FERC on Thursday modified its discussion of a previous order rejecting Invenergy’s request to waive SPP’s financial security posting requirements, denying a rehearing request by operation of law.
The commission said in a letter order that it continued to find Invenergy’s waiver request does not address a concrete problem, as required under FERC’s four-part waiver criteria (ER21-2807).
Invenergy Wind Development and Invenergy Solar Development asked for the rehearing after the commission in December found that developer did not demonstrate that its potential loss of posted financial security “is a concrete problem that warrants waiver.” (See FERC Splits on Waivers from SPP IC Process).
The renewable developer said it had eight interconnection requests pending in the same SPP queue cluster as another developer. It alleged that the RTO said the study would need to be redone because requests higher in the queue were withdrawn from an earlier cluster. Invenergy said a discussion with SPP staff about the upgrades and assigned cost allocations left its questions unresolved.
Invenergy said that, faced with the choice of withdrawing its requests or posting a third financial security to preserve its option to stay in the queue and avoid losing previously paid security amounts, it chose to post security under protest for three of its eight projects.
FERC said Invenergy’s waiver request would address the potential to lose its posted financial security if it were to withdraw from the queue with a corresponding impact on the cost and timing of the remaining and lower queued interconnection customers.
“We continue to find that this potential loss is not a concrete problem that warrants waiver of the tariff as Invenergy has not been confronted with forfeiture of its financial security at this time,” the commission said.
Commissioner Mark Christie, who dissented from the previous order, concurred this time, saying it “represents the least bad alternative at this time.”
“It is undeniable that the commission’s ‘case-by-case’ implementation of its waiver policy has allowed it to, in this instance, provide undue preference for one interconnection customer over another without adequate justification,” Christie said. “Here, however, my colleagues have taken advantage of this discretion to reach outcomes that are both arbitrary and unduly discriminatory, and in doing so have undermined whatever value remained of the commission’s four-pronged waiver ‘test.’
“I hope going forward, we can reexamine the commission’s waiver policies to provide clear guidance that can be consistently and fairly applied going forward,” he said.
The California Energy Commission adopted a key report on gas decarbonization last week and opened a proceeding to explore options to replace gas derived from fossil fuels with options that include green hydrogen and electric heat pumps.
“The importance of this really can’t be overstated,” Commissioner Andrew McAllister said. “This is a generational shift, and we’re laying the foundation” for the transition away from fossil gas over the next quarter century, he said.
The report approved March 9 was one of four volumes in the Energy Commission’s 2021 Integrated Energy Policy Report, a biennial roadmap of state energy policy. It examined major issues, including the potential impact of the replacement of gas space- and water-heating with electric heat pumps, the affordability of natural gas as demand declines, and maintenance of aging gas infrastructure.
It addressed the potential for generating green hydrogen on-site at solar arrays and using gas produced from organic waste along with plans to retire the Aliso Canyon Natural Gas Storage facility in Southern California, site of a massive methane leak in 2015. An independent consultant is currently assessing options for closing Aliso Canyon between 2027 and 2035 and replacing its role as the region’s primary gas storage facility.
“The particular challenge is how to transition away from reliance on Aliso Canyon, recognizing the importance it plays in the reliability, safety and economic hedging for the greater Los Angeles area and Southern California more broadly,” the IEPR report said.
Another topic was the grid’s dependence on natural gas to meet demand as the state tries to achieve its 100% clean energy goal by 2045.
“The role of gas generation in the electricity system is shifting with the addition of large amounts of renewable generation, primarily solar and wind,” it said. “Gas generators not only ensure reliability but are key enablers of increasing amounts of renewable resources, which are the primary source of greenhouse gas emission reductions in the electric sector.
“A stable grid is essential to achieving emission reductions from electrification of residential and commercial buildings and electric vehicles to decarbonize the transportation sector,” it said.
The report noted that “defining pathways for gas system decarbonization and addressing key policy issues associated with the gas transition” require a long-term planning process that does not currently exist. As a start to fixing the situation, the CEC unanimously approved a new proceeding examining gas decarbonization strategies.
“As California decarbonizes its energy system, the state faces rapidly emerging gas issues,” the order instituting an information proceeding (OIIP) said. “These issues include declining long-term gas demand from building electrification, the critical interdependencies between the gas and electricity systems, and the potential role of renewable gas, renewable hydrogen, and other low carbon fuels and technologies.
“One of the overarching themes of the 2021 IEPR is that to address these issues the state needs a comprehensive, inclusive, long-term gas planning process to ensure a safe, reliable and equitable transition away from fossil gas,” it said. “This OIIP launches a proceeding to continue the dialogue on gas transition topics and begin carrying out the 2021 IEPR recommendations.”
PJM presented an updated proposal addressing start-up cost offer development at last week’s Market Implementation Committee meeting after being sent back to a subcommittee for more work on the issue.
Tom Hauske, principal engineer in PJM’s performance compliance department, provided a first read of the revised PJM/Independent Market Monitor proposal to revise Manual 15 that emerged from the Cost Development Subcommittee (CDS).
The CDS initially brought two proposals for first reads to the October MIC meeting. (See “Start-up Cost Offer Development,” PJM MIC Briefs: Oct. 6, 2021.) But a vote on the proposals was postponed so more discussions could take place and have stakeholders reach a consensus on a single proposal.
Manual 15 currently allows combined cycle units to include fuel costs after generator breaker closure and synchronization to the grid in their calculations of start-up costs that other unit types, like steam and nuclear units, cannot. The proposed revisions would align start-up cost for all units with a soak process, or units that use steam turbines.
Comparison of a 2×1 combined cycle unit with a pseudo-modeled 2×1 combined cycle unit when dispatched on a parameter-limited schedule | PJM
For units with a soak process, including steam, combined cycle and nuclear units, some of the soak costs would be included in the start-up costs from PJM’s notification to the “dispatchable output” and from the last breaker open to the shutdown process.
Units that don’t have a soak process, like combustion turbines and reciprocating engines, would maintain the status quo, with start-up costs including costs from PJM notification to first breaker close and from last breaker open to the shutdown process.
The revised proposal features several other changes to Manual 15 to provide additional guidance and clarification, including equations to calculate start-up costs, station service calculations for units with and without a soak process, and unit-specific parameter limits on includable costs.
Hauske said PJM’s intent is to provide a six-month window for implementation to allow market sellers the opportunity to have their fuel costs or net generation used for the offset to be reviewed by the Monitor prior to the proposal going into effect.
“We’re trying to avoid the possibility of putting someone in a compliance trap where a unit today could wind up having a smaller start-up cost and then have a fuel-cost policy penalty,” Hauske said.
The committee will be asked to endorse the proposal at next month’s meeting.
Minimum Run Time Guidance Endorsed
Members unanimously endorsed PJM’s proposal addressing pseudo-modeled combined cycle minimum run time guidance after stakeholders asked for more time last month to analyze the changes.
Hauske reviewed the proposal that included adding language to Manual 11: Energy and Ancillary Services Market Operations that would require market sellers to update the minimum run time of any subsequent pseudo-modeled unit to remove the associated steam turbine start-up time included in the parameter limit when it’s dispatched.
Hauske said market sellers can model a combined cycle generation unit as multiple “pseudo units” that are made up of a single combustion turbine and a portion of a steam turbine. But he said the potential exists for one or more of the pseudo-modeled units to operate for a period beyond the minimum run time parameter limit compared to an identical non-pseudo-modeled combined cycle unit if the market units of a pseudo-modeled combined cycle unit are dispatched at different times because the steam turbine takes extra time to reach operative levels.
PJM would provide guidance developed in the initiative to any pseudo-modeled combined cycle unit requesting an adjustment during the review period, Hauske said, or to existing pseudo-modeled combined cycle units with an approved unit-specific minimum run time parameter.
The proposal will receive a final vote at the Markets and Reliability Committee meeting next week. Hauske said PJM wants to have a final endorsement at the next MRC meeting because the RTO’s unit-specific parameter adjustment process started Feb. 28, and PJM must provide a determination on the requests by April 15.
Manual 18 Revisions Endorsed
Stakeholders unanimously endorsed manual revisions conforming with several FERC orders related to PJM’s capacity market.
revisions to the application of the minimum offer price rule, which became effective by operation of law in September when the commission deadlocked (ER21-2582);
an October compliance filing to amend several sections of Attachment DD of the tariff establishing a replacement market seller offer cap (EL19-47);
restored tariff provisions reinstating the prior backward-looking energy and ancillary services (E&AS) offset for the 2023/24 Base Residual Auction and beyond (EL19-58); and
the removal of the 10% cost adder for the reference resource used to establish the variable resource requirement curve (ER19-105).
Bastian said language in section 3.3.2 was updated to reflect that the net E&AS of the reference resource combustion turbine will be calculated using the forward-looking methodology with the application of the 10% adder for only the 2022/23 delivery year. The net E&AS will be determined using the historical approach and without the application of the 10% adder for all other delivery years.
The revisions also delete language in section 5.4.5.2 describing the consequences of accepting a state subsidy after electing the competitive exemption or certifying that a resource is not state-subsidized.
Members will vote on the manual changes at next week’s MRC meeting for final endorsement.
Critical Gas Infrastructure Approved
Stakeholders unanimously approved an issue charge to address critical gas infrastructure recommendations for demand response.
Jack O’Neill of PJM’s demand response department reviewed the problem statement and issue charge addressing the recommendation for DR participation found in the FERC and NERCreport on last February’s winter storm in Texas and other parts of the South.
The report included a recommendation “to require balancing authorities’ operating plans (for contingency reserves and to mitigate capacity and energy emergencies) to prohibit use of critical natural gas infrastructure loads for demand response.”
Natural gas infrastructure in PJM | PJM
PJM began discussions with curtailment service providers (CSPs) through the Demand Response Subcommittee (DRS) to identify impacted loads for the 2021/22 winter season, O’Neill said, and the committee developed a preliminary definition of critical gas infrastructure loads.
O’Neill said CSPs have cooperated with PJM to identify impacted loads in the RTO’s DR Hub application so dispatchers have “operational awareness.” PJM estimates about 20 facilities of critical gas infrastructure load participate as DR in the RTO’s wholesale markets, amounting to about 95 MW of winter capability and 190 MW of summer capability.
The key work activities of the issue charge include defining critical gas infrastructure loads and PJM market participation rules in compliance with FERC/NERC recommendations and developing a transition mechanism if new participation rules impact member’s capacity commitment.
Work on the issue is assigned to the DRS and is expected to last 12 months. O’Neill said the goal is to file any necessary tariff changes with FERC in the first quarter of 2023.
Operating Reserve Clarification Endorsed
Stakeholders unanimously approved an issue charge to address clarifications and potential enhancements to the rules for paying operating reserve credits to resources running when requested by PJM.
Phil D’Antonio of PJM’s energy market operations department reviewed the problem statement and issue charge developed by the RTO to find opportunities to strengthen incentives for supply resources to operate consistent with PJM’s directions.
PJM pays energy uplift to market participants under specified conditions to guarantee that competitive market outcomes “do not require efficient resources to operate for the PJM system at a loss,” D’Antonio said. Uplift payments are one of the incentives for generation owners to offer energy for dispatch based on short-run marginal costs and to operate units through the direction of the RTO’s operators.
D’Antonio said PJM wants to clarify the definition of “operating as requested by PJM” in both the tariff and manuals because it “lacks the type of systematic approach” found in the definition of “following dispatch,” which is used in assessing balancing operating reserve deviation charges. He said PJM and the Monitor have debated the meaning of the definition and want to clear it up.
Key work activities in the issue charge include determining a definition of “operating as requested by PJM” as it relates to payment of operating reserve credits. It also seeks to establish alternative rules addressing the megawatt level to which balancing operating reserve credits should be paid to resources found not to be closely following PJM’s commitment and dispatch instructions.
D’Antonio said stakeholder discussions led to an additional key work activity to determine how intermittent resources are treated under the definition of “operating as requested by PJM” with respect to dispatch megawatts and/or forecast megawatts.
Stakeholders will work on the issue at the MIC beginning in April, D’Antonio said, with the potential for scheduling of special MIC meetings as needed. Work on the issue is expected to last around nine months.
FERC last week ruled that New York transmission owners (NYTOs) can exercise a right of first refusal (ROFR) for upgrades to their transmission facilities without being bound by other developers’ cost caps.
The commission’s ruling Friday adds rules for implementing a federal ROFR for upgrades that are part of another developer’s public policy transmission project under Order 1000 (EL22-2-001).
FERC had ruled in April 2021 that the NYTOs — Fortis’ Central Hudson Gas & Electric (NYSE:FTS); Consolidated Edison and Orange and Rockland Utilities (NYSE:ED); the Long Island Power Authority; the New York Power Authority; Avangrid’s New York State Electric & Gas and Rochester Gas & Electric (NYSE:AGR); and National Grid’s Niagara Mohawk Power (NYSE:NGG) — have a federal ROFR under the ISO-TO Agreement and other “foundational agreements” (EL20-65). (See FERC Confirms NYTOs’ Right of First Refusal.)
NYISO filed tariff changes to implement the ROFR in October under Federal Power Act Section 206 — requiring it to demonstrate that its existing rules were unjust and unreasonable — after stakeholders were unable to reach consensus on a filing under the lower threshold of Section 205. (See “MC Nixes ROFR Tariff Changes,” NYISO Management Committee Briefs: Aug. 25, 2021.)
The commission agreed with the ISO that the lack of rules governing the ROFR “will likely result in disputes at the commission and in court, which will cause delays and potentially harm competitive transmission development in New York.” It noted that the commission has already accepted tariff provisions implementing federal ROFRs in CAISO, PJM, SPP, MISO and ISO-NE.
The tariff revisions create separate categories for public policy transmission projects: new transmission facilities and upgrades to existing transmission facilities.
Under the new rules, which are effective as of Oct. 12, 2021, a NYTO will have 30 days to notify NYISO if it does not intend to exercise its federal ROFR for an upgrade. In such cases, the ISO will designate the upgrades to the developer that proposed the project.
Cost Cap Controversy
The new rules revise NYISO’s voluntary cost-containment requirements, clarifying that transmission upgrades will not be subject to any cost cap. The ISO said that requiring a NYTO to accept another developer’s cost cap would undermine the NYTOs’ federal ROFRs.
A group filing as “New York Consumer Advocates” — including the New York Public Service Commission, New York State Energy Research and Development Authority (NYSERDA), New York City and the Natural Resources Defense Council — protested that the lack of cost containment on upgrade projects would subject consumers to higher costs. Transmission developer LS Power separately contended it would undermine competition by causing developers to stop proposing cost-containment measures.
The commission sided with the ISO, saying that “making a developer’s proposed cost cap binding on the NYTO would raise complex implementation issues because the developer’s cost-containment proposal may or may not represent a reasonable expectation of the NYTO’s upgrade costs.”
It added: “While Order No. 1000 required evaluation of competitive proposals that result in the selection of the ‘more efficient or cost-effective’ transmission solution to an identified regional transmission need, it did not mandate that the transmission provider select the least-cost transmission project or apply cost containment for any project.”
FERC noted that four other grid operators — PJM, SPP, MISO and ISO-NE — either do not subject upgrades to a competitive evaluation process or do not allow nonincumbent developers to include upgrades in their proposals.
In a joint concurring statement, Commissioners Allison Clements and Mark Christie said they share the “absolutely legitimate” cost concerns expressed by the PSC and NYSERDA.
Christie went further in a separate statement, noting that NYISO is a single-state grid operator and that its agencies may reject a proposed transmission project because it is “too costly to consumers or that less costly alternatives are available.”
“And, of course, the ultimate recourse for consumers and consumer advocates concerned about the costs of New York’s — or any other state’s — public policies is to the ballot box,” he added.
Community solar advocates offered a compromise while Dominion Energy (NYSE:D) stood its ground in the latest round of filings last week over the minimum charge for customers who subscribe to shared solar projects.
The parties filed comments in response to the recommendation by Virginia State Corporation Commission hearing examiner D. Mathias Roussy Jr. that the commission approve its staff’s “Alternative Option B,” of a $55.10 minimum monthly charge — about $20 less than Dominion’s proposed charge of more than $75/month (PUR-2020-00125).
The utility had said anything less than that would result in cost shifts to nonparticipating customers. But commission staff, legislators and the Virginia Department of Energy had joined solar advocates in expressing concern that Dominion’s proposed charge is too high to encourage participation in the shared-solar concept. (See Stark Choice for Va. Regulators on Shared-solar ‘Minimum Bill’.)
Expected to launch in July 2023, the shared-solar program would allow apartment dwellers and those in homes unsuitable for rooftop solar to offset part of their electric bills by purchasing a share of solar projects remote from their homes.
Roussy’s recommendation satisfied neither Dominion nor advocacy groups, the Coalition for Community Solar Access and Appalachian Voices, which filed comments on the March 9 deadline.
Dominion said it stands by its proposal. “The company has consistently advocated for a minimum bill that is narrowly tailored to recover only those costs contemplated by the statute and regulations governing the shared solar program,” its counsel, Jontille Ray, argued. “As has been noted already in this proceeding, the minimum bill is not a company creation; it is a requirement of law.” Ray said that qualifying low-income customers would be exempt from the minimum bill.
Writing for Appalachian Voices, William Cleveland of the Southern Environmental Law Center called for adoption of CCSA’s minimum bill proposal of $7.58 per month. “Given Dominion and staff’s inclusion of non-incremental costs in their proposals and failure to produce any evidence or analysis of cost shifts or related cost-benefit analyses, the commission should select a minimum bill that does not rely on those omissions,” Cleveland said. “Unlike Dominion’s proposed minimum bill and Staff Alternative Option B, the low level of CCSA’s minimum bill — $7.58 — would deliver considerable savings to participating customers and help create a workable program.”
CCSA was more willing to compromise. After reviewing the back-and-forth in hearings before the SCC, Eric Wallace, counsel for the group, wrote, “With a $20 administrative charge component (as estimated by Dominion) factored in, CCSA’s proposal increases to a $20 minimum bill plus a $6.58 charge, so customers pay $26.58.”
CCSA’s original $7.58 proposal factored in a $1.00 administrative charge. CCSA’s revised proposal “is substantial relative to the $15-$20 range for other minimum bills around the country.” In Dominion’s South Carolina service territory, a minimum charge of $13.50 was recently approved for shared solar residential customers, he said.
Andy Farmer, the SCC’s interim director of the Division of Information Resources, told NetZero Insider Monday that the agency “does not have a specific timetable for issuing a final order in this case.
“An order could be expected in a few months,” he said.
After a year of debate, semiconductor manufacturer GlobalFoundries has agreed to comply with Vermont’s Renewable Energy Standard if regulators grant its request for self-managed utility status.
The company filed a request last March to oversee its own electricity purchases through the ISO-NE market to power its manufacturing operations in Essex, Vt. In its petition (21-1107-PET), GlobalFoundries claimed that it should be exempt from RES compliance because it would not be reselling electricity. (See Negotiations Stall in GlobalFoundries’ Bid for Vt. Utility Status.)
On Feb. 17, the Public Utility Commission issued an order finding that it does not have the statutory authority to grant that exemption.
“GlobalFoundries’ exit from [Green Mountain Power’s] service territory would either make GlobalFoundries a public service company … or an entity that is not currently authorized under Vermont law,” the order said. “There is no statutorily authorized third option for what GlobalFoundries seeks: to operate with some of the functions of a public service company but without the statutory obligations of a public service company.”
The PUC gave the company three weeks to decide how it would proceed with the application.
GlobalFoundries filed a proposed certificate of public good (CPG) Friday that indicates it will, as a self-managed utility, comply with the RES and any forthcoming changes to it. A bill (S.264) currently before the state legislature proposes to increase the state’s RES from 75% by 2032 to 100% by 2030.
“GlobalFoundries will continue to work with the state to meet the greenhouse gas reduction targets set by the [2020] Global Warming Solutions Act,” Shapleigh Smith, an attorney with Dinse, Knapp & McAndrew, said in a letter Friday to the commission. “This includes, among other things, GlobalFoundries’ commitment to an entirely carbon-neutral electricity supply for its Essex facility.”
If approved, the proposed CPG would obligate GlobalFoundries to:
make payments to offset the loss of gross revenue taxes it would have paid as a utility customer;
continue to participate in Vermont’s energy efficiency program; and
pay into the state’s Home Weatherization Assistance Fund.
The CPG would also exempt the company from “requirements applicable to traditional public utilities that are intended to protect ratepayers and other members of the public but which are not necessary in the context of a self-managed utility.” Those requirements include, for example, rate setting and least-cost integrated planning.
The Conservation Law Foundation, a party to the case, filed a memorandum Thursday seeking clarification of the scope of the PUC’s order regarding an RES exemption. GlobalFoundries believes that the order establishes that the commission has the authority to grant the company’s request to become a self-managed utility, CLF said in the memo. CLF, however, disagreed with that assessment.
The company’s “ongoing effort to establish a ‘self-managed utility’ appears to flout the commission’s order,” CLF said.
In its order, the commission said that there is no concept in Vermont statute for a self-managed utility. As such, CLF said, the commission made it clear that by discontinuing service with GMP, GlobalFoundries would either be a regulated public service company or an entity not authorized by Vermont law.
In a separate memo filed Thursday, AllEarth Renewables (AER) agreed with CLF’s reading of the order, adding that the commission failed to take the order to its “clear conclusion.”
By finding that the PUC can authorize a public service company but not create a utility entity as described by GlobalFoundries, the commission “has effectively and correctly decided the entire case,” AER said. Given that finding, AER said, the PUC should dismiss the case.
GlobalFoundries filed a proposed docket schedule that calls for technical hearings in June and a final order from the PUC on the petition by Sept. 1.
The head of Maine’s Public Utilities Commission called for better regional coordination and governance changes at ISO-NE during the Consumer Liaison Group’s meeting Thursday.
Phil Bartlett — who was giving the keynote address because it was Maine’s turn to host the quarterly meeting, which has turned virtual during the pandemic — emphasized that energy consumers “are going to be footing the bill” for many of the changes occurring in the region’s energy transition.
“We need to come together as a region to plan and effectively communicate what we’re trying to accomplish,” Bartlett said.
He also warned that New England needs to be thoughtful about its transmission planning, especially in light of the failure of the New England Clean Energy Connect, shot down by Maine voters in a decision that is still in court.
“That’s something we need to confront head on and think about how to tackle,” Bartlett said, warning that it would be hard to build any infrastructure if every new transmission line faces opposition from incumbents.
Bartlett also said he sees an impending clash between state energy contracts and the region’s markets.
“There’s a real risk that markets won’t be sustainable,” he said. “If states are putting so much under contract, the markets, which are designed to provide competitive pressures, are going to have a difficult time doing that. We need to have these honest discussions.”
And lastly, Bartlett reiterated calls for ISO-NE to improve its transparency and involve states more in its process.
“At this point, any sort of market reform or transmission planning is going to implicate state policies, and it’s important that states be at the table,” he said. “We also need to make sure that consumer costs are getting better attention and consideration as decisions are going to be made.”
Order 2222
A panel of speakers also discussed ISO-NE’s approach to complying with FERC Order 2222, which directed RTOs to facilitate distributed energy resource aggregations’ participation in their markets.
“Bundled together, we see them as something that could respond to price, to be the balancing resource, to change production or change load on the system in conditions of over- or under-generation,” said Henry Yoshimura, the RTO’s director of demand resource strategy.
“Our members have told us they don’t think ISO-NE’s proposal will allow them any more avenues than they already have,” Jeff Dennis, managing director of Advanced Energy Economy, told the CLG.
Ian Burnes, program manager at Efficiency Maine Trust, noted that a challenge with tapping into the benefits of demand resources is consumer awareness.
“Most consumers don’t care about their energy. They don’t care until the bills get high, or their hot water isn’t on, or their house gets cold, or their light bulb has burnt out,” he said. “So we have a real challenge of delivering on this great promise of aggregating loads to reduce the cost of decarbonizing our economy.”
“I look forward to working with everybody at ISO, in the markets and in New England to make sure we can get this right, but it’s going to take a real attention to detail and a real commitment to make it work so we can meet customers where they are,” Burnes said.
RTO Update
Anne George, ISO-NE’s vice president for external affairs and corporate communications, gave an update on what the grid operator has been working on.
She highlighted numerous studies and initiatives the RTO is undergoing to improve its forecasting and adjust to the energy transition. George also gave a summary of the messy process of completing February’s Forward Capacity Auction. And she ran through the events of January, which included near-record prices and increased emissions, because of cold weather and higher electricity demand.
“It was a pretty interesting January. But thankfully, some of the issues we saw take place didn’t result in any sort of emergency procedures,” George said.
Leadership Change
Rebecca Tepper is stepping down as chair of the CLG’s Coordinating Committee after seven years and 25 quarterly meetings.
She’s handing the duty over to Elizabeth Mahony, an assistant attorney general in Massachusetts.
HOUSTON — Taking his turn in the CERAWeek by S&P Global’s briefing room Friday, U.S. Sen. Joe Manchin (D-W.Va.) wasted no time as a reporter began to ask a question about possible negotiations to reconfigure the Build Back Better Act.
Cutting the journalist off, Manchin said, “There is no Build Back Better.”
An awkward silence fell over the room. Manchin, whose announced opposition to the $2.2 trillion reconciliation package in December effectively killed the legislation, took notice.
“Look, I don’t mean to be sarcastic. That bill was as a major, mammoth piece of legislation, OK? I had concerns from Day 1 that we shouldn’t be doing that much policy,” he said.
Manchin said the Democrats’ use of reconciliation to pass the bill was wrong, saying the process was not designed for policy but to “get our financial house in order.”
“Here we are changing the whole social restructuring of our society, and that was the biggest thing that I had with it,” he said, acknowledging there are “many good things” in BBB. “Our debt grows every day, every day. You’ve got to change that trajectory. Get a tax code that’s competitive and fair and allows us to compete and grow and be prosperous, but pay the bills and then use the revenue from that to pay down debt and get your finances in order.”
Manchin was joined by Sen. Lisa Murkowski (R-Alaska), his former partner on the Senate Energy and Natural Resources Committee, and 900 other speakers during CERAWeek. The global energy gathering, often called the “Davos of energy,” attracted a record 5,800 delegates, bettering the attendance for the most previous in-person CERAWeek in 2019.
Most speakers addressed Russian’s invasion of Ukraine and the alarming upheaval in energy, commodity and financial markets it has created. They discussed energy independence, supply chain disruptions, new business strategies and an accelerated “pace of change” brought on by the economic and geopolitical turmoil.
“My hope is that with [the] situation in Ukraine … all the eyes in the world [are] truly focused on energy in a concerted and directed way that we have not seen before,” Murkowski said. “Now everybody’s talking about it. I think we have an opportunity, we have an avenue, but it’s not something that we can just talk about. We’ve got to be acting in administration. Let’s acknowledge that we have resources that are available to us, and let’s focus on what we have here. Why are we going to places where they hate us? It makes no sense. There are no good answers.”
“We are on the cusp of things we’ve never seen in my lifetime. I’m more concerned right now that this thing will take off, and we have no idea what the endgame is going to be,” said Manchin, who remembered clearly the Cuban Missile Crisis in 1962. “We’ve allowed [Russian President Vladimir] Putin to weaponize energy. … You better have a weapon just as good, if not better. By God, we’ve got to start using that, and that’s energy, energy independence, energy productivity in this country.”
“It is very sobering, and it’s a reminder to us of the leadership responsibilities that we have and how we, again, step into those roles,” Murkowski said. “How we assume that leadership, how we take the tools that we have at our disposal, to not only make us less vulnerable, but to help our friends and allies, which again, takes us back to energy and the role that the United States can play. I think there is a moral obligation here.
“If we can, we should do that in a responsible way that recognizes that climate is still a very, very serious issue for us,” she added. “We don’t have to put it off the table. Again, what we can do to contribute to the safety and the security and the resiliency of people that we care about who are fighting for their own freedom and democracy?”
Granholm Asks Industry to Work with DOE
During a luncheon address to CERAWeek’s attendees, U.S. Energy Secretary Jennifer Granholm placed her remarks in historical context.
“We could not be having this conversation at a more intense, troubling, shocking time in world history … with enormous consequences for the future of energy,” she said. “I’m in a mood to cut to the chase here and tell you what I really think about where we are at as a country and as a part of the energy sector. We are on a war footing — an emergency — and we have to responsibly increase short-term supply where we can right now to stabilize the market and to minimize harm to American families.”
Granholm said releases from the world’s strategic oil reserves will help, but she also asked energy companies to produce more now, where they can. But she said that doesn’t mean she is setting aside climate change concerns or the clean energy transition, which is already happening.
“You all know that. You’re wrestling with it yourselves. You’ve got businesses to run and employees who are nervous about the change,” Granholm said. “We have to do this right, with the right timing, the right technologies, the right partnerships. But we can’t do it if we are fighting internal battles. Some people here seem to think this is the time to recycle old talking points.”
She pointed out that natural gas and LNG are at record levels, and that oil production will be there by next year. She also reminder her audience that 9,000 onshore drilling permits “are sitting unused.”
“We’ll walk and chew gum at the same time. So yes, right now, we need oil and gas production to rise to meet current demand,” Granholm said. “We are here to work with anyone and everyone who’s serious about taking a leap toward the future, by diversifying your energy portfolio to add clean fuels and technologies … by creating good-paying jobs for your talented workforce in the energy industry of the future, and by reaping the rewards of a clean-energy market that will exceed $23 trillion by the end of the decade.”
Granholm said the Department of Energy is ready to partner with the private sector through the $62 billion the agency received last year from the Infrastructure Investment and Jobs Act.
“The truth is, the U.S. government has always partnered with the energy industry in times of need. For over 100 years, the oil and gas industry has powered our nation and gotten us where we are today,” she said. “We are eternally grateful for that, and we want you to power this country for the next 100 years with zero-carbon technologies.”
Bringing her hands together, Granholm closed by saying, “Aren’t we ready to finally work together to confront this moment of crisis and come out stronger on the other side?”
Glick: FERC Investigating ‘Market Anomalies’
FERC Chairman Richard Glick said the commission is investigating whether natural gas operators may have manipulated the market during the February 2021 deep freeze.
“We are investigating potential allegations of manipulation that may have happened in jurisdictional electricity markets, and we did find some anomalies,” Glick said. “Those are being further investigated.”
Glick told reporters investigations like this one take time and that no conclusions have been made.
“One thing that I have tried to make clear under my chairmanship is that if wrongdoing occurs, we’re going to go after that, and that’s certainly going to be the case in this in this situation too,” he said. “It just takes a while to go through the evidence.”
FERC isn’t looking at market manipulation claims within ERCOT, as it is not within the commission’s jurisdiction. It is also limited in its regulation over interstate gas pipelines in Texas once they are operating.
“We have authority over pipelines when they’re sited, and we also have authority over the rates that [interstate] pipelines charge throughout the life of the project,” Glick said.
Asked his thoughts about ERCOT’s market-redesign efforts, he said in that instance, he was glad the commission doesn’t have jurisdiction over the Texas grid operator.
“We have enough problems in terms of market redesigns and the ones we actually overseeing. I wish them luck,” Glick said.
EPA Offering ‘Regulatory Certainty’
EPA Administrator Michael Regan countered several speakers that argued the Biden administration is actively discouraging investments to increase U.S. energy production by pointing out 90% of natural gas extraction is done on private land.
“That continues to move forward,” he said, “I think this president is very smartly focused on a transition that is equitable but also that is cognizant of the current state of play in the world. We all want affordable, reliable, energy and electricity, and I think the smart regulatory approach is to capture where the private sector has been going on for the last decade is the right way to get 80 to 90% of capacity coming online this year.”
Regan said he remains confident the U.S. will eliminate emissions from fossil fuels in the power sector by 2035 and promised to present a “suite of rules” to the industry.
“Obviously, as we develop these rules, we actually quantify the performance of these rules. We will do sort of the quantification to look at the reductions we would get from those targeted pollutants. … By presenting all of these rules at the same time to the industry, the industry gets a chance to take a look at this suite of rules all at once and say, ‘Is it worth doubling down in investments in this current facility or operation? Or should we look at that cost and say now it’s time to pivot and invest in a clean energy future.’
“If some of these facilities decide that it’s not worth investing in and you get an expedient retirement … that’s the best tool for reducing greenhouse gas emissions. The industry wants us to keep our eyes on all of the balls that are up in the air so that they can have regulatory certainty and they can make the best investment strategies possible.”
Ukraine Nukes’ Safety ‘at Risk’
In a hastily arranged addition to CERAWeek’s agenda, Nuclear Energy Institute representatives held a briefing on the state of play in Ukraine following the Russians’ capture of Chernobyl and the Zaporizhzhia nuclear power plant, the largest such facility in Europe.
International Atomic Energy Agency Director General Rafael Mariano Grossi has said several of the IAEA’s seven “indispensable pillars of nuclear safety” are already at risk following the Russian takeover of Zaporizhzhya. Those pillars include allowing the operators to fulfill their safety and security duties and be able to make decisions “free of undue pressure.”
“We understand the Ukranians are continuing to operate all these power plants,” NEI CEO Maria Korsnick said Wednesday, noting a “military structure” is in place over Zaporizhzhya’s staff.
Nuclear units in Ukraine. | Energoatom
The plant “continues to operate safely,” she said. “We have verification that operators are changing shifts, so those are healthy indications that it is operating well during these stressful times.”
Zaporizhzhya has six reactors. NEI said one unit is operating at 60% power as of March 9; two have undergone controlled shutdowns; two others are being held “in reserve” in low-power mode; and the sixth is down for maintenance.
The last undamaged reactor at the Chernobyl nuclear plant was shut down in 2000, with spent fuel rods placed in cooling water and “sufficiently cooled,” said John Kotek, NEI’s senior vice president of policy development and public affairs.
Kathryn Higley, a professor at Oregon State University’s School of Nuclear Science and Engineering, said Chernobyl’s radiation monitors have not shown any releases. Ukranian regulators say diesel generators continue to provide backup power at the plant and to the spent fuel storage facilities at the 1986 accident’s site after transmission lines were severed Wednesday; additional fuel supplies were delivered Friday.
Ukraine’s nuclear utility, Energoatom, continues the operate the country’s other nine reactors at three different sites.
MISO said last week that the transmission line linking its Midwest and South regions has been out of commission since December and is expected to remain offline until July, raising the cost of energy transfers.
The RTO said it will replace the contract path capability between its regions with non-firm service on April 10 until the line returns to service. It said members should prepare for “financial and operational implications.”
The 1,000-MW contract path, a 500-kV Associated Electric Cooperative Inc. line, went offline Dec. 10. The line, which stretches from southern Missouri into northern Arkansas, is MISO’s only physical tie between its Midwest and South regions. MISO said it expects the line to remain on an extended outage through June 30, leaving it dependent on non-firm transfers from neighboring grids.
During a Thursday Market Subcommittee meeting, senior adviser Jack Dannis said a Dec. 10-11 tornado outbreak that bombarded the central and southern U.S. took out 17 towers and four miles of the line. He did not specify which state the line damage occurred in.
The tie was originally expected to be back in service by the end of February. Dannis said he couldn’t speculate on whether the work requiring the outage would be extended beyond June.
Clean Grid Alliance’s Natalie McIntire said she was surprised that MISO waited so long to report the status of the contract path.
“This happened in December, and the first I heard about it … was yesterday,” she said. “I’m wondering why MISO hasn’t alerted stakeholders to this beforehand.”
McIntire pointed out that the grid operator’s leadership has delivered two executive updates to stakeholders since the line went down. Neither mentioned the line’s outage.
As a rule, MISO doesn’t reveal specific generation or transmission outages on its system.
Andy Kowalczyk, with activist group 350 New Orleans, said he was also concerned that staff didn’t communicate the significant outage, especially considering that a winter storm passed through the area a few weeks later.
Dannis said MISO only recently became aware of the outage’s extension into summer. He said the RTO will replace the firm capacity with “non-firm, as available” transmission capacity after it exhausts its four-month grace period, according to a usage agreement of the line with SPP, AECI and other joint parties. The agreement provides that the grid operator can pay an additional $667/MW-month “for every decreased megawatt of contract path capacity.”
Assuming the line is back in service by July, MISO would need to pay about $1.3 million to secure 1,000 MW of non-firm transfer capability. It will divide the cost among market participants using its current market-based allocation design that assigns costs based on excess congestion across its regional directional transfer constraint.
Kevin Vannoy, director of market design, said though MISO’s usual 1,000-MW contract path becomes non-firm because the physical line is out of service, it can still flow up to its usual 2,500-3,000 MW non-firm transfers under its agreement with SPP and the joint parties.
“We think there’s enough physical transfer capability on the system to continue operating as we normally have,” he told stakeholders.
However, Vannoy said it’s possible that conditions might force MISO to order transmission loading relief to reduce transfers. The RTO’s use of non-firm transfers can be curtailed down to zero to prevent load shedding or during system emergencies.
Minnesota Public Utilities Commission staffer Hwikwon Ham asked whether MISO has considered a hypothetical heat wave striking it and SPP at the same time, forcing transfers to be curtailed.
Staff said they’re increasing coordination with members but haven’t devised any special mitigation plans.
Stakeholders questioned why MISO didn’t make updates to either its spring reliability outlook or the delivery estimates in its capacity auction because of a major transmission line’s loss.
Dannis said MISO has been operating for three months now with “minimal” operational impacts. He said he expects little difficulty during the shoulder maintenance season.
MISO Director of Settlements Laura Rauch said the impacts should be strictly financial.
“We can still operate as we normally do. This is about dollars, not anything that would preclude us from operating,” she said.
Stakeholders asked why it’s taking six months to complete line repairs.
Dannis said he was aware of some supply chain issues for equipment needed to fix the line but said he couldn’t offer anything further.
The D.C. Circuit Court of Appeals on Friday handed more fuel to FERC’s Democratic majority for its new policies on natural gas infrastructure, ruling that the commission has to take another shot at reviewing downstream greenhouse gas emissions from a Massachusetts compressor project.
The court granted a petition for review and remand from Food & Water Watch, which had challenged FERC’s approval of a project by Tennessee Gas Pipeline to upgrade a compressor station in Agawam, Mass.
“The commission’s environmental assessment failed to account for the reasonably foreseeable indirect effects of the project — specifically, the greenhouse gas emissions attributable to burning the gas to be carried in the pipeline,” Judge Sri Srinivasan wrote in the court’s opinion.
The environmental group had argued that FERC’s decision failed to comply with the National Environmental Protection Act in four ways, and the court agreed with one of those arguments: that FERC failed to adequately consider the effects of the emissions associated with the consumption of the gas that the project would carry.
The commission had asked for data from Tennessee Gas, and the pipeline company provided them, but FERC found the information was “too generalized” to estimate downstream emissions at all, an argument which the court rejected.
The court relied heavily on its 2017 decision in Sierra Club v. FERC, better known as “Sabal Trail,” a similar case in which the Sierra Club challenged FERC’s approval of three pipelines in the Southeastern U.S.
“Our decision in Sabal Trail points the way to concluding that the available information was sufficiently specific to render downstream emissions reasonably foreseeable,” Srinivasan wrote.
The court ordered FERC to “perform a supplemental environmental assessment in which it must either quantify and consider the project’s downstream carbon emissions or explain in more detail why it cannot do so.”
Well Timed for Glick
The ruling will fit neatly into the argument that FERC Chairman Richard Glick has been making around his decision to revamp the commission’s pipeline approval process to more closely consider emissions, which has been challenged by Republicans and even some Democrats in Congress.
In a Senate hearing just days before the latest ruling, Glick pointed specifically to the D.C. Circuit’s past opinions to defend his move to update FERC’s policy statement governing natural gas infrastructure certificates. (See Glick: No Regrets over Gas Policy Statements.)
“The D.C. Circuit has spoken on several occasions, and unless the court’s interpretation is reversed, we have no choice but to follow with unambiguous guidance,” Glick said.
The changes “will lead to project orders that are more legally durable,” he added.
Things Left Unsaid
The ruling notably did not take a position on the “significance” of downstream emissions, but only whether FERC has a duty to tally them.
“We see nothing that provides any view on whether FERC has the authority to require mitigation of those emissions as a general matter,” ClearView Energy Partners wrote in its analysis of the ruling. “Since FERC did not make a call on significance in this case, and the petitioner failed to properly raise it, this case provides no incremental insight into this issue.”
The court also didn’t shed any light on the assessment of upstream emissions or the use of the social cost of carbon, so those will have to be adjudicated in future cases. “Those fights still lie ahead,” ClearView wrote.
Reactions
“Today’s decision adds to a growing list of cases affirming that FERC is required to consider these climate impacts,” said Sarah Ladin, an attorney at the Institute for Policy Integrity at the New York University School of Law.
“More broadly, today’s decision affirms that the commission’s new policy statement is an appropriate action to ensure it properly considers greenhouse gas emissions in assessing pipeline applications,” Ladin wrote in a statement.
Gillian Giannetti, a senior attorney at the Natural Resources Defense Council, wrote that FERC’s work on the Agawam project was the “kind of shoddy review that FERC aims to correct in updating its policy statements.”
“It doesn’t benefit anyone for FERC to lose over and over and over on this issue,” she tweeted.
