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November 6, 2024

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Glick Touts Gas Pipeline Reliability Organization Before Congress

Warning of danger to both the nation’s natural gas infrastructure and the bulk power system if the current status quo continues, FERC Chairman Richard Glick on Wednesday lent his support to a proposal by House Democrats that would expand the commission’s powers to regulate natural gas pipelines.

In a three-hour-plus hearing, Glick fielded questions from the House Energy and Commerce Subcommittee on Energy on HR 6084, the Energy Product Reliability Act. Sponsored by subcommittee Chair Bobby Rush (D-Ill.), the bill would create an energy product reliability organization (EPRO) to — in the words of a memorandum circulated ahead of the hearing — “oversee the reliable delivery of energy products on energy pipelines through mandatory and enforceable reliability standards.”

The bill is modeled on Section 215 of the Federal Power Act, which authorized FERC to certify an electric reliability organization, and the proposed EPRO would have a similar relationship to the commission as NERC and the regional entities. It would be required to devise mandatory reliability standards to ensure reliable operation of natural gas pipelines and submit them to FERC for approval, while having many of the same powers as the ERO for enforcement and assessment and review of penalties by FERC.

In his written testimony, Glick lauded the “great strides” that the ERO Enterprise has made toward “improving reliability of the” grid, but he warned that without a similar framework in the natural gas sector, the U.S. remains vulnerable to disruption of the energy supply. He frequently cited last year’s winter storms, which led to thousands of outages across Texas as gas distribution systems failed amid extreme cold weather, to illustrate how the current regulatory regime fails to account for electric-gas interdependencies. (See FERC, NERC Share Findings on February Winter Storm.)

HR 6084 would explicitly require the EPRO to create standards that ensure the reliable supply of natural gas for electricity generation to avert such shortfalls. In response to a question from Rep. Kim Schrier (D-Wash.), Glick said that a more reliable natural gas supply would give electric generators confidence “that they will be able to access the fuel they need to keep the electric generation going during times of extreme weather.”

Cybersecurity Remains a Major Concern

Glick also frequently invoked cybersecurity as a major risk to both the gas pipeline system and the grid, reminding lawmakers of the Colonial Pipeline cyberattack in May that caused the company to shut down its entire pipeline network, a major source of petroleum products to the U.S. East Coast, for several days. (See Colonial Hack Sparks Competing Recommendations at FERC.) The FERC chairman reminded the subcommittee that even before the attack, he and former Commissioner Neil Chatterjee had called for FERC to assume jurisdiction over pipeline security, which is currently handled by the Transportation Security Administration.

Asked by Rep. Mike Doyle (D-Penn.) how HR 6084 would improve the situation, Glick pointed to two key differences. First, the EPRO would have jurisdiction over all aspects of reliability, not just physical and cybersecurity. Second, unlike TSA security regulations that must be renewed every year, EPRO standards would have no time limit.

“The EPRO would be able to propose, and FERC [to] approve … permanent standards that could be modified over time,” Glick said. “I think it’s very important to have a standard-setting situation where you don’t have to come back every year and renew those standards, [but] you’d have some sort of certainty for pipeline companies and others to make the investments they need to make to comply with longer-lasting standards.”

GOP Skeptical About Expanding FERC’s Mandate

Republicans on the subcommittee devoted most of their time to criticizing the Biden administration’s energy policies, repeatedly questioning Glick’s fellow witness, Deputy Energy Secretary David Turk, about the impact of decisions such as revoking the permit for the Keystone XL crude oil pipeline on Biden’s first day in office, or releasing 50 million barrels of oil from the Strategic Petroleum Reserve in November.

But the proposed EPRO did not escape their attention. They sought to portray HR 6084 as an unnecessary expansion of FERC’s power and a distraction from high energy prices. Speaking for many in the minority, Ranking Member Fred Upton (R-Mich.) called the proposed legislation “completely off-base, out of touch with the realities facing America today … [and] a sweeping power grab pre-empting states and local jurisdictions from regulating all types of energy infrastructure.”

“This bill would dramatically expand FERC, transforming a relatively tiny agency into a behemoth with regulatory powers over America’s energy system,” Upton said. “We’re not just talking about interstate pipelines and the bulk power system, [which] cross state lines; this bill would impose new federal taxes, fees and regulations on all energy in the country. Americans are not asking for that bill.”

Rep. Greg Pence (R-Ind.) questioned Glick about the potential cost of mandating new standards and whether the prospect of complying with a new regulatory regime would discourage construction of new pipelines. In response, Glick argued that the long-term benefits of stabilizing the essential gas infrastructure would more than outweigh the upfront costs of compliance.

“I think if you talked to many of the electricity companies, they would argue the fact that we now have mandatory reliability standards on the electricity side [has] actually reduced their cost,” Glick said. “Because they become more reliable, they don’t have to buy backup power. … They don’t have to … go out and build a facility over and over again every time a hurricane comes and lands on their shores. So, I think that actually, in the long term, we’re talking about a more reliable system [and] making sure that the actual costs to consumers go down.”

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BOEM OKs Construction for 132-MW South Fork OSW Project

The Bureau of Ocean Energy Management (BOEM) on Tuesday approved the start of construction for the 132-MW South Fork Wind Project being built for the Long Island Power Authority, subject to the terms of the plan greenlighted in November by the U.S. Department of the Interior. 

“This milestone underscores the tremendous opportunity we have to create a new industry from the ground up to drive our green energy economy, deliver clean power to millions of homes and create good jobs across the state,” New York Governor Kathy Hochul said in a statement. 

A joint venture between Ørsted and Eversource Energy (NYSE:ES), South Fork is expected to begin operations at the end of 2023 and will be located approximately 19 miles southeast of Block Island, R.I., and 35 miles east of Montauk Point, N.Y.

The construction and operations plan, which will create 100 union jobs, promised that the developer would install 12 or fewer turbines and adopt a range of measures to help avoid, minimize and mitigate potential impacts. (See Interior Greenlights 132-MW South Fork COP.)

The Biden administration has been moving to speed up the leasing and permitting of offshore wind energy areas, earlier in January announcing that it will auction six lease areas in the New York Bight on Feb. 23, enough to site at least 5.6 GW of generation. (See BOEM to Auction Six New Lease Areas in NY Bight.)

New York has targeted 9 GW of offshore wind by 2035 and is basing procurement of offshore wind renewable energy credits in part on economic benefits provided by the projects, including domestic supply chain and port infrastructure investments, benefits to disadvantaged communities and creation of jobs and workforce training programs. 

“As New York’s first offshore wind farm, South Fork Wind is already contributing to a new statewide and U.S. manufacturing era and maritime industry, including good-paying union jobs through our labor partnerships and vision for the industry,” CEO of Ørsted Offshore North America David Hardy said.

“With onshore construction expected in the coming days, New Yorkers are closer than ever to realizing the benefits of clean energy,” Eversource CEO Joe Nolan said. 

Kiewit Offshore Services is already fabricating the project’s 1,500-ton, 60-foot-tall offshore substation at a facility near Corpus Christi, Texas. The developers have contracted Long Island-based Haugland Energy Group to install the duct bank system for the project’s underground onshore transmission line and to lead the construction of the onshore interconnection facility in East Hampton.

Work will begin in summer 2023 to install the project’s offshore monopile foundations and 11-MW Siemens-Gamesa wind turbines.

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Texas PUC Pushes ERCOT on Market Changes

ERCOT’s regulators are pushing back against its plans to implement policy changes and new products in response to February’s devastating winter storm.

Asked by the Public Utility Commission in December to lay out an implementation plan for the first phase of what the commission labels a blueprint for ERCOT’s market redesign, staff last week filed a 10-page memo with timelines, budget requirements and key variables surrounding the work (52373).

The PUC’s response?

“I have a lot of concerns,” Commissioner Lori Cobos said during the Jan. 13 open meeting. “I have concerns with the long, projected timelines. … I know ERCOT may be setting expectations, but we have expectations too. We have expectations that these products will be put in the market as soon as possible.”

Cobos and the commission have been focused on ERCOT contingency reserve service (ECRS), a 10-minute ramping ancillary service product designed to address increasing renewable energy penetration. The market change was one of five ancillary services in the blueprint’s first phase. (See PUC Forges Ahead with ERCOT Market Redesign.)

Kenan Ögelman, ERCOT’s vice president of commercial operations, said in the memo that the grid operator has prioritized ECRS for delivery in early 2023. However, because of the product’s interaction with ERCOT’s major energy management system (EMS) upgrade, ECRS may have to wait until that is stabilized after its mid-2023 through mid-2024 implementation window.

“Two years is too long. It’s unacceptable,” Cobos said. “We’ve been working really hard to get these items on the blueprint implanted as soon as possible. I know ERCOT has resource constraints … that need to be evaluated by the leadership at ERCOT. ERCOT needs staff resources and contractors to ensure that ECRS is delivered on time and before the EMS upgrade.”

ERCOT also said it would take one or two years to implement a firm-fuel ancillary service product, another high-priority PUC directive. It asked for the commission’s input on eligibility qualifications, procurement processes, quantity of procurements and performance requirements.

Ögelman said allocating firm fuel’s costs on a load-ratio-share basis, as is done now, would be quicker to implement than assigning costs to certain resources.

“ERCOT must ensure a firm-fuel product is in place by next winter,” Cobos said. “The legislature expects it; Senate Bill 3 requires it.”

Cobos also said the backstop reliability mechanism, a second-phase proposal, should be delivered as soon as possible in 2023. In his memo, Ögelman said that will be difficult to do given the “relative size and complexities of these efforts.”

“ERCOT cannot deliver three major projects simultaneously in next 18 months,” Ögelman wrote.

Commissioner Will McAdams acknowledged that ERCOT is facing a workforce squeeze and urged it to leverage its contractors to bring the near-term market designs online. He said the commission has received feedback from lawmakers that they expect to see several of the proposals “imposed” in the next two years.

“Given the complexity and massive effort we’re taking with the blueprint and we’re ordering ERCOT to take,” McAdams said, “we need to adhere, and must adhere, to the definitive points of the statute where possible. Be aware of that as you’re developing the mechanics.”

Ögelman said staff would begin drafting an urgent revision request on on-site fuel storage as part of the firm-fuel product, adding PUC feedback when they receive it. He told the commission that the grid currently has about 4.4 GW of on-site fuel storage, but he agreed to survey generators to see if there is additional storage capacity.

“We will start that today,” he said. Ögelman said staff will need to minimize revision request timelines and will work with stakeholders to move the change through.

“Funny enough, the [stakeholder approval] process is top of the list for [ERCOT’s new] board to address,” PUC Chair Peter Lake said. “It’s a problem and will be remedied.”

Board Discussions

On Monday and Tuesday, the new directors reviewed ERCOT’s corporate governance structure and project portfolio. An IT subcommittee was among several ideas floated as the board discussed bylaw revisions and other changes.

Staff engaged the board in a lengthy discussion of the many projects they are working on besides those directed by the PUC. The directors peppered the speakers with questions about the use of vendors for complex software systems and the frequent delays in project deliveries, asking how projects could be completed faster.

“It’s not like we have the source code for that system,” ERCOT CIO Jayapal Parakkuth said. “We are completely dependent on the vendor for that system to provide the solution. So, in this case, us adding staff around that product would not help us.”

Mandy Bauld, director of ERCOT’s Project Management Office, reminded the board that the office is working on the largest changes to the market since the nodal market went online in 2010.

“The most important next step is [to] let the new ERCOT board take a look at this and work with them to help chart a path forward,” Lake said. “By the next commission meeting, we’ll continue to put the pieces in place and move the implementation forward.”

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ERCOT Preps for 2nd Cold Snap of Year

ERCOT is bracing for the second major cold front of the year, issuing an operating condition notice (OCN) for Thursday and Friday ahead of expected “extreme cold weather.”

Interim CEO Brad Jones assured the Board of Directors on Tuesday during the second day of a two-day training session that the OCN is just an initial step in the grid operator’s emergency alert system and that he was confident the grid will manage the situation.

“It’s not a significant reliability challenge,” Jones said.

The grid operator issued the OCN at 9:30 a.m., signifying a need for additional resources because forecasted wind chills dropped to a level where they could affect power plant operations. An OCN is still three levels away from an energy emergency alert.

Operations alert levels (ERCOT) Content.jpgERCOT’s operations alert levels | ERCOT

 

Staff said they are expecting demand to peak about 61 GW Thursday night and Friday morning and that they have about 79 GW of operating capacity available. Dan Woodfin, vice president of system operations, said the latter number is “significant” and a “little more” than the grid operator had at its disposal during a Jan. 2-3 cold snap. (See ERCOT, PUC Say Grid is Ready for Winter Weather.)

That did little to comfort some of the directors, who heard much about the lack of transparency between Texas’ electric and natural gas systems. The lack of thermal fuel supplies, primarily natural gas, have been fingered as the primary reason for the widespread power outages during last February’s winter storm. (See FERC, NERC Release Final Texas Storm Report.)

The electric industry has added weatherization requirements with regulatory teeth for its power plants since then, but the gas industry, regulated by the Texas Railroad Commission (RRC), has lagged behind. The commission is not expected to mandate strict weatherization practices until next winter.

Asked if ERCOT would have enough gas supplies for the system’s plants, Jones said staff have already received one notice of a gas restriction that could affect up to 1.5 GW of capacity.

“One of the concerns we have is the great deal of information we don’t have,” Jones said of the gas side. He said he has plans to add a gas desk in the operations center that would monitor gas availability or restrictions, an idea that he said was first brought up in 2015 when he was ERCOT’s COO.

“We had concerns [in 2015 that] we wouldn’t get the information we needed,” he said. “We’re still in the same situation. There’s not a great deal of transparency around the operations of our natural gas system. That information doesn’t usually flow to us.”

Jones and Peter Lake, chair of the Public Utility Commission, both pointed to the Texas Energy Reliability Council (TERC) as where dialogue and coordination between the two industries takes place. Lake said the group was an informal group before the winter storm, but that legislation last year formalized TERC and “designed it specifically for that kind of information sharing.”

TERC meets as often as twice a month, Lake said. However, the meetings are not public.

Director John Swainson pressed Lake on the RRC’s regulatory responsibility. Lake declined to speak for that commission, saying, “They do oil and gas. They’re sitting across the table from us at TERC.”

“Doesn’t that look like sort of a weakness in the system here?” Swainson asked. “We’re trying to ensure our generators can provide power, but if no one’s providing gas to our power plants, that’s a weak link.”

“That’s why the legislature gave us TERC, and that’s why TERC is meeting more frequently,” Lake responded.

Temperatures are expected to dip to as low as 16 degrees Fahrenheit on Thursday in some parts of the state, according to The Weather Channel. ERCOT’s meteorologist says “wind chills will be an issue” most of Thursday and that temperatures likely won’t make it out of the 30s that afternoon in most of the state. Winter precipitation is not expected to be a factor.

Woodfin said that about 11.8 GW of thermal resources are currently on outages, a normal amount for ERCOT.

Staff also updated the board on their weatherization inspections at power plants and transmission facilities, saying they have inspected 324 generation resources and 22 transmission sites. This followed receipt of winter weather readiness reports from 850 generators and 54 transmission service providers. (See ERCOT Generators Near 100% Winter Readiness Compliance.)

David Kezell, ERCOT’s newly hired director of weatherization and inspection, said the inspections found 10 potential deficiencies at dispatchable generation sites, not at intermittent renewable resources, and six at transmission facilities. He said all of the deficiencies are being tracked and that most have been resolved and closed.

“I believe the system is in much better condition this year than it was last year,” Kezell said.

With Kezell’s organization still staffing up, ERCOT was forced to rely on contractors to handle most of the inspections. Staff that were pulled from other departments helped with the more than 3,600 hours of work during the fourth quarter.

ERCOT filed a report on its winter weather readiness inspections with the PUC on Tuesday (52786, 52787).

The board also agreed with staff’s recommendation to reschedule its Feb. 8 meeting to March 7-8. Its meeting schedule was set under its previous format, which was overhauled by the Texas legislature following last year’s storm. Several of the new directors had conflicts with the February date.

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Report Shows Nevada Lagging 2030 GHG Target

A new report from the state of Nevada projects that the state’s greenhouse gas emissions in 2030 will be 24% less than in 2005 — far short of the 45% reduction that the state has set as a goal.

And the 24% projected reduction in 2030 is only slightly more than the 23% reduction expected by 2025. Nevada’s goal for 2025 is a 28% reduction in GHG emissions compared to 2005.

The figures are included in the state’s 2021 GHG emissions inventory and projections report, which the Nevada Department of Conservation and Natural Resources (NDCNR) released last week. The 2021 report details the state’s GHG emissions through 2019 with projections through 2041.

State Senate Bill 254 requires NDCNR to issue the report each year.

The report finds that the state’s electricity sector is on track to meet the renewable portfolio standard (RPS), which requires half of energy sold to customers to come from renewable sources by 2030.

But increased emissions from the transportation, industrial, and residential and commercial sectors “cancel out” progress made under the RPS, NDCNR said.

“Additional climate action is necessary to stay on track with the goals and reign in climate pollution across all economic sectors,” NDCNR said in a release.

The report lists an array of policies Nevada could adopt to potentially bring the state closer to its GHG reduction goals. They include implementing net-zero building codes, adopting California’s upcoming Advanced Clean Cars II regulation or integrating the social cost of GHG emissions in planning.

The report noted that the listed policies aren’t recommendations at this stage; further analysis of costs and benefits is needed.

Decreased Emissions

In 2019, Nevada’s net GHG emissions totaled 40.6 million metric tons of CO2 equivalent (MMTCO2e), an 18% reduction from 49.3 million metric tons in 2005. Nevada contributed 0.71% of the U.S. total for gross GHG emissions in 2019, despite having 0.94% of the population, the report said.

Transportation overtook the electricity generation sector in 2015 to become the state’s largest source of GHG emissions. Emissions from the industrial sector are also on the rise.

In 2019, transportation contributed 34% of the state’s GHG emissions, the report said, followed by electricity generation at 29% and industry at 17%.

Given the trends for the transportation and industrial sectors, “addressing GHG emissions from these two sectors should be a priority for policymakers in both the near- and long-term,” according to the report.

“It is also important to note that continued decarbonization of the electricity generation sector is needed to realize greater carbon reduction benefits of transportation sector electrification,” the report said.

Transportation Sector

GHG emissions from Nevada’s transportation sector hit a low of 13.5 MMTCO2e in 2011, but by 2019 had increased by about 18%. Highway vehicles and aircraft were the main drivers of the increase, the report said.

The report predicts that 2020 data will show a drop in transportation sector emissions, followed by a gradual increase through 2041.

“Generally, gains in emission reductions due to new federal and state regulations will be offset by population and economic growth,” the report said.

But NDCNR noted the “high degree of uncertainty” in making GHG projections for the sector. In particular, it’s not yet known how long the increase in teleworking seen during the COVID-19 pandemic will continue.

In October, the state adopted the Clean Cars Nevada program, which takes effect starting with model year 2025 vehicles. (See Nev. Adopts Clean Cars Rule, Allows Early Credits.)

The report noted that it will take several years for the program to start making a dent in GHG emissions. By 2041, transportation sector emissions are expected to be about 6% lower than they would have been in the absence of the program.

Electricity Sector

GHG emissions from the electricity generation sector dropped from 26.2 MMTCO2e in 2005 to 13.6 million metric tons in 2019, a 48% reduction. The report estimates emissions for all fossil fuel-fired electricity generated in Nevada, even though some of that electricity may be used out of state.

The report attributes the sector’s decrease in GHG emissions largely to the retirement of the Mohave Generating Station in 2005 and the Reid Gardner Generating Station’s last unit in 2017. The two coal-fired power plants were partially replaced with natural gas-fired plants. The increased use of renewable energy is another factor in the sector’s GHG reductions, the report said.

Nevada has two remaining coal-fired power plants: the North Valmy Generating Station, which could potentially retire in 2025; and TS Power, which is expected to be converted to a dual coal and natural gas plant.

The report projects that those changes will contribute to a reduction in emissions from the electricity sector to 8 million metric tons in 2041.

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Ohio Report Offers Policy Roadmap to EV Adoption

Ohio residents who buy electric cars face an annual $200 charge in addition to basic registration fees to make up for not paying 38.5 cents per gallon in motor fuel taxes.

The charge is one of the highest among the 20 states imposing the fees to make up for lost gas taxes used for road maintenance.

But it makes little sense in a state dependent on automobile and auto parts manufacturing, especially as the industry moves into EV manufacturing, argues a policy report issued Tuesday by the Citizens Utility Board of Ohio.

The ABCs of Ohio EVs: A Policy Guide to Electrify Ohio argues that electrification of transportation is happening whether Ohio lawmakers want it or not and that it’s already past time to begin building policies to encourage the transition in an orderly and rational manner.

At its core, the report argues that encouraging auto electrification could lower consumer electric rates because regulated utilities will be able to sell more power over the infrastructure now in place, a debatable contention.

“I would emphasize that the central point of this 28-page report really is that if we do this right, then everybody will benefit from the increasing penetration of electric vehicles whether they drive one or not,” said Martin Cohen, a principal of Martin Roth Cohen and Associates, an energy economics consulting firm that assisted in researching the report.

“There will be downward pressure on electric rates because we’ll have new volumes of electricity sold to charge these EVs at the same time, as [well as] cleaner air and less pollution,” Cohen said in a news conference announcing the report.

“The key is that we need to do this by using the existing infrastructure — generation, transmission, distribution — which we can do with the right policies and programs in place to use electric vehicle charging, which is a flexible load to fill in the valleys in demand for electricity.”

EV adoption will not increase the cost of the system, he added, and it will produce new revenue for the utilities, helping to lower or steady future rates.

Accelerating Adoption

The report also argued that widespread EV use is just around the corner — and not coming in the distant future.

In the first six months of 2021, the number of EVs registered in Ohio jumped from 14,530 to 28,595, rising to 1.72% of new car registrations, but still representing only one of every 300 registered passenger cars, according to the report.

That growth will accelerate, Cohen said. “EVs are really going to be a choice of consumers, which is why they’re going to mushroom. It’s not primarily because of policy.

“It’s because people like them, and they are so much cheaper to drive and have such low maintenance and so many improved performance characteristics over a comparable internal combustion vehicle that we do expect they are going to be very popular,” he said.

The report notes that GM alone plans to produce 30 new EV models by 2025 and only electric cars by 2035.  “With the impending introduction of a new generation of EVs with higher ranges and lower costs, a tipping point toward mass market adoption appears to be on the horizon.”

GM assembles cars in Ohio and makes parts in the state, such as transmissions, an item not used in electric vehicles.

Thomas Bullock, executive director of CUB Ohio, said the anticipated growth of EV sales is set to accelerate.  “We have 4.5 million cars on [Ohio] roads.  When 20% are electric, we could see a 10% increase in overall electricity consumption. That can happen in as quickly as 10 years,” he said.

Bullock noted that AEP Ohio, a subsidiary of American Electric Power, took the first step toward direct utility involvement in EV charging last year in a rate case that included language authorizing EV rates for a limited number of charging stations.

However, the report appears to suggest that utilities should stick to selling power to EV charging companies rather than build the stations. In other words, it’s an issue that requires a comprehensive state policy and not one that can be addressed piecemeal in utility rate cases.

The report also opens a debate about whether state public utility commissions have the authority to develop EV charging policies without underlying rules crafted by state lawmakers.  The Ohio legislature knocked down proposed legislation last year that would have lowered the $200 EV registration fee.

Bullock said the report will be sent to the Ohio PUC, the Ohio Consumers’ Counsel and the legislature. None were asked to participate in drafting the report.

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Federal Judge: Tx Line Can’t Cross Wildlife Refuge

The Cardinal-Hickory Creek transmission project is “incompatible” with southwestern Wisconsin’s protected Driftless Area, a federal judge ruled last week in blocking construction in the region.

U.S. District Judge William Conley, with the Western District of Wisconsin, forbade the nearly $500 million, 101-mile 345-kV line from southwest Wisconsin to Iowa from making a beeline through the Upper Mississippi River National Fish and Wildlife Refuge (21-cv-096-wmc). A final judgement is pending.

Conley said project developers American Transmission Co. (ATC), ITC Midwest and Dairyland Power Cooperative violated federal environmental laws to secure permits for the line. He said clear-cutting and construction of transmission towers in the refuge would fragment habitat, adversely impact wildlife breeding, and permanently alter forest succession patterns — all “clear contradictions with the refuge’s purposes.”

ATC, ITC Midwest and Dairyland planned to begin opening up the project’s Wisconsin portion in early November. However, Conley agreed with several conservation groups and issued a preliminary injunction against the line. (See Conservation Groups Win Injunction vs. Cardinal-Hickory Creek.)

The utilities framed the line as a minor project in need of “a relocated right of way that results in a disturbance of some 30 or so acres … in the context of a 240,000-acre refuge.”

However, in a ruling last Friday, Conley said the route would cut through the heart of the refuge, disturbing 39 acres of land. He said the utilities had only secured permitting for nine of the acres.

Conley struck down the utilities’ arguments that one of the conservation groups didn’t have standing to sue and that the case was moot because they applied for a land transfer as an alternative to their right-of-way permit request.

The judge said that U.S. Fish and Wildlife Service, the agency responsible for right-of-way easement and special-use permits to cross the Upper Mississippi River National Wildlife and Fish Refuge, seemed to be “working hand-in-glove” with ATC, ITC and Dairyland. He said the only other line route alternative offered was a “nearly identical crossing” that indicated the service and the utilities were committed to carving a path through the refuge.

Conley pointed out that the utilities first sought a right of way in 2020, then an amended right of way, and later dropped the requests altogether. They recently proposed a land transfer with Fish and Wildlife instead of a permitting process.

“Suspiciously, all of these actions took place in the months after this case was filed,” Conley wrote, calling the sequence of events “thin porridge.”

“While the utilities have waffled between seeking another right of way or land transfers, at no point has Fish and Wildlife or the utilities suggested that the CHC would not cross the refuge,” Conley said. He said even if a new administrative record for a land exchange was opened, Fish and Wildlife would likely complete a nearly identical analysis to its right-of-way request.

Conley said the government agencies and utilities “appear to be playing a shell game, cavalierly revoking applications for and grants of permits.”

He also pointed out that Congress wrote the National Wildlife Refuge System Improvement Act of 1997 in order “to curb incompatible, secondary uses within refuges.”

“An incompatible use cannot become compatible simply by converting it to a land transfer,” he wrote.

Conley also ruled that the line’s environmental impact statement, prepared by the U.S. Department of Agriculture’s Rural Utilities Service, was inadequate and failed to comply with the National Environmental Policy Act (NEPA).

Conservation groups Wisconsin Wildlife Federation, Driftless Area Land Conservancy, National Wildlife Refuge Association, and Defenders of Wildlife argued in May that developers and government agencies ignored environmental harms when authorizing the line.

Conley said it didn’t appear that the utilities considered increasing the transfer capability of nearby existing lines or pursuing electric storage projects as alternatives to major new construction.

He said it appeared that the Rural Utilities Service simply parroted MISO’s reasoning for proposing the line instead of independently scrutinizing the line’s functions. A decade ago, the RTO said the line would relieve transmission congestion, boost reliability and facilitate more interconnections of renewable generation to the grid. MISO also said Cardinal-Hickory Creek would negate the need for more than a dozen smaller line upgrades in the vicinity.

“Because RUS adopted MISO’s convoluted purpose statement, which then drastically narrowed the alternatives reviewed in the [environmental impact statement], that purpose statement fails to comply with NEPA,” Conley said.

The Cardinal-Hickory Creek line is the last of MISO’s $6.7 billion, 17-project Multi-Value Project portfolio approved in 2011.

Developers Vow Line’s Completion 

In a statement, ATC, ITC Midwest and Dairyland said the judge’s ruling has “no immediate impact on the co-owners’ ability to continue construction activities” after the first injunction was issued. The companies pointed out that a final judgement has yet to be issued and that they are to provide briefs on remedies by Jan. 24.

“The utilities are committed to completing this project, which will reduce energy costs, improve electric grid reliability, relieve congestion on the transmission system, support decarbonization goals and help support the interconnection of renewable generation in the Upper Midwest,” the utilities said.

Environmental Law and Policy Center attorney Howard Learner, representing the conservation groups, said it was clear that Cardinal-Hickory Creek’s route would harm the refuge and said it’s time for the developers to consider alternatives.

“Running a huge high-voltage transmission line with 20-story high towers through the national wildlife refuge is illegal and is contrary to common sense and sound policy,” he said in an emailed statement.

Learner said the permanent injunction “makes clear that the agencies and the transmission companies essentially rigged the environmental impact statement process to preclude fairly evaluating alternatives to the huge, proposed transmission line.”

He said there exist “less expensive alternatives, that are less environmental damaging to the scenic Driftless Area’s vital natural resources, family farms and communities, and that create more local opportunities for clean energy progress in Wisconsin.”

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DC Circuit Rebuffs DOE on Boiler Efficiency Rule

The Department of Energy must provide better justification for its 2020 rule increasing the energy efficiency standards of boilers used in commercial buildings and multifamily housing, the D.C. Circuit Court of Appeals ruled Tuesday, giving the department 90 days to respond.

In issuing the remand, the court said DOE exaggerated the savings that would result from its rule on commercial-packaged boilers. The rule was more stringent than the standards of the American Society of Heating, Refrigerating and Air-Conditioning Engineers (ASHRAE).

The Energy Policy and Conservation Act prohibits DOE from establishing a standard more stringent than ASHRAE’s, barring “clear and convincing evidence” that it is economically justified, technically feasible and will lead to significant energy savings.

Commercial-packaged boilers are gas- or oil-fired and have rated inputs of at least 300 kBtu/h and are used for space conditioning and/or water heating. DOE said the rule, which was set to take effect in January 2023, would save consumers $36,832 for a large oil-fired boiler, a payback of 2.7 years out of an estimated 25-year lifespan.

The rule was challenged by the American Public Gas Association, which represents publicly owned gas distribution systems; the Air-Conditioning, Heating & Refrigeration Institute (AHRI), which represents manufacturers; and Spire Inc., an owner of gas utilities, including Spire Missouri. The American Gas Association, which represents local distribution utilities, intervened in support of the challengers.

The three-judge panel — Chief Judge Sri Srinivasan, Circuit Judge Ketanji Brown Jackson and Senior Circuit Judge Douglas H. Ginsburg, who wrote the opinion — noted that the “clear and convincing evidence” standard “is unusual,” saying, “We are aware of no other authorization for rulemaking subject to this heightened evidentiary standard.

“This unusual framework creates an unusually strong bias in favor of the status quo,” it added.

Bad Assumptions

The law requires DOE to consider the difference in the life-cycle cost (LCC) of equipment with and without a more stringent standard and the projected energy savings likely to result from the standard. The LCC is the sum of the purchase price (including installation) and lifetime operating cost (fuel, maintenance and repairs), discounted to present value.

The LCC analysis required DOE to describe the mix of boilers if it issued no new standards versus the mix with the new rules.

DOE said it had historical shipping data — the most accurate picture of the mix of boilers in a world without new standards — for only two of the eight relevant categories of boilers. Thus, it assumed the distribution of efficiency levels in shipped equipment was the same as that found in models listed in the database maintained by the AHRI.

In its “no-new-standards case,” DOE assumed the distribution of efficiencies among shipped boilers is the same as the distribution of efficiencies across the models listed in the AHRI database.

“As a result, when the DOE ran trials randomly assigning boilers to buildings in the no-new-standards case, the chance a boiler with a certain efficiency level would be assigned to a building in the sample was equal to the percentage of boilers in the AHRI database with that efficiency level, without regard to the characteristics of the building to which the boiler was assigned,” the court observed. In doing so, the court found, DOE failed to acknowledge that a rational building owner would consider the costs and benefits of its new boiler purchase to produce the best economic performance for its building.

“If a purchaser selects the most efficient unit for its building, then the DOE’s model will assign the benefits of that choice to its rule, rather than attributing it, correctly, to the purchaser’s rational decision-making,” the court said, inflating the economic value of the more stringent standard.

The court said DOE was “dismissive” in rejecting comments challenging its random assignment.

“DOE essentially said it did the best it could with the data it had. This is not enough to justify assuming a purchaser’s decisions will not align with its economic interests in purchasing a boiler,” the court said. “Indeed, the DOE’s lackadaisical response would have been inadequate even if the rulemaking were not governed by a heightened evidentiary standard, for the DOE’s failure to ‘engage the arguments raised before it.’”

The court also said DOE “significantly overstated” the fuel cost savings from the new standard.

“Because operators of commercial packaged boilers are among the largest purchasers of fuel from energy utilities, they receive volume discounts and enter into hedging contracts, and therefore pay significantly less” than predicted average energy prices, the court noted.

And it said the agency exaggerated in estimating that the median burner operating hours — a “crucial” variable in the LCC analysis — for most burners was more than 1,000 hours per year.

It cited an AHRI consultant who said “commercial buildings are generally cooling load dominated, so it would be highly unusual to have 1,000 system operating hours per year.”

“By no stretch was this an exemplar of reasoned decision-making,” the court said. “A commenter pointed to seeming anomalies in the DOE’s data, and the agency ignored them.”

Remedy

DOE told the court it expected to be able to provide “a full and sound” justification satisfying the clear and convincing evidence standard.

“Under these circumstances, we think it should be afforded a limited opportunity to do so,” the court said. “Therefore, we shall remand the final rule to the DOE for the agency to take appropriate remedial action within 90 days. If the DOE fails to do so, the final rule will automatically be vacated unless the agency demonstrates within 10 days of the issuance of this decision the need for additional time.”

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ERO Align Tool Final Release Now Planned for Q4

The ERO Enterprise has begun rolling out the third release of the Align software platform and the ERO Secure Evidence Locker (SEL), but some of the functionality planned for the release has been separated out and will be released later this year, SERC staff said Tuesday.

Speaking at SERC’s 2022 Open Forum, Todd Curl, the regional entity’s senior manager for risk awareness and oversight, said that Release 3 of Align — which adds audits, spot checks, compliance investigations and complaints to the functionality covered in previous releases — went online in December.

A spokesperson from NERC told ERO Insider that REs are currently working out plans for training and adoption. Curl said SERC intends to conduct training sessions in the second quarter of 2022, “consistent with what several other regions are doing.”

NERC originally planned for Release 3 to happen in the third quarter of 2021, and to be the final stage in Align’s deployment. (See Release 2 of ERO Align Tool Goes Live for All Regions.) As intended, Release 3 would have also included inherent risk assessments and compliance oversight plans. However, the ERO Enterprise’s experience implementing the first two releases in 2021 led NERC to set more modest goals for the release.

“As the ERO Enterprise subject matter experts worked together to identify the specific requirements needed around this very large Release 3 functionality, it became clear that these processes, which had never before been automated or harmonized, would be simply too complex for one single release,” Curl said. “So, given the importance of the smooth transition for these processes to the effectiveness of the CMEP [compliance monitoring and enforcement program], there were some adjustments to the original plan.”

These remaining functions have been separated into a separate Release 4, which will roll out in the third or fourth quarter of 2022, according to NERC. As with previous releases, the functionalities added in Release 3 and 4 only apply to new cases. Registered entities should continue to process and submit supporting evidence for existing self-reports using their current tools.

First Two Releases Already Online

Release 1 and 2 of Align, along with the SEL, went live last year. (See ERO Align Tool Goes Live for NERC, MRO, Texas RE.) The first release took effect starting in March and covered creating and submitting self-reports and self-logs, creating and managing mitigating activities and mitigation plans, and responding to requests for information. The second, which came online in July, added technical feasibility exceptions, periodic data submittals, attestations and self-certifications.

Align began in 2014 as the CMEP Technology Project, with the rollout date originally set for September 2019; this was delayed because of concerns about the software vendor’s sale to an Australia-based company whose investors include a private equity firm based in Hong Kong. (See NERC Investigating Chinese Tie to Software Vendor.)

This security issue prompted NERC to include the SEL in Release 1 rather than debut it later as originally planned. Because the SEL is intended to provide secure storage where potentially sensitive information can be kept separate from work papers managed through the Align tool, it is not part of the main software package, and REs are allowed to construct their own lockers for CMEP evidence if they meet NERC’s reliability and security specifications.

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MISO’s Seasonal Capacity Proposal Opposed at FERC

Stakeholders last week had mostly negative reactions at FERC to MISO’s bid to reconfigure its resource adequacy design into seasonal auctions with availability-based resource accreditations.

DTE Energy characterized MISO’s new accreditation as a “severe over-correction” that is “based on chance.” It predicted year-over-year capacity credit volatility and generation overbuilt at the expense of ratepayers, should the proposal go into effect.

“MISO’s proposal would inappropriately require a resource owner to do what MISO cannot or will not do, namely predict when system conditions will be tight in advance,” DTE wrote in its protest. “Even if forecasts based on weather predictions and historical patterns were accurate enough to indicate potential operating periods of concern, tight conditions are also driven by unpredictable events such as other resources’ forced outages or transmission outages.”

Louisiana utilities Entergy and Cleco also said the design would expose market participants to an “unreasonable level of volatility.”

The Coalition of Midwest Power Producers said MISO failed to show how the new auction and accreditation design would stem the RTO’s tide of reliability issues and asked FERC to order a technical conference to investigate problems with the plan.

MISO late last year sought the commission’s approval to perform four seasonal capacity auctions, with separate reserve margins, by 2024 and apply a seasonal accreditation based on a generating unit’s past performance during tight system conditions (ER22-495).

The grid operator also filed separately to establish a minimum capacity obligation. MISO load-serving entities would have to demonstrate that they have secured at least 50% of the capacity required to meet their peak load in advance of voluntary capacity auctions (ER22-496). (See FERC Grants Comment Extension for MISO Capacity Filing.)

MISO originally intended the minimum capacity requirement be included in the seasonal auction design. However, stakeholders said including it in the same filing could risk FERC’s rejection of the entire resource adequacy modification. Written opinions on the RTO’s plans were due Jan. 14.

Multiple market participants said MISO’s requested effective date was too soon, since preparations are already underway for the 2023-24 planning year capacity auction(s).

The Clean Energy Coalition, which includes the Sierra Club, Sustainable FERC Project, Natural Resources Defense Council and Clean Grid Alliance, said the seasonal design “is rigid and does not allow for a changing risk pattern that will continue into the future as the resource mix continues to evolve.” The groups criticized MISO for not considering fuel supply risks in accreditation and for using different risk hours to accredit thermal resources and wind resources. The latter will continue rely on the RTO’s existing effective load carrying capability calculation.

They also said the accreditation proposal is incomplete because it doesn’t offer a capacity accreditation approach for electric storage resources.   

Ameren said while it can get behind seasonal auctions, it disagreed with the proposed accreditation because of the disparate treatment of resource types when calculating capacity credits.

WEC Energy Group objected to MISO’s plan to plump up seasons with low or no loss-of-load risk with a resource’s annual availability values for accreditation purposes. It said a resource’s capacity credits in low-risk seasons would “inappropriately include resource availability from other seasons.”

MISO’s transmission owners said while they supported a transition to seasonal auctions and availability-based performance incentives, they wanted the grid operator to explain whether it will continue to limit capacity accreditation to summer interconnection rights. In MISO, a market participant’s annual unforced capacity value cannot exceed the resource’s summer interconnection rights.

“If the proposed seasonal construct is implemented, MISO effectively will be limiting non-summer capacity accreditation to summer interconnection rights,” the TOs said.

The Organization of MISO States (OMS) was one of few to lend support to the seasonal plan, saying it represents an “improvement over the status quo.”

“While MISO cannot control when a generator or transmission line goes down or when and how an extreme weather pattern will affect the system, it can control the signals generators receive to be available in the face of uncertainty,” OMS said. “This proposal more accurately identifies seasonal risk than MISO’s current resource adequacy construct and more accurately accredits resources’ ability to contribute to the system during tight conditions.”

OMS said it is “entirely reasonable for MISO to require resources that receive capacity credit and capacity payments be available to offer energy for a large part of a given season.”

Not all state regulators were in step with OMS. The Mississippi Public Service Commission said the accreditation proposal “interferes with state jurisdiction over generation resource decisions because existing and future generation that does meet MISO’s criteria will be devalued as sources of capacity.”

The PSC said the accreditation is “untested” in any other grid operator and is “a costly experiment.”

The Louisiana PSC also panned the accreditation design as placing “too much significance on too small a sample size” of risky hours. It added that MISO’s month-long limit on planned outages in any season will cause “discriminatory treatment of generation that requires outages greater than 31 days, particularly nuclear generation.”

Manitoba Hydro also said while the filing may not be perfect, it is necessary to confront escalating reliability risks in the footprint.

International Transmission Co. invoked climate change in addition to the resource fleet’s continued transition as evidence that seasonal auctions and accreditations will be necessary. It urged FERC to adopt the resource adequacy overhaul.

Minimum Capacity Rule Draws Ire

The possible introduction of a 50% minimum capacity obligation also proved unpopular. Several said it was a pointless mandate.

The Illinois Commerce Commission protested the possible requirement as unproven and discriminatory against retail choice areas in MISO, which rely on “a robust competitive wholesale market” instead of regulated, integrated resource planning.

The ICC said the rule will “likely result in higher rates that are unjust and unreasonable and is likely to result in the exercise of market power.”

Big Rivers Electric Corp., Hoosier Energy Rural Electric Cooperative, and Southern Illinois Power Cooperative said MISO didn’t describe what reliability problems the minimum obligation is tailored to address.  

Shell Energy North America similarly said MISO didn’t explain its reasoning for introducing the rule. It said the grid operator’s worries about load-serving entities’ (LSEs) increasing overreliance on its voluntary auction are overblown.

“In the last 2021-2022 Planning Resource Auction, MISO procured 96.4% of its capacity from self-scheduled and fixed resource adequacy plan resources, up from 94.5% in the 2020/2021 auction. This trend shows LSEs are acquiring more resources on a forward basis counter to MISO’s claims,” Shell Energy wrote.

Exelon called the minimum capacity obligation “a solution in search of an unsubstantiated problem, which will impose regulatory constraints that will inevitably increase costs to customers.”

However, the minimum capacity rule had its defenders. Entergy said the requirement is a “practical safeguard to ensure that LSEs engage in reasonable resource planning practices” and don’t develop a dependence on the Planning Resource Auction. DTE Energy also called it a “necessary first step in maintaining local and regional reliability.” Duke Energy characterized it as a “a much-needed backstop.”

Consumers Energy said the rule would level the playing field between the LSEs under state obligations to plan their capacity procurement years in advance and those that aren’t. It called the rule a “gentle mitigating measure.”