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November 6, 2024

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Inslee Plugs Washington Buildings Bills at Forum with Gore, McCarthy

Gov. Jay Inslee on Wednesday urged constituents to lobby Washington legislators to drum up extra votes for two bills addressing the carbon footprints of buildings in the state.

Inslee was speaking at a virtual town hall that also featured former Vice President Al Gore and White House National Climate Adviser Gina McCarthy. The governor told watchers to call their legislators: “I need one vote each on a couple of bills right now.”

While it was not apparent how many people tuned in to the town hall, a moderator said that roughly 500 questions were submitted for Inslee, Gore and McCarthy. The meeting lasted about 50 minutes and only four questions were presented.

Inslee was stumping for Senate Bill 5722 and House Bill 1770.

Sponsored by Sen. Joe Nguyen (D), SB 5722 calls for the state’s Department of Commerce to set draft standards to trim carbon for buildings ranging from 20,000 to 50,000 square feet by Dec. 1, 2023. A 2019 law already addresses the carbon footprints of buildings that are greater than 50,000 square feet, which number about 10,000 in the state. (See Rent Provision Sparks Pushback on Wash. Buildings GHG Bill.)

Nguyen’s bill has already passed the Senate along party lines but appears to lack support from some Democrats among the party’s 57-41 majority in the House.

HB 1770 would require new residential and nonresidential buildings to reduce their energy consumption to 70% below the 2006 state energy code baseline by 2031 and 80% below the baseline by 2034 — as well as be equipped for solar panel placement. Introduced by Rep. Davina Duerr (D), the bill passed the House 51-47, with six Democrats voting against it.

Both bills are part of Inslee’s climate change legislative agenda for the 2022 session. (See Inslee Unveils $626M Climate Legislation Wish List.)

Most of Wednesday’s town hall functioned as a pep talk session by Inslee, Gore and McCarthy.

“We’re in the early stages of a sustainability revolution,” Gore said, later adding, “I think we’re at the political tipping point on the climate crisis.”

McCarthy and Inslee said states are better suited than the federal government to try new approaches to combat global warming. “We can advance the ball where the federal government cannot. We can do things that are unique to our circumstances,” Inslee said.

Gore contended that global warming would halt three to five years after the world reaches carbon neutrality. “It’s like a switch that can be flipped,” he said. The former vice president did not elaborate on any studies that backed up his contention.

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Powhatan Energy to Declare Bankruptcy

Powhatan Energy Fund will file for Chapter 7 bankruptcy, a company representative said Thursday, effectively ending more than a decade of litigation and legal moves with FERC over a high-profile market manipulation case in PJM.

In an email to RTO Insider, Powhatan co-founder Kevin Gates said the Pennsylvania-based money management firm that once participated in PJM markets “does not have enough money to continue to litigate with the FERC over simple spread trades that took place almost 12 years ago” and decided to declare bankruptcy, unwinding the firm. The bankruptcy documents were not yet filed as of Thursday evening.

In 2015, FERC ordered Powhatan and one of its traders to to pay $34.5 million in penalties and disgorged profits. The commission accepted the Office of Enforcement’s findings that the company and trader Houlihan “Alan” Chen violated anti-manipulation rules by making riskless back-to-back up-to-congestion (UTC) trades to profit on line-loss rebates (IN15-3). (See FERC Orders Gates, Powhatan to Pay $34.5 Million; Next Stop, Federal Court?)

In July of that year, the commission filed suit in the U.S. District Court for the Eastern District of Virginia to request an order affirming FERC’s orders assessing civil penalties, leading to several years of motions, countermotions and orders. Powhatan chronicled the legal back-and-forth on its website.

“We’ve already paid our attorneys many millions of dollars and simply do not have another million dollars to continue to defend ourselves from FERC’s meritless assault,” Kevin Gates said in the email.

The Case

Chen, who conducted the trades, began trading UTCs in 2007, after leaving Merrill Lynch, where FERC said he studied UTCs as a tool for physical and financial transactions.

Initially, Chen’s trades were based on market fundamentals and models he developed using a “careful, low risk approach of what he called ‘directional bets,’” FERC said. Most bids were under 100 MW, and his profitability depended on favorable price spreads.

In October 2009, after discovering he was receiving line-loss rebates, Chen switched to a strategy designed to capture increased volumes of rebates, FERC said.

His strategy changed again after suffering a $176,000 loss on May 30, 2010, when one leg of a trade saw an unexpected price spike. Following the loss, Chen switched to a round-trip trading strategy between the same two points (A-to-B, B-to-A) that FERC said made the underlying trades effectively riskless.

FERC sought penalties only for what it called the “manipulation period,” from June 1 to August 3, 2010, when Chen stopped the trading after receiving a warning from PJM Market Monitor Joe Bowring.

FERC began investigating Chen and Powhatan, with Chen and the Gates brothers responding to FERC data requests and sitting for depositions while their lawyers sparred with FERC attorneys and provided affidavits from an economist and an attorney supporting their defense.

In October, FERC issued a consent agreement with Chen, with Chen agreeing to disgorge $600,000 to PJM.

Gates’ Response

In 2015, Kevin Gates told RTO Insider that he rejected FERC’s offer to enter settlement discussions after he, his brother and Chen had responded to data requests and sat for depositions while their lawyers continued to spar with the agency. In a Feb. 18 email, Gates said the company subsequently attended “like three court-mandated settlement discussions,” none of which were productive.

The company did propose a settlement with FERC last June, which the commission turned down.

“Even though FERC’s investigation began 4,201 days ago, we weren’t even able to complete discovery as they threw up every possible roadblock they could think of to drag this case out and bleed us of resources,” Gates said.

Gates said FERC “essentially has an unlimited budget” to litigate cases and is “happy to spend other people’s money to promote their own agenda.” He said FERC’s “modus operandi” is to use litigation and their power to “extract massive, headline-grabbing settlements” from individuals and companies that don’t want to engage in their defense in court.

“We suspect this will make the FERC happy,” Kevin Gates wrote. “They have never sought the pursuit of justice, but rather used the administrative process and the legal system as a cudgel with which to bully us. FERC is part of the reason that citizens are losing faith in our government and a demonstration that bureaucrats sometimes deserve their worst stereotypes.”

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Rate Hikes Prompt Concern in California

The California Public Utilities Commission is questioning how much more ratepayers can stomach after approving back-to-back $1 billion rate increases for Pacific Gas and Electric and substantial rate hikes for the state’s two other large investor-owned utilities.

The increases were mostly driven by high natural gas prices and FERC transmission-rate requirements, among other factors, commissioners said.

“We’ve seen significant rate increases in each of the three major investor-owned utility service areas in the last few months,” Commissioner Darcie Houck said Feb. 10 before “reluctantly” approving the second major rate hike to hit PG&E customers since January. “Ratepayers have justifiably voiced concerns and objections to these rate increases.”

“We as a commission must carefully consider what and whether ratepayers can withstand regarding further rate increases, and we need to explore innovative methods to help curb rate increases and to protect the most vulnerable Californians,” Houck said.

The CPUC has scheduled an en banc hearing on utility rates for Feb. 28 and March 1 intended to examine proposals to control costs and mitigate rates. The two-day session follows a similar hearing last year attended by CAISO governors, state energy commissioners and legislative leaders, all concerned with spiraling costs. (See Calif. Worries High Rates Could Hurt Climate Efforts.)

The increases that took effect in January and others that start in March will worsen the situation, CPUC commissioners said.

In PG&E’s case, the CPUC approved a $769 million increase to the utility’s Energy Resource Recovery Account (ERRA) and a $358 million addition for ERRA under-collection in 2021, adding more than $1.1 billion to PG&E’s 2022 revenue requirement.

It will result in a nearly 11% rate hike for residential customers, averaging $16.37 per month, and larger increases for commercial and industrial users.

The changes, approved Feb. 10, take effect March 1.

“An industry and worldwide increase in natural gas commodity prices in 2021 and into 2022 has increased costs and is a main contributor to the increase approved today, which allows PG&E to recover from ratepayers the costs PG&E incurred to purchase power for customers in 2021 and forecasted costs for power in 2022,” the CPUC said in a statement following the decision.

The CPUC said it could re-examine the decision later this year if gas prices fall.

The new increase came on top of an 8% rate hike that took effect Jan. 1, averaging $11.29/month for PG&E residential customers.

The main drivers were a $671 million increase in FERC-approved transmission rates and a $284 million increase in PG&E’s general rate case for program costs, the CPUC said. The commission also granted PG&E $173 million in additional revenue to cover losses from unpaid bills during the pandemic and additional funds for wildfire insurance premiums.

“Ratepayers in PG&E territory have had a particularly difficult year and are questioning these increases along with safety concerns, given the many catastrophic wildfires suffered over the years,” ignited by PG&E equipment, Houck said.

“In addition to energy fuel costs rising, we are also facing challenges to grid infrastructure upgrades and ensuring sufficient resources to meet our clean energy goals,” she said. “All of these items require investment. All this said, ratepayers are not an unlimited source of funds to cover any and all costs.”

SCE, SDG&E

For Southern California Edison, the CPUC approved a January rate increase of 2.9%, working out to an average monthly bump of $3.99 in residential bills.

The causes included the addition of $385 million to SCE’s general rate case for wildfire mitigation work, including vegetation management, installing covered conductor, and upgrades to SCE’s transmission and distribution grid. The CPUC also authorized an increase of $238 million for transmission capital, operation and maintenance costs in 2022, based on prior approval from FERC.

SCE’s purchase of $1 billion in liability insurance, as required by state law, contributed to the rate hike, the CPUC said.

CPUC-approved increases that take effect in March reflect high natural gas prices, the recovery of $401 million in wildfire prevention costs and $77 million for unpaid bills during the pandemic.

In December, the CPUC approved $1.2 billion in rate recovery for SCE’s procurement of 536 MW of energy storage for summer reliability. About $85 million of that will be collected in 2022, the CPUC said.

Starting in March, SCE residential customers can expect an additional 7.7% bill increase, adding $11.48 a month on average.

Between the January and March rate hikes, SCE residential customers will be paying nearly 11% more for electricity this year, or about an extra $12.50 per month.

San Diego Gas and Electric residential bills rose by 11.4% in January because of a $273.5 million boost to the utility’s revenue requirement, mostly based on high gas prices, and $38.5 million for transmission costs authorized by FERC, the CPUC said. Insurance premiums of $65 million also contributed to the higher rates.

CPUC President Alice Reynolds and commissioners Genevieve Shiroma and Clifford Rechtschaffen also expressed concern about rising electricity costs.

Rechtschaffen said the CPUC must continue working on the issue, including at the upcoming en banc hearing.

“We’re looking for innovative ideas to improve affordability, especially for low- and moderate-income customers,” Rechtschaffen said. “We really need to dig deeply into some of these solutions.”

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NYISO Business Issues Committee Briefs: Feb. 16, 2022

Updates External ICAP Rights

The NYISO Business Issues Committee on Wednesday approved revisions to the Installed Capacity (ICAP) Manual that update capacity import limits for the 2022/23 capability year.

The ISO completed deliverability testing and determined that all of the import rights are deliverable, said Pallavi Jain, senior ICAP market operations engineer. The update is part of an annual process to determine the maximum amount of import capacity allowed from neighboring control areas.

NYISO performed simulations to determine capacity imports allowed without violating the loss-of-load expectation (LOLE), one day in 10 years. The ties excluded were interface facilities with unforced capacity deliverability rights; controllable lines from PJM into the New York Control Area; and the NUSCO 1385 Northport-Norwalk Harbor Cable between Long Island and Connecticut.

Concerns on Response to FERC

One stakeholder brought up the issue of NYISO responding to FERC’s Feb. 9 deficiency letter regarding the ISO’s January filing on its comprehensive mitigation review and capacity accreditation methodology (ER22-772).

Among other issues, FERC asked the ISO to define “marginal reliability contribution” and to “explain in detail how NYISO would calculate the marginal reliability contribution of a capacity accreditation resource class using a ‘system [effective load-carrying capability] methodology.’”

“If the NYISO is responsive to FERC’s questions, it will necessarily be prejudging a number of the issues that we were all to have collectively discussed over the next few months, and that is a concern to us,” said Aaron Breidenbaugh, director of regulatory affairs at energy management company Centrica Business Solutions.

“As you know, we were not supportive of joining the two issues [buyer-side mitigation and capacity accreditation] at FERC, nor are we supportive of the marginal accreditation approach,” Breidenbaugh said. “We think there’s a lot of questions that remain to be answered, and obviously there’s a difference of opinion on that given what was filed at FERC.”

If the ISO feels pressured to answer FERC before stakeholders can discuss the issues, “it seems like in doing so they’re likely to run afoul of the commitments made to the market participants that those issues be resolved in the stakeholder process,” he said.

NYISO is still very focused on working with stakeholders on the many questions regarding the techniques used for calculating capacity accreditation factors, said Michael DeSocio, director of market design.

“We’re going to continue full speed ahead working with you all on these issues making sure everyone understands how the calculations will work and understands the details that go into these calculations,” DeSocio said. “That conversation will actually start next week, and we’ll continue to move the ball forward on that as quickly as we can.”

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Split FERC Updates Policies on Gas Infrastructure Applications

FERC voted 3-2 Thursday to update its 1999 policy statement on natural gas infrastructure certificates (PL18-1) and released guidance on how it will evaluate the impacts of projects’ greenhouse gas emissions in its environmental analyses (PL21-3).

The updated policy statement concludes an effort begun in late 2017 under Chair Kevin McIntyre that languished under successor Neil Chatterjee before being restarted almost exactly a year ago by Richard Glick. (See Glick Hits ‘Refresh’ at 1st FERC Open Meeting.)

Combined with the new guidance on GHG emissions, however, it begins an era in which the commission will more closely scrutinize gas projects, including the evidence for their need and their emissions’ impacts on global climate change.

Glick and his fellow Democratic commissioners, Allison Clements and Willie Phillips, said the statements would provide more certainty for pipeline developers. Glick in particular pointed to numerous projects that have been remanded or vacated by federal courts because of insufficient environmental analyses by regulators including FERC.

“In my opinion, the courts have been clear: We have an obligation under both [the National Environmental Policy Act] and the Natural Gas Act to consider the impact of reasonably foreseeable greenhouse gas emissions, and if we were to continue to turn a blind eye to climate change and greenhouse gas emissions, we would simply be adding to the legal uncertainty of these orders approving a project,” Glick said during the commission’s monthly open meeting Thursday.

But Republican Commissioners James Danly and Mark Christie blasted the new policies, saying that FERC was essentially rewriting the Natural Gas Act and attempting to prevent more gas pipelines from going into service.

“I happen to agree that reducing carbon emissions that impact the climate is a compelling policy goal,” Christie said. “But the commission does not have an open-ended license under the U.S. Constitution or the NGA to address climate change or any other problem the majority may wish to address. … Here’s an inconvenient truth: If Congress wants to change the commission’s mission under the NGA, it has that power; FERC does not.”

More than Precedent Agreements Required

Among the most significant changes in the updated policy statement is that FERC will no longer solely rely on precedent agreements as evidence of need for the project.

Such agreements are private contracts between project developers and prospective customers of the project’s gas. But the courts have reprimanded the commission’s reliance on them as indicators of need because they are often between affiliates: developers essentially selling pipeline capacity to themselves.

“Although precedent agreements remain important evidence of need, precedent agreements alone often may not be sufficient to establish need for a project,” FERC staff said in a presentation to commissioners. “The updated policy statement further encourages applicants to provide specific information detailing how the gas to be transported by a proposed project would ultimately be used, why the project is needed to serve that use and the expected utilization rate of the project.”

The update also lists four major public interests that the commission will consider in determining whether a projects’ benefits outweigh its adverse impacts: those of the applicant’s existing customers; those of existing pipelines and their captive customers; the environment; and those of landowners and surrounding communities, including environmental justice communities.

A FERC fact sheet states that “the commission’s consideration of landowner impacts will be based upon robust early engagement with all interested landowners and continued evaluation of input from landowners throughout any given proceeding” and that it will take into account “what a pipeline applicant already has done to acquire lands through good-faith negotiation, as well as an applicant’s plans to minimize the use of eminent domain upon receiving a certificate.”

Impact on Climate Change

FERC said its new policy for analyzing climate impact is considered “interim”; it asked for public comment by April 4.

Under the new policy, FERC will presume that projects with estimated GHG emissions of at least 100,000 metric tons of carbon dioxide equivalent per year will have a significant impact on climate change — requiring that the commission conduct an environmental impact statement — unless the developer can rebut that presumption with evidence.

The commission also stamped a policy long sought by Democrats: It will consider all “reasonably foreseeable” GHG emissions that would result from the project, including those resulting from the downstream use of the gas being transported.

Republican Dissent

Danly’s and Christie’s statements during the open meeting criticized both policy statements collectively; their dissents, along with the statements themselves, had not been published as of press time.

Both Republicans criticized the statements as vague and ambiguous and said the majority was overstepping the commission’s legal authority.

“It is very difficult for us to achieve the objectives of the Natural Gas Act, which is to encourage the orderly development of natural gas infrastructure … when we are adopting policies that are either vague or make it difficult to rationally allocate capital,” Danly said. “I think that it is inevitable that these policy statements are going to chill investments, and that they are going to do so when we have areas of the country facing … constraints in gas supply. …

“It is troubling to me that implicit in these two policy statements is what appears to be a displacement of congressional declaration of the importance of natural gas with the commission’s seemingly implicit declaration instead that natural gas is harmful or negative and needs to be discouraged as much as possible.”

The Republicans also lambasted their colleagues for implementing the interim policy immediately, despite being subject to revision, not just on new applications, but on those pending as well.

“Changing the rules in the middle of the game violates any serious principle of due process, regulatory certainty and just basic fairness,” Christie said.

Sabal Trail

Speaking to reporters by conference call after the meeting, Glick said Danly and Christie spent much of their dissents essentially disagreeing with three of the D.C. Circuit Court of Appeals’ rulings, especially the 2017 Sierra Club v. FERC ruling on the Sabal Trail pipeline.

It was this case that sparked the ongoing dispute over the commission’s analysis of gas project’s GHG emissions. The issues of whether and how FERC should or even can analyze a project’s downstream emissions has been debated ever since. During his time in the minority, Glick repeatedly insisted that the Republican majority was ignoring the court’s directive for FERC to consider the impact of a project’s emissions on climate change when evaluating it. (See EBA Panelists Debate Role of FERC in Regulating Carbon.)

In his dissent, Danly called the decision an “outlier,” arguing that “it is very much in tension with prevailing Supreme Court precedent.”

“We should not rest too much weight upon Sabal Trail,” Danly wrote. “Not only is the holding narrower than the majority seems to believe and was roundly criticized by the accompanying dissent, its reasoning has since been called into question by another appellate court, and I expect it will soon be challenged in the Supreme Court.”

In his statement during the meeting, Christie argued that there is no explicit court directive, noting that “since Sabal Trail, there have been more recent opinions from the U.S. Supreme Court itself reasserting its major-questions doctrine.” Also known as “the major rules doctrine,” it holds that “major questions of public policy” are reserved for Congress, not the executive or judicial branches, to answer. It came back to the fore of the court with King v. Burwell, which ruled on provisions of the Patient Protection and Affordable Care Act.

The doctrine is a check on Chevron deference, in which the courts defer to an executive agency’s interpretation of a statute.

“Whether this commission can reject a certificate to build a natural gas facility, one that otherwise meets the criteria for approval under the Natural Gas Act, because of its alleged impact on global climate change, is clearly a major question of public policy,” Christie said. “I cannot think of a more important question of policy — not just energy policy, but economic policy and, yes, even national security policy.”

Glick countered that “it’s kind of the height of arrogance, I think, to say, ‘Well the court got it wrong, so I’m going to ignore the court.’” The major-questions doctrine is irrelevant, he argued, because Congress in the NGA has already directed FERC to consider whether the public benefits of a project outweigh its negative impacts.

Glick also said the prediction that the Supreme Court would overturn the D.C. Circuit is also irrelevant. The Republicans “may be right; I don’t know. … But in the meantime, we’re bound” by the current ruling, he said.

Temporary Spire Certificate Remains

The commission on Thursday also responded to arguments raised on rehearing of its December order issuing a temporary certificate to Spire STL Pipeline to allow it to continue operating (CP17-40-012).

In June, the D.C. Circuit ordered FERC to vacate its decision permitting the 65-mile natural gas pipeline, saying the commission had failed to follow its own rules on evidence of a need for the facility (20-1016).

Spire announced plans for the project in 2016, but when its “open season” failed to produce any shippers wanting the capacity, it signed an agreement with one of its affiliates for 87.5% of the line’s capacity. In granting the project a certificate of public convenience and necessity, FERC failed to consider “plausible evidence of self-dealing,” the court said. (See DC Circuit Slaps FERC on Pipeline GHG Analysis.)

On Dec. 3, however, the commission granted Spire a temporary certificate, finding that an “emergency” exists because if the pipeline were to cease operations, Spire’s Missouri affiliate would lose gas supply, “potentially impacting hundreds of thousands of homes and businesses during the winter heating season.”

Requests by the Environmental Defense Fund and others to rehear the Dec. 3 order were automatically rejected when the commission did not act on them within 30 days.

In Thursday’s order, the commission rejected the challengers’ request for a stay of the temporary certificate and responded to EDF’s request that it immediately address the self-dealing issue.

“While allegations of self-dealing must be taken seriously and merit additional consideration by the commission on remand of the certificate order, that issue is not relevant to the question addressed by the commission in this proceeding: whether to issue a temporary certificate in the heart of winter where the health and welfare of hundreds of thousands of customers is at stake,” FERC said.

Rich Heidorn Jr. contributed to this report.

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Enviros Want Faster Action on NJ Cargo-handling Emission Rules

Critics of new rules proposed by the New Jersey Department of Environmental Protection (DEP) to cut emissions from cargo-handling equipment at the state’s ports and rail terminals say the rules should be tougher, require faster action and be expanded to include warehouses.

Speakers at a Feb. 9 public hearing on the rules said that though they are a step in the right direction, they should require significant carbon reduction in the next two years, rather than the five years allowed for the conversion of some equipment to low-carbon emissions. They also said the DEP should mandate the use of electric cargo-handling equipment, rather than allowing cargo handlers to use low-emission diesel engines.

“Cleaning up emissions from cargo-handling equipment is an important” step, especially in areas with overburdened communities, said Jonathan Smith, an attorney for Earthjustice. “But we need to eliminate, and not just reduce, emissions from cargo-handling equipment.”

Representatives of the business community, including port and railroad terminal operators, said the rules could be too burdensome, hurt their competitive edge and disrupt emission-reduction efforts already underway.

The diverse response to the rules shows the challenge facing the state as it seeks to cut emissions and mandate expensive equipment upgrades at one of the state’s economic pillars, especially at the Port of New York and New Jersey. The challenge is heightened by the sensitivity over longtime environmental justice concerns in port areas.

The DEP’s proposed rules, which are based on similar rules enacted in California a decade ago, would require owners and operators of new and existing diesel-powered cargo-handling equipment to replace them with newer, less polluting models or install cleaner engines into existing equipment. The requirements cover a variety of vehicles, from the yard tractors that move containers around the terminal to mechanical equipment that can pick up, stack, and load and unload containers on and from trucks. (See NJ Targets Port Cargo-handling Emissions.)

Equipment that is more than 20 years old would be brought in line with the rules within two years, but equipment made since 2007, which is inherently cleaner, would need to be replaced or upgraded within five years. The rules aim to cut the emission of nitrogen oxides, which can damage an individual’s respiratory tract and cause breathing difficulties, and PM2.5, which has been associated with asthma, lung cancer and premature death.

The new equipment would need to meet EPA’s Tier 4 emissions standards, the agency’s toughest for emissions from diesel engines. EPA has estimated that the standard could cut PM2.5 and NOx by more than 90%.

Some environmentalists, who made up the bulk of the 30 or so speakers at the hearing, encouraged the DEP to also require warehouses to comply with the rules, arguing that they also use cargo-moving equipment and generate heavy emissions. Warehouse space in New Jersey is growing rapidly in the state, driven by rising cargo volumes through the ports and the dramatic increase in online commerce.

One speaker cited an April report compiled by the University of Redlands and the People’s Collective for Environmental Justice, which analyzed data on warehouse locations and air pollution in five South California counties. They found that the “top 10 communities in the South Coast Basin with the most warehouses also fall in the highest percentiles of toxic facilities.”

“Cleaning up all aspects of the goods-movement industry is the priority, not just pieces of it,” said Patricio Portillo, senior advocate with the Natural Resources Defense Council. “Excluding warehouses creates a potential risk that the old, highly polluting equipment could be shifted from ports to warehouses — a potentially perverse incentive that would run counter to the rules’ objectives.”

Megan Steele, communications coordinator for the New Jersey chapter of the Sierra Club, said the organization is “concerned that this rule does not go far enough, fast enough.” The rules should require a transition to zero-emissions cargo-handling equipment rather than allowing operators to shift to cleaner diesel engines, she said.

Yet Smith noted that the rules allow the use of 2010 model year engines, which are already old, and some could be in service for another five years before they would have to be replaced.

“We urge DEP to strengthen this rule and to continue to work toward zero-emissions equipment at these facilities,” he said.

Business Opposition

The rules are the latest effort by the administration of Gov. Phil Murphy to help the state cut its emissions by 50% below 2006 levels by 2030 and 80% by 2050. Other strategies include offering incentives and grants to encourage the purchase of electric vehicles, launching an extensive offshore wind program, and redesigning to state’s solar sector with a new incentive package and a new community solar program.

DEP rules aimed at cutting emissions from electricity generation and building heating systems also faced tough criticism at a public hearing on Feb. 1, when environmentalists and business interests criticized the rules, albeit for different reasons.

Ray Cantor, vice president for the New Jersey Business and Industry Association, last week told the DEP that his organization could not support the cargo-handling equipment rules because it did not agree that the state needed to act as fast as the department suggested.

“Artificial deadlines tend to result in bad decisions,” Cantor said. “Obviously, that’s what was happened here. Given the current state of the science, we do not believe that department has to act precipitously.” Excessive haste can push up the cost of responding, he said, adding that some port facilities have already introduced “very aggressive and comprehensive plans” to cut emissions, and those could be swept aside by the current rules.

Hurting the Competitive Edge

Michael Fesen, executive director for government relations at Norfolk Southern — one of three railroads, along with CSX and Conrail that operate in New Jersey — noted that his sector is already looking to cut emissions. He requested that the DEP allow an “open dialogue be constructed so that recognition of the ongoing efforts by the railroads and the yard operators to reduce emissions be recognized.”

He said the rules could negatively impact cargo-moving railyards, of which there are 50 in the state, in part by pushing up costs.

“Rail is typically a cheaper and more environmentally friendly alternative to truck, but we compete fiercely on price,” he said. “Increased cost of cargo-handling railyards will disfavor rail transportation overall throughout the United States.”

Robert Palaima, the recently retired president of Delaware River Stevedores, which handles cargo in the Port of Camden on the New Jersey side of the Delaware River, added that if the rules require extensive investment in port-handling equipment it could significantly impact the competitive position of some ports.

For example, converting the equipment at his former employer to meet the proposed DEP rules could cost $13 million, he said. “If the regulatory and cost environment became too burdensome, cargo can easily shift across the river to Pennsylvania, Delaware and Maryland,” he said.

Moreover, he added, the Port of Camden handles bulk and breakbulk cargo, which requires a more diverse set of equipment than that used by larger ports that move containers, such as the Port of New York and New Jersey, in the northern part of the state. And equipment used to move containers is used less intensely than that for moving bulk and breakbulk cargo, he said.

“This equipment isn’t used day in, day out [in] 24-hour operations,” he said. “So, I’m not sure that the emissions reduction will be what the department anticipates.”

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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.