, public and state colleges and universities, and tribal governments.

In the first round of CFI funding, $700 million will be available. The application deadline is May 30. A webinar on March 22 will cover more details.

Both the NEVI and CFI programs were established through the Infrastructure Investment and Jobs Act (IIJA). Other programs expanded under IIJA also offer funding for EV charging, infrastructure planning and workforce development.

To help sort out the various federal funding options, the Electrification Coalition has developed a tool called the EV Funding Finder.

Webinar speaker Will Drier, a policy manager with the Electrification Coalition, said the tool includes information such as matching-fund requirements and whether money from different funds can be combined or “stacked.”

The tool includes case studies on different transportation electrification scenarios, such as a city that plans to electrify its fleet.

More information on the EV Funding Finder is available here.

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Webinar Wades into Push to Revise US Permitting Rules

The U.S. must change its permitting processes to deploy the $2 trillion allocated for energy in last year’s industrial policy bills and ensure the emissions reductions needed to avoid the worst impacts of climate change, speakers said during a webinar hosted by Our Energy Policy Wednesday.

Rep. Pete Stauber (R-Minn.), whose Northeast Minnesota district is home to the nation’s biggest reserves of key clean energy industry minerals such as nickel, cobalt and platinum, said a proposal to speed up approval of mining permits has made it into House Republican bill HR 1, which is expected to move to a floor vote in the coming weeks. (See Republicans’ Opening Offer on Permitting is Missing Electric Tx.)

“We have yet to move earth at all on those resources,” Stauber said. “In fact, we have one mining proposal on year 20 of permitting and litigation. Think about that: a proposal to mine the minerals needed for clean energy is being held up for 20 years.”

Without tapping those resources and many others, renewable energy goals will not be attained, he said.

“We are dealing with an incredibly complex permitting landscape that’s influenced by an extraordinarily dynamic regulatory landscape that is — across federal, state [and] local levels — often uncoordinated,” said Karen Hanley, senior vice president at the Permitting Institute. “And when we’re talking about ‘rising tides lift all boats,’ we’re looking for good governance in the permitting process itself.”

Much of the conversation on the Hill has been dominated by the National Environmental Policy Act, which Hanley noted is just one of 65 federal laws and regulations that impact permitting, on top of many more rules from the states and local government.

“Where policy comes into play, we consider that to be a separate discussion; the process itself should not be used subjectively to pick winners and losers,” Hanley said.

The permitting process must weigh the benefits of an infrastructure project against its impact on the area where it is built, other speakers said.

“It’s all just a matter of trade-offs,” said Paul Phifer, director of permitting and development at Attentive Energy. “I mean, all permitting to me is an expression of our values. So, it’s an expression of risk management.”

Phifer’s firm is a subsidiary of French oil major TotalEnergies, which is developing an offshore wind project off the coast of New York. It would make sense for Congress to change the permitting laws to reflect some of the new tradeoffs faced by energy development now, he argued.

Setting the Tone

Much of the conversation on rule changes has focused on “categorical exclusions” that would give energy projects of preferred types or in specific areas an easy path through the process if they have limited environmental impacts, said Hanley. The Coast Guard must review some offshore projects, but it has a checklist it can apply to execute such categorical exclusions that ensure it has double checked that its oversight is not needed for specific projects, she added.

Accelerating the permitting process does not necessarily require a raft of new laws but rather Congress being clearer about how they are to be implemented, Phifer said.

“That’s the kind of thing that sets the tone that I would say that filters down … through the federal agencies even to the states, as opposed to tweaking and making minor regulatory revisions across the 65 laws that Karen mentioned,” Phifer said.

Getting any changes through Congress this year will require bipartisanship, with both chambers closely divided and controlled by different parties.

“I think there’s interest on both sides of the aisle, in particular, in long linear projects,” Hanley said. “I think there’s a recognition that where our energy needs are, isn’t necessarily the same places where the sources are, or the generation can be.”

Communities located between areas with energy resources and bigger sources of demand must often deal with projects that provide them little benefit, which brings up many complexities.

The issue of permitting has been debated for years, and Hanley expects lawmakers to insert many of their older proposals into the package. But she thinks there is opportunity to move forward on a package that addresses “fundamental process corrections” that do not eliminate necessary environmental protections.

“Obviously, all industries have their own little pet asks that they would like to see included in a package like that,” said Emily Wong, American Petroleum Institute’s director of federal relations. “But I think it’s been pretty clear from our discussion today, that we’ve all identified a lot of the same big-picture issues. And it’s certainly our hope, at API at least, that there’s enough agreement there for us to see something move across the finish line.”

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NYISO Battered but not Bruised this Winter

December’s winter storm and early February’s cold snap challenged the New York grid, causing outages and operational flow orders, but they did not cause any emergencies, NYISO told the Operating Committee last week.

Temperatures this winter were higher than normal, with the average temperature in Central Park during January being 43.5 degrees Fahrenheit, nearly 10 degrees over the 1991-2020 average. This January ranked highest in terms of average hourly temperature (37.5 F) among all years since 2011, and there were only 11 days in the month with a peak load of more than 20,000 MW, with the average since 2011 being 26.

But the two extreme weather events caused temperatures to drop rapidly. Aaron Markham, NYISO vice president of operations, noted that on Dec. 24, it was 50 F at noon in both Albany and New York City; by 8 p.m. that night, it was 15 F. Both natural gas pipelines and gas-fired generators experienced forced outages during the December storm because of frozen production wells and compressor stations.

Still, peak load only reached 22,004 MW during the storm, partly because, Markham said, it coincided with the Christmas holidays, which happened to be over the weekend. Conditions were tighter during the February cold snap, with the peak load of the season occurring on Feb. 3 at 23,369 MW, just shy of NYISO’s forecast of 23,893 MW. Temperatures dropped to as low as ‑2.3 F on Feb. 4, averaging 16.5 and 9.5 on Feb. 3 and 4, respectively.

However, Markham noted that there was little precipitation during the February event, and gas supply interruptions and plant outages were less than during the storm. 

Markham also highlighted that significant amounts of stored fuel was burned during the two events, concerning the ISO about replenishments for next winter. NYISO also heavily relied on oil-fired generation during the peak periods, with oil supplying 23% of power during the peak hour; gas supplied 24%. Gas prices in Iroquois Zone 2 reached $135.50/MMBtu on Feb. 5.

Nevertheless, NYISO was able to operate through the two events without calling on demand response resources or issuing any emergency actions, such as voltage reductions or public appeals for conservation.

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Ann Arbor to Open Talks with DTE on Future of Natural Gas Use

Ann Arbor City Council voted unanimously Monday to begin negotiations with DTE Energy (NYSE: DTE) immediately on a new gas franchise agreement aligned with the city’s A2ZERO plan to reach carbon neutrality by 2030.

DTE’s 30-year franchise agreement, which allows the utility to use the city’s rights of way and provide gas service to its residents, expires in 2027 but can be revoked by the city before then.

The resolution authorizing the renegotiation process (R-23-101) directs city staff to “ensure that any new or amended proposed franchise is aligned, to the fullest extent possible, with the city’s A2ZERO goals and best practices regarding uses of the city’s rights of way, without compromising the ability of community members to heat or cook in their homes and businesses.”

It notes that local governments, including Chicago, Salt Lake City and San Diego, have “successfully advanced affordability, equity, and clean energy goals” in their franchise negotiations.

City Sustainability Director Missy Stults has said the city is also watching efforts in Massachusetts to replace gas service with district-level geothermal systems to provide heating and cooling.

Ann Arbor Mayor Christopher Taylor said negotiating a new agreement made sense, and is, “consistent with the wishes of Ann Arbor voters who overwhelmingly passed a proposal in November to provide more clean energy choices and reduce dangerous pollution. Using clean, renewable energy to heat our homes and businesses will improve public health, reduce dangerous pollution that causes asthma, cancer and lung diseases, and save lives.”

City officials also said they will hold public listening sessions to get feedback from city residents as officials move forward with the negotiations. No dates for those public meetings have been set.

DTE spokesman Chris Lamphear said the utility “looks forward to having productive discussions with Ann Arbor leaders as we plot a course toward a cleaner energy future, which is a goal we both share. We are pleased to see the city continuing to collect feedback from its residents and businesses on the best paths forward, and we believe we can explore a range of possibilities that ensure the Ann Arbor community continues to have the safe and affordable energy it needs for decades to come.”

Lamphear said the company is working to reduce carbon dioxide and methane emissions in natural gas by 80% by 2040. With its renewable energy sources and local participation in the company’s MiGreen program, Lamphear said DTE has helped Ann Arbor reach 30% of its overall carbon reduction goal.

Ann Arbor has taken the most aggressive actions to reach carbon neutrality in Michigan. It has considered a local ordinance prohibiting new buildings from using natural gas but not acted on the proposal.

The city finds itself in a bit of a conundrum because it also is looking to develop new housing and has given initial approval for plans for a major housing development that would use natural gas for heating, drawing opposition from some city residents opposed to continued gas use.

DTE has said it would oppose a city ban on using natural gas in new construction, and Republicans in the Michigan legislature have introduced a bill barring local governments from preventing the use of natural gas.

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FERC Approves SSR Agreement for Wisconsin Coal Plant

FERC on Tuesday approved a MISO system support resource (SSR) agreement that will keep a Wisconsin coal plant operating for reliability purposes.

Under the agreement, Manitowoc Public Utilities will continue to operate its Lakefront Unit 9 coal-fired unit, effective Feb. 1 (ER23-914).

In a separate order, the commission questioned Manitowoc’s request for $1.03 million in monthly compensation for the plant, saying it might be overcharging customers for the one-year SSR. FERC established hearing and settlement judge procedures to settle the matter (ER23-977).

MISO told the commission that it would face unresolved thermal overloading and steady-state voltage issues on 12 constraints if Lakefront 9 was permitted to suspend operations as scheduled. The 63-MW unit began operations in 2006 and serves load in Manitowoc, Wis. MISO said there weren’t any nearby resources available to redispatch, viable transmission reconfiguration options, or enough demand-side management to avoid an SSR. (See MISO Proposing 2nd SSR Agreement for Retiring Coal Unit.)

FERC found that the RTO had no “feasible alternatives that could resolve the identified reliability problems … to avoid the need for the Lakefront Unit 9 SSR agreement.” The grid operator uses the agreements to keep generators online past their retirement dates as a last-resort measure for system reliability.

Manitowoc intended to suspend the unit and convert it for renewable fuel sources. It said it plans to bring the unit back to full commercial operation by the end of January 2026 “when the alternative fuel source becomes available in sufficient quantity.”

The municipal utility said it needs more than $1 million to cover operations and maintenance labor expenses, administrative expenses, non-labor maintenance expenses, site security, insurance, carrying charges and various fees and taxes.

Wisconsin Public Service and WPPI Energy protested Manitowoc’s proposed amount, arguing the utility showed no basis for its cost projections and estimates.

WPPI said Manitowoc used “unsubstantiated forecast inputs” in its cost-of-service model, “impeding the commission and consumers from undertaking a proper evaluation of the proposed charges.”

FERC agreed. It said its preliminary analysis indicated that Manitowoc’s requested amount might be unreasonable.

The SSR designation is MISO’s second within a year. In October, it received FERC permission to instate an SSR agreement for Ameren Missouri’s 1.2-GW Rush Island coal plant. The commission also cast doubt on the reasonableness of the monthly compensation in that proceeding.   (See FERC: Rush Island Plant’s Extension Essential to MISO Reliability.)

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Republicans Opening Offer on Permitting is Missing Electric Tx

House Republicans this month are moving a package aimed at changing the country’s energy permitting processes, but it lacks changes to a key area backed by Democrats and many in the power industry: electric transmission.

House Speaker Kevin McCarthy (R-Calif.) introduced HR 1, the Lower Energy Costs Act, last week, which includes a package of reforms to the National Environmental Policy Act and is largely aimed at oil and gas production and mining.

McCarthy gave the bill the number HR 1 because it is the House GOP’s top priority this Congress, he said last week. The Committee on Rules is already taking amendments on the package and could move the bill onto the floor by next week.

“Every time we need a pipeline, road, or dam, an average of almost 5 years and millions of dollars in costs get added to the project to comply with Washington’s permitting process,” McCarthy said. “That’s too long. We can streamline permitting and still protect the environment. That’s a goal worthy of the number one.”

American Petroleum Institute President Mike Sommers last week wrote a letter to House leaders from both parties in favor of the Republican package.

“One particular focus of API and our members is enacting serious, bipartisan permitting reform,” Sommers said. “Too many projects have been scuttled because of onerous regulations and uncertainty. The delays and denials of permits, stemming from lengthy regulatory reviews and drawn-out judicial proceedings, have stifled needed investments and increased costs.”

American Clean Power said HR 1 includes “important provisions and reforms” that will speed up the deployment of clean energy in the U.S.

“Failure to enact critical permitting reforms and lift barriers that are hindering our ability to build much-needed transmission puts an estimated 150,000 clean energy jobs at risk,” ACP President Jason Grumet said in a statement. “We look forward to working with Congress to build on this important effort.”

The package is full of ideas Republicans have been debating in recent Congresses and represents what that caucus wants to see happen on energy, said former FERC chairman and Hogan Lovells Senior Adviser Neil Chatterjee. The bill is likely to pass the House with Republican support and maybe a few Democrats too.

“It’s also an opening offer to negotiation with the Senate,” Chatterjee said in an interview. “And I think, ultimately, to the extent that something gets done specifically on permitting reform, I think the Senate is going to drive that. So, we just have to see what can get the votes in the Senate and also get a majority in the House.”

Any permitting reform that passes both chambers is likely to be narrower and will require some tradeoffs between Democrats who want to focus on expanding clean energy and Republicans who favor fossil fuels. Chatterjee said that partisan split does not make sense, but recent events have only solidified it. 

‘Easier Said Than Done’

The Inflation Reduction Act (IRA) included a number of provisions that Chatterjee supported as a Republican, but he was always critical of the fact that Democrats passed it without Republican support.

“My frustration was that it was done in a partisan manner,” Chatterjee said. “This is what this is, what I was concerned about, is that to the extent it became a political football, you wouldn’t get a whole lot of cooperation to make sure it’s implemented properly.”

Republicans did not include any provisions aimed at transmission in HR 1 because it would only help to implement the IRA and they have no incentive to help Democratic policy become a reality, he added.

“I think there is some willingness on the Republican side in both chambers to pursue transmission as part of a bipartisan bill,” Grid Strategies President Rob Gramlich said in an interview. “But I don’t I don’t think people are seeing HR 1 as really the bipartisan effort that includes transmission.”

Any bipartisan bill would have to include provisions that speed up the pace of transmission development significantly, and many climate hawk Democrats will have to decide whether any deals they cut lead to long-term emissions cuts, Gramlich said.

“I think there’s a lot of interest in more of a bright line authority for FERC on their permitting, something similar to Sen. [Sheldon] Whitehouse’s SITE Act, which has 1000-MW bright line,” said Gramlich.

Sen. Whitehouse (D-R.I.) in the last Congress introduced the Streamlining Interstate Transmission of Electricity Act, which would give FERC new siting authority for large, interstate lines.

FERC and DOE currently split some backstop siting authority, but that process requires NEPA reviews at both agencies and can take a long time. The arrangement has been in place since 2005 and has never been used to successfully site a transmission line.

Sen. Kevin Cramer (R-N.D.) is a former state regulator who knows the transmission issues well and will likely be key to getting Republican support for any reforms in that area, Chatterjee said. But there is still a question of whether FERC would have the appetite to use that authority.

“I’ve heard both former Democratic and Republican commissioners say this: that even if FERC had enhanced authority in this area, I think they’d be reluctant to do it,” Chatterjee said. “It’s just easier said than done to roll over the states on something this sensitive and this complicated.”

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GCPA Names Brad Jones as Power Star Honoree

The Gulf Coast Power Association (GCPA) named former interim ERCOT CEO Brad Jones as the 2023 recipient of its Pat Wood Power Star Award in recognition of his significant contributions toward the advancement of Texas’ competitive energy markets, the organization said Tuesday.

Jones has been credited with righting the ERCOT ship after the deadly February 2021 winter storm that nearly brought the Texas grid to its knees and killed more than 200 state residents during the ensuing dayslong power outages. Coming out of retirement, he led the grid operator’s implementation of several legislative changes and leaned on a package of 60 initiatives designed to improve the Texas Interconnection’s reliability and regaining the public’s trust. (See ERCOT Board Chooses Jones as Interim CEO.)

Asked by legislative leaders to come out of retirement and lead ERCOT after the storm, Jones returned to his couch last October after 18 months. He received awards from Texas’ governor, both of the state legislature’s houses and the Public Utility Commission.

“All Texans owe Brad an enormous debt of gratitude for stepping up during a time of unprecedented challenge and urgency,” PUC Chair Peter Lake said in a statement. “His steady hand and deep experience in grid operations were critical in providing the clear leadership necessary to move ERCOT forward. … Because of Brad’s selfless and tireless efforts, the Texas grid is more reliable than it’s ever been to the benefit of Texans today and for generations to come.”

Jones is “not shy about doing tough, necessary things for improvement. … His confidence in the future of the grid and of ERCOT was contagious,” said Paul Foster, chair of ERCOT’s Board of Directors. “Brad left ERCOT in much better shape, both economically and in reliability.”

The award is named after former FERC and PUC Chair Pat Wood III, the first honoree. Winners are selected by the GCPA’s board of directors; Wood will present the award to Jones during the GCPA’s annual spring conference April 18-19 in Houston.

“I have long been a Brad Jones fanboy,” Wood said. “He is genuine. He is smart. He is decisive. His passion and optimism are matched only by his competence and leadership. His parents raised him right. What a gift he has been to Texas and to our industry.”

Jones has more than 30 years of experience in the industry. He oversaw TXU’s (now Vistra) development of the 1.8-GW Oak Grove facility and represented the company on Wall Street during a volatile time in TXU’s history.

He left TXU to become ERCOT’s COO, leaving the state only to serve as NYISO’s CEO in 2015. He abruptly returned to Texas to retire in 2018. (See Brad Jones out at NYISO.)

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California Governor Seeks Central Procurement Authority

The office of California Gov. Gavin Newsom has proposed legislation that would establish a central procurement authority to ensure the state has sufficient electricity resources to avoid shortfalls as it struggles with extreme heat, tight supply and a changing resource mix across the West.

The proposal is contained in budget trailer bill language that follow’s Newsom’s fiscal year 2023/24 budget released in January. No lawmaker has yet signed on to carry the bill in the current legislative session.

The governor’s proposal would give the California Public Utilities Commission (CPUC) the option to name the state Department of Water Resources (DWR) or an investor-owned utility to procure energy for the state’s load-serving entities, including public utilities and community choice aggregators.

“For California to achieve its long-term greenhouse gas emission reduction goals, while maintaining a reliable electrical system and providing customers with greater choice in electricity retail providers, the state must establish a new central procurement function within the [DWR] that enables the development of a more diverse portfolio of renewable and zero-carbon energy resources,” it says.

The state has directed investor-owned utilities to procure for other LSEs in the past, but DWR has not performed that function. The governor’s legislative language would authorize it to do so if called upon by the CPUC.

The department’s State Water Project is a major producer of electricity through its hydroelectric projects and the state’s single largest consumer of electricity, which it uses to operate pumping plants that deliver water throughout the state.

Under the proposal, DWR could issue bonds and recover costs through ratepayer charges approved by the CPUC as long as the charges “[do] not unreasonably increase costs to customers … compared with the procurement of diverse clean energy resources by an electrical corporation.”

DWR would have to conduct a competitive procurement process and “prioritize investments that do not compete with the procurement of diverse clean energy resources already planned for development and disclosed by load-serving entities or local publicly owned electric utilities.”

LAO Report

In a March 10 report on the governor’s proposal, the state Legislative Analyst’s Office says that “according to the administration, the DWR procurement is intended to be for long lead‑time resources such as offshore wind, geothermal, and long duration storage. The proposed statutory changes, however, do not explicitly limit this procurement option to those types of resources.”

“DWR would utilize its new Strategic Reliability Reserve office and staff to manage the procurement,” the LAO report says.

The department administers the state’s Electricity Supply Strategic Reliability Reserve Program (ESSRRP), a $5.2 billion fund sought by Newsom in last year’s budget and enacted in June to pay for new generation and storage, to keep older natural gas plants online and to provide emergency backup generation through DWR. (See California to Pass Sweeping Energy Policy Changes.)

California has experienced blackouts and near misses the past three summers as it tries to shift its resource mix from fossil fuels to renewable power amid extreme heat, wildfires, drought and strained supply in neighboring states.

Another component of the governor’s legislative proposal is a requirement that load-serving entities pay for failing to obtain sufficient resources to meet demand by making payments to the strategic reserve fund. The move is intended to “discourage LSEs from over-relying” on the ESSRRP, the report says.

“The state would assess a payment if an LSE does not meet its reliability obligations in a month when the state had to access the ESSRRP,” it says. “Specifically, the payment would be based on a calculation that factors in the cost of the energy resource provided by the ESSRRP and the LSE’s deficiency in meeting its monthly resource adequacy or planning reserve requirements. The payments would be calculated by the CPUC and the California Energy Commission.”

The payments would be in addition to fines for resource inadequacy imposed by the CPUC.

Questions for Lawmakers

The LAO report proposes questions for lawmakers to consider when weighing the governor’s proposal, including the potential impact on ratepayers of adding DWR procurement costs to their already-high electricity bills.

It also questions the market effects of central procurement by DWR.

“The current market for energy resources is strained, with a large number of LSEs competing for a relatively small pool of projects that often will take years to develop,” it says. “How the entrance of DWR — a large, well‑resourced entity with the backing of the state — would influence the market for new energy resources is unclear.”

The report also questions whether the state needs new central procurement authority or whether current resource planning processes and the ability of IOUs to procure for other LSEs is enough.

Having DWR in charge of long-lead time resources poses risks, the report says.

“The administration has expressed concerns that LSEs might be hesitant to procure large, long‑lead time resources because of their high cost and risk as newer technologies,” it says. “The Governor’s proposal to have the state pursue procuring these resources instead essentially shifts this risk from the privately owned utilities (and their investors) to ratepayers and taxpayers. While this could help facilitate the development of these important resources, additional information is needed about the types of risks involved and their magnitude for the Legislature to determine if they are worth the potential benefits.”

Finally, the LAO asks whether the energy policy changes should be considered as part of the budget process.

“The Governor’s proposals represent significant policy changes for the state, and they do not have a particularly strong nexus with the budget,” the report says. “The Legislature will want to consider the most appropriate venue for discussing and deliberating these proposed changes. For example, the Legislature could consider these proposals through the policy process, rather than as part of the budget process.”

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Maryland Bill Would Require Utilities to Report Votes at PJM

A bill passed by the Maryland House of Delegates last week would require that utilities submit annual reports detailing their votes at PJM, including an explanation of how each vote benefits the public interest.

Del. Lorig Charkoudian, the sponsor of HB1186, said the bill would provide needed insight for legislators into the decision-making at PJM and aid them in determining if utilities operating in the state are acting contrary to clean energy policy goals and ratepayers’ interests. The General Assembly holds the authority to determine the state’s generation mix targets and is expected to protect consumers, she said, but its legislation is often undermined by decisions made by PJM stakeholders.

The House passed the bill 100-35 on Saturday, advancing it to the Senate Education, Energy and the Environment Committee.

“We’re in this position where sometimes I call PJM a shadow government because you have an LLC that is theoretically … neutral on policy, but in reality the decisions they make every day … absolutely make or break our climate change rules,” Charkoudian told RTO Insider.

Most of the state’s utilities are voting members of PJM:

  • the four investor-owned utilities: Exelon’s (NASDAQ:EXC) Delmarva Power and Light, Potomac Electric Power Co. (Pepco) and Baltimore Gas and Electric; and FirstEnergy’s (NYSE:FE) Potomac Edison;
  • the municipal utilities for Berlin, Easton, Hagerstown, Thurmont and Williamsport; and
  • the Southern Maryland Electric Cooperative (SMECO).

Two rural electric co-ops — A&N Electric and Choptank Electric — are members of Virginia-based Old Dominion Electric Cooperative, itself a PJM member but presumably would not be subject to the bill. According to the fiscal and policy note for the bill released by the Department of Legislative Services, “the companies can likely submit the required voting record information with existing resources. If not, local expenditures increase minimally. Revenues are not affected.”

Charkoudian said that lawmakers’ attempts to understand how local utilities are voting on matters affecting the state are stymied by PJM rules, which do not make public the votes individual entities make at the lower committees and task forces. Though votes at the Members Committee are public, Charkoudian said initiatives benefiting the state may be blocked before they reach that level without legislators being able to understand why.

In particular, she pointed to the parameters defining the variable resource requirement curve as influencing the type of generation that is likely to be built in the state, while backlogs in the interconnection queue have limited the ability for renewable generation to be developed.

“I don’t think this bill solves the problem, but it leads to a better … conversation about what we can do to ensure that PJM is reinforcing what we’re trying to do,” Charkoudian said.

PJM spokesperson Jeff Shields said that all committees where votes are taken are open to the public and media.

“PJM has not been asked to opine on this legislation,” Shields said. “All committees where votes are taken are open to the public and to the media. Votes of PJM’s most senior committee, the Members Committee, are public, and a voting report is posted showing individual votes.”

Stakeholder Comments

The Maryland Energy Administration, Office of People’s Counsel and the state’s chapter of the Sierra Club submitted favorable testimony to the House Economic Matters Committee. They argued that the bill would provide transparency without interfering with utilities’ ability to cast votes on issues before PJM.

“Public service companies are provided with state-granted monopolies in order to perform important public functions and are required to operate ‘in the interest of the public,’” the OPC said. “At the same time, however, many public service companies are private companies with fiduciary obligations to earn profits for their investors. Unless effectively regulated, public service company votes at PJM can result in serious misalignments with the public interest.”

The IOUs and SMECO all submitted testimony in opposition to the bill, which they say would stifle debate and create significant administrative burden without providing much benefit to legislators.

Exelon Vice President of Federal Regulatory Affairs Sharon Midgley, a regular attendee of PJM committee meetings, said the company supports transparency and is willing to engage with policymakers and regulators, but it believes the legislation in its current form misses the mark. She said the requirement that the public benefit rationale for each vote be described is vague, with there being many competing issues of public interest, including affordability, security and the environment.

For votes in the lower committees, Midgley said there is currently no framework for logging individual votes — particularly those taken by voice or acclamation, which allow an item to pass if there are no objections. Requiring those votes to be cast would add a responsibility to stakeholders based in other states and sectors.

Midgley also pointed to PJM’s Manual 34, which states that all matters before stakeholders are considered preliminary until a vote is taken by the MC.

“All participants understand that documents, reports, slideshows and other written material used at all until final Member Committee and/or PJM board approval are intended to be works in progress and to encourage dialogue, discussion, debate and, preferably, movement towards consensus,” the manual says. “Therefore, such work products should be treated in the spirit to which they are intended; that is, not as final or complete documents, nor the final position or view of a participant.”

In its comments, FirstEnergy noted that the votes at the Markets and Reliability Committee and MC consolidate all affiliates together so each corporate entity has a single vote, which it said often means that its vote on an issue may not be driven by issues in any one state.

“Because of this consolidated vote, there are times when FirstEnergy’s ‘vote’ is not driven by Potomac Edison or Maryland considerations. Compelling utilities to report and explain their vote in these situations just does not make sense,” said the company, which has subsidiaries in Ohio, Pennsylvania, West Virginia and New Jersey.

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MISO Issued Show-cause on Seasonal Capacity Auction Values

FERC on Friday issued MISO a show-cause order saying the grid operator appears to be violating its tariff by failing to publish a systemwide unforced capacity ratio ahead of its first four-season capacity auction in a few weeks.

The commission said although MISO has updated individual units’ ratios of unforced capacity to intermediate seasonal-accredited capacity, it hasn’t updated the systemwide ratio (EL23-46). It ordered MISO within seven days to either show cause as to why it would not have to update the ratio or explain how it will revise the ratio before it conducts its seasonal capacity auctions for the 2023/24 planning year beginning June 1.

Commissioner Mark Christie said FERC’s order on MISO’s missing ratio is more proof that grid operators’ capacity markets are convoluted and dysfunctional.  

The ratios are a new concept added alongside MISO’s seasonal, availability-based accreditation style. (See FERC Affirms MISO’s Seasonal Auctions, Accreditation.) MISO and market participants use the ratios to validate capacity values. The RTO said it intended it to be “an annual calculation posted well in advance of each PRA in order to provide market participants certainty as they plan to meet planning reserve margin requirements.”

In an early March filing to FERC to explain issues surrounding the systemwide ratio, MISO said its tariff was silent on the matter of when the ratio should be published in advance of its four-season Planning Resource Auction (PRA) conducted in April. The RTO said it published the annual ratio on Dec. 15, but found that its software registered some previously approved and exempt generator outages over the last three years as illegitimate, thus lowering expected capacity.

While MISO said it issued individual corrections for affected generators, it said it could not update the systemwide ratio again in time for the 2023/24 PRA.

Late last month, Director of Resource Adequacy Coordination Zakaria Joundi said MISO’s filing on the ratio is “an attempt to share and communicate with FERC what we’ve been up to” and signal to FERC that “potential process changes” may be needed moving onto the next planning year.

At the time, Joundi said MISO was in the “final stretch” before running its first seasonal auctions.

FERC said that while it was sympathetic to the challenges MISO faced in pulling off its first seasonal auction, the RTO was nonetheless violating its tariff by not releasing an updated ratio.

“We understand that this is the first year in which MISO is transitioning to its seasonal capacity construct and that errors may occur in executing complex calculations,” FERC said. “In this instance, MISO identified an error in how outage exemptions were calculated and corrected this error by updating the [seasonal accredited capacity] values of affected resources.  However, the … tariff does not afford MISO with discretion to decide whether to update the ratio; rather, MISO must calculate the ratio consistent with the formula set forth in the tariff.”

In an email to RTO Insider, MISO said it was reviewing FERC’s order and will submit a formal response by March 24.

Christie Criticizes Capacity Markets 

Christie seized on the order as further evidence that grid operators’ capacity markets are plagued by complicated rules.

He said MISO’s seasonal capacity construct is “daunting[ly] complex,” pointing out that the seasonal accreditation values assigned to some thermal resources in the ratio aren’t even “directly” used as their accredited capacity.

“Given these Rube Goldberg machinations, it is perhaps no wonder that something went awry in MISO’s accreditation calculations — though, in fairness, MISO attributes the incorrect calculations to an error by its Control Room Operations Window (CROW) software program in assessing the timeliness of outage submissions (which I suppose represents a serving of CROW),” Christie wrote in a concurrence to the order.

“This proceeding shows once again that these administrative constructs known as capacity markets are characterized by such hopeless complexity and impenetrable opacity that they represent the classic example of a game that only insiders can play and win,” Christie continued. “The interest groups that have the time and resources to navigate this labyrinth can and will make sure their interests are protected or at least advocated well. Whether the public interest is or even can be protected in this insiders’ game is increasingly a salient question.”

Speaking this month at the Gulf Coast Power Association’s MISO-SPP conference, MISO Independent Market Monitor David Patton predicted MISO will gather “lessons learned” from the April auctions and results. He said MISO moved too hastily to design and seek approval for its seasonal market.

“With the speed at which they implemented it, there’s going to be some things that are going to be not quite right,” Patton said.