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November 19, 2024

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Advocates Seek Pathway for Biofuels in New Connecticut Energy Strategy

Representatives of the biofuels industry asked Connecticut regulators Thursday to acknowledge liquid fuels in the state’s 2022 energy plan as a near-term option for reducing greenhouse gas emissions.

“Bioheat should be an established carbon-reducing pathway in the Comprehensive Energy Strategy (CES),” said Stephen Dodge, director of state regulatory affairs for Clean Fuels Alliance America (CFAA).

Electrification cannot “realistically” be the only path to emission reductions, when heating fuel blended with biodiesel can reduce GHGs “immediately,” he said during a Connecticut Department of Energy and Environmental Protection (DEEP) CES scoping meeting.

In its 2018 energy strategy update, DEEP credited biodiesel with improving air quality and reducing GHG emissions and called for further assessment of biodiesel market maturity. Displacing fossil fuels with biodiesel, the CES said, would require tracking feedstock sources, manufacturing, and amount sold and consumed.

DEEP accepted public comments at the scoping meeting as part of its proceeding to update the CES.

Dodge pointed to New York, Rhode Island and Massachusetts as examples of states with an established biodiesel pathway for reducing emissions. Massachusetts regulators recently ruled that electric ratepayer-funded subsidies for liquid fuel-fired home heating should remain in place, he said, after the alliance “successfully argued that bioheat fuel is a legitimate pathway to immediately begin reducing CO2 emissions.”

A study by Trinity Consultants, commissioned by CFAA, found that using 100% biodiesel as a heating oil replacement can reduce carcinogenic diesel particulate matter emissions by 86%.

At a 50% blend, biodiesel would have lower CO2 emissions than power coming from the transmission grid, said Chris Herb, president of the Connecticut Energy Marketers Association.

“Conversions to cold climate heat pumps … will only increase CO2 emissions” compared to biodiesel used for heating, he said.

Herb called for the 2022 CES update to “leverage” a law enacted last year that requires the blending of advanced biofuel with fuel oil starting at 5% in July and increasing to 50% by 2035. That law requires DEEP to consider in the CES how biofuel blends may contribute on a lifecycle basis to meeting the state’s GHG emission reduction targets and how a thermal portfolio standard could contribute to further reductions.

“Hundreds of thousands of homes in our state need little to no modifications … to start using a fuel that is cleaner and has the ability to displace fossil fuels today,” he said.

Advancing bioheat through the CES, he said, would relieve the current pressure to bring enough clean energy onto the electric system to accommodate the state’s efforts toward heat pump and electric vehicle adoption.

The Acadia Center, however, cautioned regulators against using alternative fuels in buildings.

“Numerous studies … have determined that there’s no cost-effective role for alternative fuels, such as renewable natural gas, biodiesel and green hydrogen, in buildings,” said Ben Butterworth, Acadia’s senior manager of climate and energy analysis.

Alternative fuels, he said, are “limited” and “expensive” and should be reserved for decarbonizing hard to electrify sectors, such as heavy industry, shipping and aviation.

Heather Deese, director of policy and regulatory affairs for Dandelion Energy, made the case for geothermal heat pumps, calling them a low-cost option for heating and cooling that significantly reduces GHG emissions.

“In order to provide for an equitable transition of the building stock, the CES should leverage the low ongoing operating costs of geothermal heat pumps,” Deese said, adding that the technology reduces household emissions by up to 80%.

Deese said the CES should set “ambitious” goals for transitioning to a clean energy economy and articulate “specific goals” for building electrification.

DEEP is accepting comments on the scope of the CES through March 3 and expects to publish the final strategy scope by April. The agency will offer additional stakeholder engagement opportunities throughout this year, and it anticipates publishing the final CES by the start of the 2023 legislative session, said Vicki Hackett, DEEP’s deputy commissioner for energy.

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NYPSC Applauds Central Hudson Storm Response

The New York Public Service Commission on Thursday lauded Central Hudson Gas and Electric and assisting utilities for their quick response to the early February blizzard that swept through its service area and cut power to more than 65,000 customers.

The Feb. 3-5 storm dumped up to 18 inches of snow across parts of the state, while freezing rain and cold temperatures lingered mainly in Ulster Duchess and Columbia counties in the mid-Hudson region, with reports of localized icing of one-half to three-quarters of an inch.

“This was the largest workforce Central Hudson has ever assembled in the over 100-year history of their company,” said Kevin Wisely, director of the state’s Office of Resilience and Emergency Preparedness. “The large contingent of workers moving into a concentrated area such as this does pose logistical and significant coordination challenges, particularly with housing and feeding the crews.”

Central Hudson was able to house the emergency crews and has contingency plans in place, if a future need arises, to house additional workers at local universities and colleges, as well as the ability to set up large-scale tented housing units to support an incoming workforce, Wisely said.

National Grid, New York State Electric and Gas, and the Orange and Rockland utilities all provided mutual assistance to Central Hudson.

“Kudos to the utilities for working so well together, but also frankly it was really nice to see that we didn’t have the administration calling for an investigation while the storm was still happening,” Commissioner Diane X. Burman said.

The winter storm once again highlighted the need for utilities to continually reassess infrastructure vulnerabilities across their service territories to determine appropriate storm-hardening and resiliency projects to mitigate potential weather risks and adapt infrastructure to weather extremes, Wisely said.

OKs Enviro Certificate for Tx Line to NYC

The commission on its consent agenda approved a certificate of environmental compatibility and public need for the 1,250-MW Champlain Hudson Power Express (CHPE) developed by Transmission Developers Inc. and Hydro-Québec, as well as a petition for flexible financing practices (10-T-0139 and 20-E-0598).

The PSC will soon rule on a state petition to buy power from two new transmission lines being built to bring more than 2.5 GW of renewable energy into New York City, including the CHPE and the entirely in-state Clean Path NY project (15-E-0302).

Burman cast the lone “no” votes on both measures, saying that the commission should be looking at the transmission projects “more holistically” and that the requested flexibility in the financing arrangements is too lax.

“It’s requesting flexibility to modify without prior commission approval the identity of the financing entities, payment terms and the amount financed,” Burman said. “I think we should be putting in some conditions or having them come back to us if they are going to be changing some of that. I understand the need for some flexibility, [and] I think we can address that as we move forward when we get into the more thorny issues and the other items that are not before us.”

The nearly $24 billion in combined CPNY and CHPE contracts fall under the new Clean Energy Standard Tier 4 category of renewable energy credits (RECs) set up to bring renewable energy into the city by the commission, which set a Feb. 21 deadline for reply comments on the contracts.

CHPE said in its financing petition that it had withheld the expected amount of financing given certain competitive concerns, including bid preparation for the New York State Energy and Research Development Authority’s (NYSERDA) Tier 4 solicitation.

Given that the NYSERDA Tier 4 solicitation has concluded, with the project being one of two award recipients, CHPE said in a supplement to the petition that it “will seek to raise debt financing in an amount not to exceed $4.5 billion.”

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California Poised to Regain Tailpipe Emissions Authority

The Biden administration could be days away from restoring California’s authority to adopt tailpipe emission standards that are more stringent than federal standards.

Citing “multiple sources,” E&E News reported Tuesday that the EPA could reinstate California’s authority as soon as Wednesday of this week. An EPA spokesperson told CNN that the agency expects to issue a decision on the waiver “in the near future.”

The EPA press office didn’t immediately respond to NetZero Insider’s request for information on Thursday.

At issue is a federal Clean Air Act waiver granted to California most recently in 2013 that allowed the state to enforce its tailpipe emission standards for cars and light-duty trucks — as long as the standards are at least as stringent as those of the EPA — as well as a zero-emission vehicle sales mandate. The low-emission vehicle and zero-emission vehicle (ZEV) programs are included in the California Air Resources Board’s Advanced Clean Cars regulation.

Other states were allowed to adopt California’s tailpipe emission standards as an alternative to using federal emission standards.

But in September 2019, the Trump administration adopted The Safer Affordable Fuel-Efficient Vehicles Rule Part One: One National Program Rule (SAFE-1), which rescinded California’s ability to set its own standards.

Then, on his first day in office last year, President Joe Biden issued an executive order directing federal agencies to immediately review actions taken under the Trump administration. The SAFE-1 rule was one that Biden’s order called out specifically.

In April 2021, EPA announced it was reconsidering the previous administration’s withdrawal of California’s waiver. EPA Administrator Michael Regan said at the time that the 2019 action was “legally dubious.”

“I am a firm believer in California’s long-standing statutory authority to lead,” Regan said.

Advanced Clean Cars II

The possible reinstatement of California’s ability to regulate tailpipe emissions comes as the California Air Resources Board (CARB) expects to roll out a new version of its emissions regulation.

Known as Advanced Clean Cars II, the new rule would apply to cars and light-duty trucks starting with model year 2026. CARB expects to finalize the regulation this year. (See CARB Preparing Full Course of ZEV Rules for 2022.)

As of this month, 17 states and the District of Columbia have adopted California’s low-emission vehicle regulations. Most of those have also adopted California’s ZEV regulation.

And other states may soon join the list. The New Mexico Environmental Improvement Board has scheduled a public hearing on May 4 to consider the proposed Clean Cars New Mexico regulation.

Nevada’s clean cars regulation, adopted in October, notes that the state will not enforce the regulation until the EPA reinstates California’s waiver or issues a new one.

California’s Response

In response to the EPA’s decision to rescind California’s waiver, CARB announced in 2019 that a group of automakers — Ford, Honda, BMW of North America and Volkswagen Group of America — had agreed on voluntary measures to reduce emissions. The framework included annual reductions of vehicle greenhouse gas emissions through the 2026 model year and steps to promote the transition to electric vehicles.

In addition, a California-led coalition quickly challenged in court EPA’s action to rescind the waiver. Litigation in that case was stayed while the current EPA reconsiders the waiver, according to a July release from California Attorney General Rob Bonta.

Bonta was joined by attorneys general from 20 other states and the District of Columbia along with representatives of several cities in sending a letter to EPA in July. The letter asks the agency to restore California’s waiver and rescind a previous determination that Section 177 of the Clean Air Act does not authorize other states to adopt California’s greenhouse gas standards for passenger cars and light trucks.

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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.