FERC on Monday rejected the Coalition of MISO Transmission Customers’ (CMTC) proposal to allow some load to exit the MISO system penalty-free given the current Midwestern capacity shortfall.
The commission said CMTC failed to prove that MISO’s current tariff practices are unjust and unreasonable just because they don’t contemplate allowing load to bow out when the capacity auction fails to procure enough supply (EL22-60).
CMTC argued before FERC in May that MISO should allow its customers to decrement their load without being charged capacity payment obligations to lessen the possibility of summer blackouts. (See MISO Customers Ask for Penalty-free Load Reductions.)
The group said reductions in load would help following MISO’s 2022/23 Planning Resource Auction (PRA), which unveiled a 1.2-GW capacity shortage across MISO Midwest, triggering a $236.66/MW-day cost of new generation entry (CONE) clearing price for the entire subregion. (See MISO’s 2022/23 Capacity Auction Lays Bare Shortfalls in Midwest.)
CMTC contended that when a deficit occurs, MISO should allow some load to depart the system to avoid the steep capacity prices and bolster reliability by trimming demand. The group suggested that the RTO could allow load exits up to the 1.2-GW auction shortage and stop accepting any further load reductions once the supply and demand imbalance is resolved.
But FERC said that CONE clearing prices are an intentional feature of the auction — not a bug — beckoning new resources into the market.
“We are not convinced that the 2022/2023 auction results constitute a change in circumstances,” the commission wrote.
FERC said load-serving entities have ways of hedging against high auction prices, including entering bilateral supply contracts ahead of the auction, “supporting the development of new facilities” or selling demand response capabilities.
“The ability to hedge against high auction prices and the various off-ramps from the auction is further evidence that the existing tariff provides opportunities to avoid potentially high prices in the auction and is not unjust and unreasonable as complainants claim,” FERC said.
The commission also said it wasn’t convinced that CMTC’s proposed solution would be just and reasonable. It said giving auction participants the chance to “shed an otherwise binding commitment after an auction is conducted” would undermine the auction’s prices that signal for resource planning and investment.
In a separate concurring opinion, Commissioner James Danly repeated concerns about the flood of intermittent resources in MISO’s interconnection queue and its dwindling dispatchable generation. He called the RTO’s current market design “inadequate to the task of procuring sufficient capacity.”
However, he admitted that the 2022/23 PRA functioned as intentioned “regardless of poor decisions by market participants or the long-term consequences of systemic defects in MISO’s capacity construct.”
“Why observers of MISO would shriek and clutch their pearls when the price rises to CONE in the event of a capacity shortfall … is beyond me. Anyone who gets upset about prices rising in times of scarcity cannot truly be a proponent of competitive markets,” Danly said.
MISO itself argued that processing and then resettling “a multitude of load exit requests” would be burdensome and require compliance controls. It said it foresaw “complex computation” and “needless litigation” if FERC greenlit penalty-free departures.
The RTO said it would likely be forced to replicate the auction with new levels of load so it could establish updated demand forecasts, different systemwide and zonal reserve requirements, and adjusted zonal resource credits. It said CMTC was oversimplifying a solution.
MISO’s Independent Market Monitor said CMTC’s complaint was “fundamentally incompatible with MISO’s market design and tariff.”
The Coalition of Midwest Power Producers added that CMTC was essentially seeking retroactive ratemaking and said if FERC granted the complaint, it would have “eroded investor confidence in all regional transmission organization/independent system operator markets and would also represent a disruptive precedent that others could seek similar cost avoidance.”
Multiple stakeholders are seeking a FERC re-evaluation of MISO’s approved seasonal auction design, arguing that the plan’s capacity accreditation based on generators’ past performance is untested and unfair.
The Louisiana and Mississippi public service commissions said that while they don’t “in concept” oppose capacity accreditation rules “based upon some measure of historic generator performance,” MISO didn’t provide evidence to back up its availability-based accreditation.
They acknowledged that FERC defers to and gives grid operators latitude in designing their markets.
“But when the vast majority of utilities and many state regulators, with thousands of years of cumulative experience regulating utilities and serving retail customers, vociferously object to an expensive, untried, untested and unmodeled market experiment that is highly unlikely to address the resource adequacy concerns developing in MISO, FERC needs to listen,” the state commissions wrote.
FERC in late August gave MISO the go-ahead to establish 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. However, the commission disallowed MISO’s proposal to institute a minimum capacity obligation, in which a load-serving entity must demonstrate that it has secured at least 50% of the capacity required to meet their peak load in advance of the RTO’s voluntary capacity auctions (ER22-495 and ER22-496). (See FERC OKs MISO Seasonal Auction, Accreditation.)
Consumers Energy said the availability-based accreditation will breed “unreasonable volatility for market participants and increased costs to customers without demonstrated reliability benefit.” The company asked FERC to consider delaying implementation until the 2024/2025 planning year if it chooses to let the accreditation design stand.
DTE Energy and Alliant Energy seconded Consumers’ claims that the accreditation will aggravate volatility and raise costs. They called the design a “flawed and insufficiently supported approach that will handicap prudent planning practices by stakeholders.”
Entergy, Cleco Power and other MISO South electric cooperatives said the accreditation will yield “large and unreasonable fluctuations in accredited capacity from one season in one year to the same season in the next year.” They said LSEs stand to lose “significant capacity value” in one season based on performance during one or two days with small operating reserves.
The MISO South stakeholders also took issue with the RTO’s 31-day outage limit in a given season. They said the rule “places unreasonable limits and costs on a utility that wishes to engage in prudent maintenance practices at times when sufficient resources are expected to be available to maintain reliability.”
The Clean Energy Coalition — which includes Clean Grid Alliance, Sierra Club, Natural Resources Defense Council, Sustainable FERC Project, Fresh Energy, GridLab, American Clean Power Association and Solar Energy Industries Association — said MISO’s plan to apply different accreditation methods between thermal and non-thermal generating resources is unjustified and unlawfully discriminates based on resource type.
MISO’s new capacity accreditation design applies only to thermal generation; the RTO is still working on a separate accreditation for its renewable and load-modifying resources.
MISO Submits Rehearing Request for Different Reason
Meanwhile, MISO is asking FERC review its decision to reject the minimum capacity obligation (MCO).
The grid operator said the commission’s denial “failed to recognize the proposal as a solution to encourage prudent planning by load-serving entities, utilities, suppliers and regulators to address immediate resource adequacy concerns and the widening gap between available capacity and rising demand.”
MISO said the MCO is not meant to incent generation construction, as FERC assumed.
“Instead, the MCO is a solution designed to serve as a guardrail for the region’s increased reliance on the PRA [Planning Resource Auction] for more than residual capacity needs,” the RTO said. It added that the rule would help avoid “last-minute capacity shortfalls in the PRA by requiring a minimum level of prudent, forward planning by LSEs.”
MISO said years of low capacity prices have led to expedited retirements and deferred investment in generating facilities, with some LSEs depending on its residual auction to stock all their capacity needs.
AUSTIN, Texas — With ERCOT’s Board of Directors having solidified itself as the new sheriff in town — and made up entirely of Texas residents — the grid operator’s stakeholders are settling themselves into a lesser role.
Technical Advisory Committee members discussed weighty issues such as ERCOT’s use of emergency response service (ERS) and how to handle priority revision requests from regulators, but they did not take any votes to resolve the issues.
Leading the meeting in Chair Clif Lange’s absence, TAC Vice Chair Bob Helton set the tone when he recapped the board’s August meeting, during which the directors overturned the committee’s reduction of counterparties’ unsecured credit limit to $30 million. Instead, the board eliminated unsecured credit limits, leaving ERCOT as the only U.S. grid operator without a cap.
“With that, I believe [the board] made it clear with the way the protocols are going to go is that we, as TAC and stakeholders, are an advisory function only, and not a control or authoritative function above the stakeholder process,” Helton said during the Sept. 28 meeting.
Referring to TAC as “the collective wisdom of the market,” Golden Spread Electric Cooperative’s Mike Wise said during the conversation over priority requests that the committee needs to point out the unintended consequences in any revision requests it considers.
“We have to highlight those unintended consequences and do it in a passionate way, potentially to get the attention of those who do have the ability to make decisions, those that are in authority,” he said. “We have in this case really no authority. Not limited, but no authority. And that means that this group right here has got to really engage and get to do so in an articulate way to get the attention of the decision-makers.”
Legislation passed in the wake of last year’s winter storm removed market participants from the ERCOT board. It also required the independent directors be Texas residents, eliminating potential candidates with deep market experience from across the country.
Reliant Energy’s Bill Barnes, wearing a bow tie “to reflect the occasion,” referred to Greer, known for his opposition to ERS and for being willing to let everyone know, as one of TAC’s “OGs” (original gangstas).
“Here at TAC, we honor those that have made extraordinary contributions to our process and to our market design,” Barnes said. “Our meetings will now be much more efficient and faster without Clayton’s participation.”
Several TAC members and their companies sponsored a BBQ spread after the meeting and a pair of cakes with the Drake meme, showing the rapper turning away from ERS but liking real-time co-optimization, a market mechanism still years away from implementation. A promised dunk tank “sponsored by a coalition of ERS providers” failed to arrive.
Greer, who participated in the meeting as an observer, couldn’t resist getting his own digs in. During a discussion on ERCOT’s ERS deployment practices, he said, “I just wanted to first thank you guys for having this today, because it certainly entertains me. I get that this is an antique program and we inherited it after a bad event in 2006, but it’s time to revamp it.”
Turning serious, Greer told members it was an honor to have served on TAC for two decades and offered support for the committee’s new dynamic with the board.
“Over the last 20 years working on TAC and working with some of the brightest people in the industry, the faces may change, but the mission never did,” he said. “It’s always to provide the best product, market design and reliability design, and I think we did that. If you ask any of the traders, they always want to trade ERCOT; it’s one of the most liquid markets out there. And I think that’s a testament to how well this body works.
“In the past, we’ve always had the stakeholders on the [ERCOT] board, so there was always that knowledge on the board,” Greer added. “I think the new board members are really eager to understand how the market works and why a lot of these decisions are made because sometimes, that’s opaque. Usually there’s an underlying reason why things are the way they are [and] why they’ve been the way they’ve been for the last 10 years, and helping those guys understand that, I think, it’s one of the goals to this body.”
Members honored Greer with a standing ovation before adjourning for lunch.
TAC Approves 10 Change Requests
The committee approved, separately and as part of the combination ballot, 10 revision requests and a list of the system’s 258 major transmission elements.
Luminant voted against a nodal protocol revision request (NPRR1084) that would allow ERCOT to publicly provide information about resources’ forced outages, forced derates and start-up loading failures in a more complete and timely manner. The generator said it had concerns it wouldn’t be able to comply with the change without an update to the outage scheduler. The NPRR passed by a 26-1 vote, with two abstentions.
Shell Energy abstained from NPRR1058, which passed 29-0. The NPRR would require quicker updates by qualified scheduling entities to the telemetered resource status, high sustained limit (HSL), and other relevant information, improving the physical responsive capability calculation’s validity and dispatch.
The combination ballot included four NPRRs, two revisions to the Nodal Operating Guide (NOGRRs) and two system change requests (SCRs), which if approved by the board would:
NPRR1118: clarify the outage schedule adjustment (OSA) process to improve the terminology and clarifies the process for issuing advanced action notices and OSAs, and to clarify offer submission and reliability unit commitment (RUC) procedures after an OSA is issued.
NPRR1127 and NOGRR241: clarify which entities are required to have hotline and 24/7 communications with ERCOT, and requires those entities answer each hotline call to proactively ensure situational awareness during emergency situations.
NPRR1139: replace the usage of the wind-powered generation resource and photovoltaic generation resource productions with the HSL of an intermittent renewable resource as reflected in the current operating plan.
NPRR1140: permit generation resources to recover their fuel costs when instructed to start because of a RUC and operate above the resource’s low sustained limit.
NOGRR242: update references from point of interconnection to point of interconnection bus.
SCR820: build on the hotline communication process by developing a web-based platform supporting real-time, bidirectional, “send-review” messaging between ERCOT operators and transmission operators during emergency event coordination.
SCR823: request that ERCOT process (upload) a flat file received by ERCOT from each affected transmission/distribution service provider (TDSP) that contains all the TDSPs’ electric service identifier (ESI), besides retired ESIs. This flat file would allow all retail electric providers to have county names associated to all ESIs on the very first day following Texas SET V5.0 production go-live through the TDSPs’ ESI extract that is produced daily by ERCOT.
The Inflation Reduction Act (IRA) could provide New York with up to $70 billion in energy incentives and reduce the cost of meeting state emissions goals by almost the same amount, the state’s Climate Action Council (CAC) heard last week.
The CAC’s Sept. 29 meeting featured progress reports from two of its three subgroups and a presentation of an analysis on how the recently signed IRA will impact New York’s climate goals, embodied in the Climate Leadership and Community Protection Act (CLCPA).
Carl Mas, director of NYSERDA’s Energy and Environmental Analysis Department, shared results from an integration analysis that estimated that the IRA could provide New Yorkers with up to $70 billion in incentives, reduce the costs needed to meet CLCPA requirements by $43-$68 billion and increase the net benefit from climate mitigation by up to $50 billion.
The IRA, which was signed by President Joe Biden on Aug. 16, contains provisions that span the entire economy, driving the adoption of renewable energy and clean technologies while promoting energy efficiency and electrification. (See Biden Signs Inflation Reduction Act.)
The CAC requested an integration analysis of the IRA to better understand its overall impact on the state, examine sensitivities related to fuel prices and technology costs, and consider how implementation of the CLCPA might be affected.
The analysis explored two key aspects: estimates on how much money will be available to New York to offset CLCPA costs and what net benefits will be specifically provided to the state by those funds. Due to the breadth and size of the IRA, as well as remaining uncertainties about the legislation, the analysis was purposely conservative in its estimations.
The analysis estimated that $70 billion from the IRA will:
“tip the balance” toward more in-state wind energy;
lower procurement costs for innovative technologies, such as hydrogen;
reduce vehicle charging costs and encourage EV uptake;
reduce costs associated with transitioning buildings to more energy-efficient stocks; and
broaden the adoption of electrification across disadvantaged communities.
The net benefit analysis showed that $50 billion will flow toward “the execution of future solicitations” and increase the overall benefits provided by the CLCPA by “drawing co-funding from outside of New York State,” while raising New York’s “storyline” around climate action.
Mas also shared how the IRA will impact sensitivities around fuels prices and future clean technologies.
The analysis showed there will continue to be “upward pressures on fossil fuel prices” and that if costs for clean technologies unexpectedly rise, those costs will be passed to consumers who will then take longer to adopt them.
Mas noted that the findings underscore “the value of [New York’s] transition to renewable energy as a way to buffer New Yorkers against future uncertainties.”
He pointed out that the IRA will help insulate disadvantaged customers from these uncertainties by encouraging rapid adoption of clean energy because the law contains “explicit provisions dedicated towards low-income communities.”
Mas concluded by saying that evidence continues to show that the “net benefits from decarbonization” exceed the “net costs from inaction” and the IRA will be a key element in achieving New York’s climate and energy goals.
NYSERDA plans to appear before the CAC in October to share the IRA’s impact on the building sector and distribution system.
Gas Transition
Jessica Waldorf, director of policy implementation at the Department of Public Service, shared key considerations that Gas Transition subgroup members say should be included in the scoping plan to help guide New York’s gas system transition.
The subgroup recommended that plans be developed for how “individual gas utilities and local distribution companies will reduce their emissions by 2030 and 2050,” to both “mitigate impacts on remaining gas customers as other customers transition to alternative heating methods” and ensure that customers can continue relying on these assets without facing “undue burden or cost.”
Additionally, the subgroup wanted the development of a detailed timeline that aligns with the scoping plan to help consumers and generators better understand when transitions will occur and how they can leverage new technologies.
The subgroup also emphasized that significant consideration be given to communities that the CLCPA has identified as being “historically underinvested.”
Waldorf noted that disadvantaged communities should be “prioritized” and that the subgroup felt strongly about the development of clear frameworks that ensure emissions reductions, maintain existing gas infrastructure during the transition and give greater scrutiny to investments in those communities.
The subgroup also emphasized that the state should make plans to ensure a just transition of the gas industry labor workforce by helping to provide reemployment opportunities to displaced workers.
The Gas Transition and other two subgroups, Economy-Wide and Alternative Fuels, were formed to “tackle the challenging issues before the CAC, where there was considerable difference of views among the members,” according to NYSERDA CEO Doreen Harris.
Economy-Wide
Jared Snyder, deputy commissioner for air resources, climate change and energy at the Department of Environmental Conservation, shared findings from an Economy-Wide subgroup analysis that supports New York implementing a cap-and-invest program.
Proposed cap-and-invest design for New York. | New York State Climate Action Council
The subgroup evaluated three economy-wide strategies identified in the draft scoping plan: a carbon tax, a cap-and-invest scheme, and a sectoral clean energy supply standard.
The subgroup detailed how a carbon tax “places a price directly on emissions of greenhouse gases” while a cap-and-invest approach “places a cap on the emissions and then markets allocate the emissions reductions through the sale of those allowances in auctions.” A sector specific clean energy supply standard places limitations on fuel standards to regulate bulk emissions in specific industries.
Based on the subgroup’s analyses, most members concluded that a cap-and-invest policy was best suited for New York. The subgroup preferred the strategy because “it places a cap on the emissions that could be designed to meet emissions limits that were required to achieved CLCPA goals.”
The subgroup said cap-and-invested would be a “strong mechanism” because it “ensures all emissions in the state are contributing to the CLCPA goals,” and crucially showed interactions between allowance budget and non-allowance budget sectors. Furthermore, the policy would address climate justice by enabling price certainty through the creation of price floors and placing penalties on producers exceeding their cap levels.
Although the cap-and-invest would theoretically cover the entire economy, the subgroup carefully noted that in cases where certain “sectors cannot be easily reached, the state would retire allowances on their behalf and the remaining allowances would be auctioned or distributed according to legislation.”
CAC members expressed concern about some of the proposed language around these policies, but the subgroup countered that each policy raised “open questions” and that the remaining weeks will be used to address concerns.
Next Steps and Other Details
The CAC will reconvene on Oct. 13 to cover any remaining details related to the draft scoping plan and then plans to spend November discussing redlines of interest to the plan, which will likely be subject to a formal vote by the CAC at its Dec. 19 meeting.
The CAC also voted to approve a bylaw amendment that would allow for the adoption of videoconferencing attendance for CAC members in extraordinary circumstances, except for executive sessions.
ISO-NE violated its tariff in its handling of construction delays at a Boston-area generating plant, FERC said, slapping the RTO with a $500,000 fine.
In an orderissued on Friday, FERC agreed to a settlement requiring the grid operator to boost its compliance program for making capacity payments to the New Salem Harbor Generating Station before it had started operating or even finished construction (IN18-8).
ISO-NE has repeatedly denied wrongdoing and called itself the victim of fraud. But FERC made clear in its order that they believe the grid operator played a role in encouraging the Salem Harbor developers to present misleading information about when the project was expected to be finished.
The gas-fired combined cycle generation plant had a planned commercial operation date (COD) of May 31, 2016, when it cleared the RTO’s Forward Capacity Auction In 2013. It was awarded a capacity supply obligation of 674 MW for the delivery year beginning June 1, 2016. FERC noted that the plant, which went into operation in June 2018, was the first new merchant generating resource to clear in ISO-NE’s FCA.
ISO-NE’s Violations
The FERC settlement lays out a detailed paper trail showing that ISO-NE failed to meet its duties under its tariff as the project was in development.
As likely delays popped up, Salem Harbor Power Development repeatedly provided information to ISO-NE about changing milestone dates, which should have led the company and grid operator to put forward a new commercial operation date, FERC found.
Instead, ISO-NE staff encouraged the developer to maintain May 31, 2017, as the COD. ISO-NE’s former director of resource adequacy did so explicitly to avoid triggering the automatic submission of a demand bid in the reconfiguration auction (ARA3) and forcing the company to give away its full capacity supply obligation, FERC said.
ISO-NE also violated its tariff by failing to submit a demand bid and submitting an inaccurate qualified capacity value, FERC’s Office of Enforcement found.
ISO-NE employees had enough information to know that they should have qualified it for 0 MW, FERC said.
Instead, the facility was qualified at 674 MW, which helped it earn more than $100 million in fraudulent capacity payments.
And finally, FERC found that ISO-NE restricted the access of its own Internal Market Monitor to capacity market data, including the narratives filed by the project’s developer, as the situation was unfolding.
“Enforcement concluded that System Planning’s conduct not only violated the tariff, but also frustrated the IMM’s key market oversight role,” the order reads.
ISO-NE spokesperson Matt Kakley said that since the incident, the organization has “taken steps to ensure that no one staff person can take such an action.”
And he noted that the Monitor was still able to obtain the information needed even while access to the data was curtailed.
An Intentionally Light Fine
ISO-NE did not admit or deny the violations put forward by FERC, but it agreed to a $500,000 civil penalty and $350,000 worth of compliance improvements.
Those include expanding a portal for employees to anonymously report potential violations, a new training module on tariff compliance and the role of the Monitor, and compliance monitoring by FERC.
“We recognize that a larger civil penalty might otherwise be appropriate given the magnitude of the capacity payments that ISO-NE made to Footprint,” FERC wrote in its order. “However, such a penalty likely would be passed on to the fee-paying entities, potentially compounding the harm to those entities and undermining the deterrent value of a larger civil penalty.”
ISO-NE acknowledged the possible harm to ratepayers too, by saying that its executives will pay the fine.
“ISO New England’s senior management takes responsibility for the ISO’s role in this matter. Therefore, the financial penalty outlined in the settlement agreement will be paid through a reduction in executive compensation,” the grid operator said in a statement.
Kakley said that will come in the form of a pro rata reduction, and that it will be made public in the form of the RTO’s financial reporting.
ISO-NE Response
The grid operator maintained a defiant tone in its statement on the settlement, saying that the events were precipitated by “Salem Harbor Power Development’s failure to provide accurate and complete information to ISO staff.”
But ISO-NE also recognizes that the investigation “revealed inadequacies in the market rules and our internal controls, and areas where better judgments could have been made.”
It has since changed capacity market rules to include an automatic financial penalty for resources that are behind in their development, and worked to “foster increased information exchange among internal groups.”
The issue of project delays wreaking havoc on the capacity market has not gone away. The results of this year’s capacity auction were significantly delayed while ISO-NE waited for FERC and the D.C. Circuit Court of Appeals to settle litigation over Killingly Energy Center, which had its capacity supply obligation pulled by the grid operator because of its failure to meet milestones and stay on track for its COD. (See ISO-NE Announces Capacity Auction Results After Killingly Delay.)
The New Jersey county of Cape May asked the state Board of Public Utilities (BPU) on Thursday to slow the approval process for an easement to run power cables from the state’s first offshore wind project — Ocean Wind 1 — across county land until federal environmental studies are completed.
Michael J. Donahue, representing Cape May County | New Jersey Board of Public Utilities
Michael J. Donahue, a lawyer and former state superior court judge representing the county at two online BPU hearings, said the federal environmental impact study could provide information that is relevant to whether the cable route is feasible or not.
Donahue, who said he also represents 10 of the 16 communities in Cape May County, also urged the BPU to consider alternative routes more acceptable to area residents, many of whom oppose the project.
Danish developer Ørsted is seeking BPU approval for an easement to run cables bringing energy from its Ocean Wind project to a substation that would tie the project to the grid. The developer’s favored route runs through the Jersey shore community of Ocean City, which is in Cape May County.
The case is related to but separate from Ørsted’s petition for an easement running across public land in Ocean City, which the BPU approved on Wednesday. (See NJ BPU Approves Easement Plan for 1st OSW Project.)
Ørsted’s second petition also seeks BPU consent for the developer to obtain several environmental and other permits needed to get project approval from the New Jersey Department of Environmental Protection (DEP).
The case is the second test of a controversial law (S3926) enacted in July 2021 that allows offshore wind developers to site power cables and equipment on public land regardless of local or state government opposition. If the BPU backs the easement and consents, the developer would not need approval from the county or Ocean City, which also opposes the project.
“The county is not trying to delay or obstruct,” Donahue told the hearing. “But we think it’s important that many of the issues that concern the people of Cape May County be given an opportunity to be heard.”
Donahue said the county had had “discussions over a long period of time” with Ørsted about the project, including an attempt to “modify the impacts, especially in terms of cluttering the horizon.” But the two sides failed to reach an agreement, he said.
“We urge the board, as Ocean City has, to wait for those federal environmental processes to be completed so we don’t have the prospect of having to do all this all over again,” Donahue said. The proposed route could jeopardize sensitive marshes and impact area historical sites, he argued, and it could “conflict with many utilities that already exist” in the area, including sewer, gas and water main lines.
Negative Impact
The 1,100-MW Ocean Wind project, which the BPU approved in 2019, was the first of three offshore wind farms approved by the state to date. The BPU expects to follow the approval of the 1,148-MW Ocean Wind 2 and the 1,510-MW Atlantic Shores in 2021 with a third solicitation for 1,200 MW in the first quarter of 2023. (See NJ Seeks Stakeholder Input for 3rd OSW Solicitation.)
The projects are part of Gov. Phil Murphy’s goal, signed on Sept. 21, that the state have in place 11 GW of offshore wind capacity by 2040. That goal replaced Murphy’s earlier goal of 7.5 GW by 2035.
The Bureau of Ocean Energy Management issued a draft environmental impact statement (EIS) on Ocean Wind 1 on June 22, with comments due by Aug. 23. The draft found that the project would not have major impacts on most of the 19 environmental and related categories scrutinized.
But the 1,408-page report did find that the construction and installation, operations and maintenance, and eventual decommissioning of the project would have major impacts on marine navigation and vessel traffic, as well as commercial and recreational fishing. (See BOEM Draft EIS Finds Potential Major Impacts from 1st NJ OSW Project.)
BOEM held three public hearings on the draft in July. The agency said that after it “addresses the comments provided,” it will issue a final EIS that will “inform” its decision to “approve, approve with modifications or disapprove the project.”
But federal approval is only one hurdle for Ocean Wind 1. Ørsted is seeking a 30-foot-wide easement running about eight miles along the length of Ocean City, a popular tourism and vacation area on the Jersey shore. The 275-kV line will connect the project’s turbines, about 15 miles offshore, to the PJM grid at a substation sited on a now closed coal-fired power plant in neighboring Upper Township.
At issue in the Cape May case is the project’s need for a temporary 18-month easement and a 30-foot-wide permanent easement across county land, both in Ocean City, the developer’s May 20 petition says.
The BPU’s approval of the Ocean City easement on Wednesday was a big step forward for Ocean Wind 1, allowing project cables to pass across land in Ocean City created with funds from the state Green Acres program, which pays to improve parkland and open space.
The case, which involves the same cable route as the Cape May County case, was the first test of the law granting the BPU power to override local officials on issues involving offshore wind projects. The law allows the BPU to do so — and grant approvals on projects — if the agency concludes that they are “reasonably necessary” to the project.
Madeline Urbish, Ørsted’s head of government affairs | New Jersey Board of Public Utilities
As in the earlier case, Ørsted argued that they are. Madeline Urbish, the company’s head of government affairs, told the hearing that the project needed the BPU’s approval to move ahead and meet New Jersey’s clean energy goals, after the developer had held fruitless discussions with Cape May County since 2019.
“Time is of the essence if the project is going to meet its commitment to New Jersey” and reach commercial operation in 2024, Urbish said.
“Cape May County has not been willing to reach the necessary agreements to allow the project to proceed,” she said. The county’s approval and permit consents are required for the project to secure approval from the DEP, whose blessing is needed in turn for the environmental review conducted by the federal Bureau of Ocean Energy Management.
Alternative Route
Donahue countered that in order to limit disruption and negative impacts from the transmission lines, the BPU should consider cable routes for two other offshore wind projects approved by the agency — Ocean Wind 2 and Atlantic Shores — at the same time as the route and easements for Ocean Wind 1.
Instead of running the cables through Ocean City, Ørsted could send them along an abandoned railroad or part of the Garden State Parkway, the main highway along the Jersey shore, he said.
More than a dozen speakers at the two hearings on Thursday opposed either the granting of the easement or the project in general. Many said they are Ocean City residents, and some were clearly upset by the BPU’s intervention in what they considered a decision that should be taken by local officials.
Ocean City’s business administrator, George Savastano | New Jersey Board of Public Utilities
George Savastano, Ocean City’s business administrator, questioned the legitimacy of the law and the “authority” of the BPU to make decisions on the easement issue. “It remains to be seen whether it will survive judicial scrutiny,” he said of the law, citing a section of the state constitution that, he said, states “any law concerning municipal corporations formed for local government or concerning county shall be liberally construed in their favor.”
Savastano also argued that Ørsted’s designation of several alternative routes for the cable means that the chosen route through Ocean City is not “reasonably necessary.” That question is enough reason for the issue to be heard by an administrative law court, rather than the BPU, he said, and urged the agency to send the case to the court.
At a hearing on the first easement case in June, Ocean City called on Ørsted to choose a route that would avoid the municipality and instead send the cable through Great Egg Harbor Bay, coming on shore close to the substation in Upper Township and avoiding Ocean City altogether. Cape May County also supports that route.
Savastano said that the route through Ocean City is shorter, and so likely cheaper for the developer, who should, as a result, be required to divulge the cost of pursuing each of the available routes.
“Until and unless Ocean Wind discloses the cost of each of the alternate routes, the board cannot find that the easements and consents which Ocean Wind claims to need are reasonably necessary,” he said.
The BPU has said in the past that the cost of any of the routes is irrelevant to the discussion because it will be paid for by Ørsted and won’t be an expenditure of public money.
RWE Renewables Americas will acquire Con Edison Clean Energy Businesses in a deal valued at $6.8 billion.
Their parent companies, Consolidated Edison and RWE AG, announced the agreement Saturday. It is expected to close in the first half of 2023.
Con Ed CEO Timothy P. Cawley said in a news release that the move will allow the utility to concentrate on its core operations.
“The transaction we announced today will allow Con Edison to sharply focus on our core utility businesses and the investments needed to lead New York’s ambitious clean energy transition.”
Con Ed also said it will continue to invest in clean energy transmission projects, building electrification, energy efficiency, electric vehicle infrastructure, battery storage and other technologies.
Con Edison Clean Energy Businesses operates more than 4 GW of renewable energy projects in North America through its three primary subsidiaries, Con Edison Development, Con Edison Energy and Con Edison Solutions.
RWE, based in Germany, said the Con Ed acquisition will nearly double its capacity in the U.S., give it a broader geographic footprint and expand its project pipeline to include more than 24 GW of onshore wind, solar and battery storage.
RWE is also expanding its offshore wind development efforts to the U.S. Earlier this year, it and partner National Grid submitted a successful $1.1 billion bid to secure OCS-A 0539, the largest offshore wind lease in the New York Bight. It is also a partner in an 11-MW demonstration project planned to test floating turbines in the Gulf of Maine.
RWE’s CEO and CFO have scheduled an investor and analyst conference call Oct. 4. The company said in a news release that the acquisition is a milestone in its growth plans in the U.S., a large and fast-growing market for renewables that recently got a 10-year stabilizing boost in the form of the Inflation Reduction Act.
“The unique combination of complementary portfolios in onshore wind, solar and batteries creates one of the leading renewable companies in the U.S. market,” RWE CEO Markus Krebber said in a news release. “The combined development pipeline, one of the largest in the U.S., provides tremendous opportunities for sustainability and value accretive growth, backed by a strong financial position.”
RWE Renewables Americas has developed more than 3.8 GW of renewable capacity in North America since 2007.
Con Ed said the transaction is subject to customary closing conditions, including expiration or early termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 and approvals by the U.S. Committee on Foreign Investment and FERC.
The impact of growing power demand driven by the electrification of transportation and buildings is a key problem in the drive to decarbonize U.S. electricity that utilities and regulators must tackle, said Robert Rowe, president of NorthWestern Energy.
Robert Rowe, NorthWestern Energy | USEA
Speaking at an online panel on Friday sponsored by the United States Energy Association, Rowe said U.S. utilities have already made significant cuts in their carbon emissions, but new approaches are needed for regulation and, in particular, rate structures.
The industry needs to spell out its “absolute core goals — safety, reliability, resilience, flexibility, decarbonization … as simply as possible, measurably, and then look at the regulatory mechanisms in place and ask, ‘Do they advance these goals, or do they hold you back?’” he said.
According to the Clean Energy States Alliance, 21 states, plus D.C. and Puerto Rico, have adopted 100% clean energy goals, with deadlines ranging from 2032 to 2050. Many investor-owned utilities, including NorthWestern, have followed suit, committing to clean or net-zero generation, usually by 2050.
Jim Matheson, NRECA | USEA
NorthWestern is “working with others on the electric infrastructure to support [electrification], whether its fleet electrification, personal vehicles, processes,” Rowe said. “There’s a lot of good in there, but the key is cost-effective electrification.”
Jim Matheson, CEO of the National Rural Electric Cooperative Association, argued that President Biden’s 2035 clean electricity goal may not be achievable “without severely compromising the reliability of the electric grid.”
“We think you have to have some form of always-available power,” Matheson said. “It could be nuclear; it could be coal; it could be natural gas. But in a situation where we need more electricity, the question is — how much of the portfolio can be an intermittent resource?”
More time, more advanced technologies and way more transmission will be needed, he said.
Bridge to Bankability
Jigar Shah, director of the Department of Energy’s Loan Programs Office (LPO), sees the challenge in terms of technology “liftoff”: the billions in upfront investment needed to bring new technologies to market.
Jigar Shah, DOE Loan Programs Office | USEA
The LPO’s $465 million loan to Tesla in 2010 — and the company’s payback of the money ahead of schedule — was critical in the electric vehicle manufacturer’s buildout of its Gigafactories and the growth of the now booming EV market in the U.S.
But, Shah said, a range of industry analyses show “there are 20-plus sectors that have to cross the bridge to bankability and reach full market acceptance for us to have a chance of meeting the 2035 goals the president has set down, and right now, those 20 sectors have not crossed.”
It takes about $100 billion in investments to achieve bankability, Shah said. While he sees momentum and growing interest in hydrogen, “in sector after sector, there is an assumption that the commercial markets are ready to go, but I think, in general, they’re really only interested in solar, wind and some battery storage.”
Rowe added that beyond technology risk, developing the ecosystem of supply chains, workforce and permitting will layer on more uncertainties. “Getting all those pieces together, like every transition, it’s messy; it’s complicated; it takes longer than you might have thought at the start,” he said. “But when you look back, you may have accomplished more than you actually did.”
David Naylor, Rayburn Electric Cooperative | USEA
Having a diverse generation portfolio and finding ways to leverage existing transmission and distribution systems were seen by other speakers as familiar, low-risk strategies to move decarbonization forward in the near term.
David Naylor, president and CEO of Rayburn Electric Cooperative, a transmission and generation cooperative in northeast Texas, said his co-op is going “low-tech” by upgrading its conductors “to utilize existing rights of way but get more throughput.”
At the same time, the co-op plans to increase its use of renewable power, from 5% in 2020 to 31% by 2025, according to its website. Other electric cooperatives, which often don’t have to obtain the regulatory approvals required of IOUs, have adopted more ambitious clean energy goals.
New Mexico’s Kit Carson Electric Cooperative this year hit its goal of providing 100% of its daytime power from solar, while keeping rates low.
Grid Management 2.0
Energy efficiency and demand response will become integral tools in grid management and modernization, but Rowe sees a potential obstacle in designing electric rates that encourage grid efficiency.
“Does it make sense to pay for that [efficient] infrastructure volumetrically?” he said. “It’s a little bit like you’ve got one foot on the brake — efficiency — and one foot on the accelerator — volumetric pricing — and you need a one-pedal operation. Where do you try to harmonize?”
Demand management will also be critical for integrating power to meet the increasing demand from EVs, said Matthew Lind, director for industry consultants 1898 & Co., a part of Burns & McDonnell.
He pointed to efforts by Edison Electric Institute to “bring together the electric retail provider and technology companies to develop different kinds of strategies. Demand response and time of use are necessary, but not sufficient. … The size of the resource, the ability to access that resource is going to vary pretty tremendously from area to area, depending on the nature of the demand.
Matthew Lind, 1898 & Co. | USEA
“The ability to curtail that demand on the electric side may be challenging as we further electrify other sectors of the economy,” Lind continued. “But diversity of technologies — demand response being one of those technologies — will allow for reliability and, hopefully, affordability as we make this transition.”
Rowe also cautioned that demand growth encompasses more than capacity. “Even using relatively conservative assumptions about growth, there are some significant capacity challenges on our system, and if growth exceeds that, then we have to redouble our efforts,” he said. “Capacity is not simply a supply concept. It’s how much reserve, how much [flexibility] do you need in all aspects of your system, and what’s the cost and what’s the value of that?”
Shah foresees transportation electrification driving a more radical transformation. Citing figures from Wood Mackenzie, he predicted that by 2030, the U.S. would have about 100 GWh of utility-scale storage on the grid. He also estimated that batteries in passenger and other light-duty EVs could provide as much as 800 to 850 GWh of storage.
“To suggest that this is something other than a mainstream grid operations exercise is ridiculous,” he said. “This will literally become the next way you manage the grid; even if you decide not to pull any power out of the [EV] batteries, that’s V2G [vehicle to grid]; even if you just do managed charging.
“I just think that people are using the model of last year to predict the model of 2030, and they’re just getting it woefully wrong,” he said.
‘Do Big Things’
The energy transition in the U.S. has hit a push-pull stage.
The Infrastructure Investment and Jobs Act and the Inflation Reduction Act provide strong support for clean energy buildout, such as the IRA’s direct-pay provisions that for the first time allow co-ops and municipal utilities to access a range of clean energy tax credits.
But 20 states now have laws prohibiting local jurisdictions from banning natural gas hookups in new construction, and six more are considering similar laws, according to S&P Global.
Rowe said conservative states, like the three in NorthWestern’s service territory, prioritize reliability and affordability and make investments in decarbonization based on those priorities.
“I am very uninterested, deeply uninterested in the kind of polarizing discussions where everybody takes their ideological position,” he said. “On the other hand, everyone is truly concerned about the various severe weather events, truly concerned about resilience. … I wish we could find a broad space where we can agree, and then focus on the most efficient ways to get there.”
Shah sees electrification as an unstoppable process. Banning bans on natural gas hookups may slow but won’t stop the shift to air- and ground-source heat pumps, he said, noting that they are now being installed in 38% of new homes, according to the National Association of Home Builders.
“You don’t replace natural gas in these applications through sacrifice; you replace it through better technology, and people generally like heat pumps a lot better than using natural gas for heating,” he said. “Now we’ve got to train HVAC contractors; we have to train the supply chain. We have to do all the hard work to make sure the transition occurs, and consumer preferences are honored.”
The speed of the energy transition and demand growth, and the need for the industry to stay in front of both will be a core challenge moving forward, he said.
“People have been used to being able to just use their existing infrastructure for longer without really thinking about how to add more infrastructure, but America’s got to be able to do big things again,” Shah said. “We have the right people; we have clearly all the technology, and the question becomes how do we really do big things again? We know how to do this; it’s a human issue around how we move faster, how we move more confidently and then how we export those solutions to the rest of the world.”
Lordstown Motors (NASDAQ:RIDE) announced late last week that the first two of 50 electric pickup trucks it plans to produce and sell this year had rolled off the assembly line at the former General Motors production plant in northeast Ohio.
But the future of the Endurance model and the company is still in question.
The sprawling factory is now owned by Taiwanese manufacturer Foxconn, which agreed to assemble the Endurance when it bought the 6.2 million-square-foot plant in 2021 for $230 million.
Foxconn is also planning next year to begin manufacturing a small electric car, the PEAR, designed by Fisker. The company has also announced plans to produce an electric tractor in the facility for a small California startup.
Lordstown said in a statement that the 50 trucks it expects to deliver to customers this year are “part of the first batch of up to 500 saleable vehicles we intend to build.”
“We will continue to build at a slow rate as we address remaining part pedigree and part availability issues. We expect to increase the speed of production into November and December,” CEO Edward Hightower said. The Endurance has been crash tested, but the results must still be certified.
The company also noted in a simultaneous filing with the U.S. Securities and Exchange Commission that its production and delivery schedule is dependent upon raising additional capital.
“We expect to deliver approximately 50 units to customers in 2022 and the remainder of the first batch in the first half of 2023, subject to raising sufficient capital,” it said.
The company expects to end the third quarter with “cash and cash equivalents of approximately $195 million” and would continue to explore “capital-raising alternatives,” including partnership discussions with Foxconn, according to the filing.
TEMPE, Ariz. — FERC Commissioners Mark Christie and James Danly spoke last week about the West’s pursuit of greater regional coordination, with Christie praising the region’s “organic” efforts to form one or more organized markets and Danly warning against RTOs that fail to promote competition and reliability.
The commissioners made their comments at the fall joint meeting of the Committee on Regional Electric Power Cooperation and the Western Interconnection Regional Advisory Body, where CAISO, SPP and the Western Power Pool (WPP) pitched their planned market and reliability programs.
CAISO is planning an extended day-ahead market (EDAM) for its real-time Western Energy Imbalance Market (WEIM). SPP launched its Western Energy Imbalance Service (WEIS) and is developing Markets+, a bundle of services that stops short of a full RTO. And WPP’s Western Resource Adequacy Program (WRAP) has attracted participants from across the Western Interconnection. It expects to begin a preliminary phase of operations soon as it awaits FERC approval.
“You’ve got a lot of options in the West now that are percolating up, and what characterizes every one of these options — the WEIM, the WEIS, the Markets+, the EDAM and [the WRAP] — is that these are all organic, that are coming from you,” Christie said. “FERC didn’t tell you, ‘Here it is. Do it.’ They’re being developed by you … to meet your needs, and I think that’s what’s so exciting. I’m a big believer in organic, evolutionary change [that is] bottom-up … and not being forced down from FERC.”
Christie recommended Western stakeholders look at “another organic development,” the Southeast Energy Exchange Market (SEEM), an automated bilateral 15-minute market set to launch later this year.
What’s important to recognize, he said, is that the West does not have to choose between no cooperation and an RTO.
“That’s not the binary choice that you face,” Christie said. “There are a lot of points on the continuum, and it’s for you to pick and choose what points makes sense for you.”
Christie, a longtime utility regulator in Virginia before he joined FERC, urged Western regulators to protect the public’s interests when considering their utilities’ plans to join organized markets.
Oregon PUC Commissioner Letha Tawney, who shared the stage with Christie and moderated the discussion, asked how state regulators could balance their roles of making neutral decisions on regulatory matters before them and advocating for the public’s interests when dealing with organizations such as CAISO, SPP and WPP.
Christie, a founding member of the Organization of PJM States Inc. (OPSI), said a “critically important topic” would be whether to form similar advocacy committees of state representatives in the West.
“It is unrealistic to think that states are not going to be cooperating and working with your fellow state regulators,” he said. “I mean, whatever you choose in the West — whether it’s just an energy market, an energy market plus a day-ahead market, [or a] full RTO with all the bells and whistles — whatever you choose you really need an organization like OPSI” empowered to have an advocacy role.
Governance and cost-allocation are among the issues sure to be argued over, he said.
“Cost allocation in a multi-state RTO with radically different [state] policies is an extremely difficult nut to crack,” Christie said. “And you all are sitting out here in the West … [where] every state not named California has a concern about who gets to appoint the board.”
Danly Speaks
In a separate session, Danly warned that joining an RTO could have significant drawbacks, especially if the RTO cannot ensure it has adequate resources or fair competition.
“I often think that people are not quite perfectly aware of the costs and benefits that market participation has,” Danly said.
“There are undeniable benefits that the markets have delivered,” he said. “They have driven costs for power down. There are efficiencies of scale that are so attractive that even those regions that do not want markets have, as in the case of SEEM, tried to capture as many of those benefits as they can. And that may well be the model that’s used going forward, that people creep right up to the line of a full-on RTO but don’t quite cross that threshold.”
Even so, the costs of joining a market can be “multiple,” Danly said.
“My admonition to any state or utility that’s contemplating joining markets in the West … [is that] you to do it with your eyes fully open,” he said.
A frequent CAISO critic, Danly pointed out the ISO’s problems as recently as last month in maintaining resource adequacy during summer heat waves. On Sept. 6 the utility declared a stage 3 energy emergency, instructing utilities to arm for load shed. It narrowly averted rolling blackouts after the California Governor’s Office of Emergency Services sent out a text alert to millions of cell phones telling residents to “conserve energy now” or “power interruptions may occur.”
The message reduced demand by 2,100 MW in 5 minutes, the U.S. Energy Information Administration said Wednesday.
CAISO has declared energy emergencies the past two summers and initiated rolling blackouts in August 2020.
“One of the biggest [drawbacks of organized markets] is what I think are the fairly evident failures of some of the markets to ensure resource adequacy,” Danly said. “And this is something that in the West you’re well aware of because of very recent experience in having had a squeaker with the hot weather in California [and] merely having made it through that with the lights on.”
Markets that incentivize and subsidize certain types of resources, lowering costs, impede the competition that makes a market work, he said.
“If you have a market structure that does not insulate itself correctly [from anti-competitive forces], then what you’re going to find, as we see for example in New England, is that the jurisdictions in which the market operates are acting to undermine the very premise of the market,” he said.
New England, long troubled by tight natural gas supplies in winter, is facing a more limited supply this year because of the war in Ukraine and the century-old Jones Act, which prevents foreign-owned tankers from bringing U.S. liquefied natural gas to domestic ports and forces New England to rely on Russian LNG.
“Markets, especially in the case of capacity markets, are there to ensure that a sufficient quantity of capacity is delivered,” Danly said. “That’s done by a series of auctions in which market incentives are supposed to draw people into delivering the quantity and type of resources necessary to ensure that the system remains stable and has enough electricity.
“And yet, when you have state policies enacted that serve to suppress capacity prices, then you find yourself short,” he said. “And right now, we have a market in the Northeast in which the market has told us in public, on the record, in a FERC tech conference that given the constraints under which it operates … it is not possible to use market mechanisms to ensure resource adequacy. That should be a chilling prospect for anybody who is considering participation in a market.”
If reliability is a problem in New England, where states “have similar and in-parallel public policy goals … I would just suggest that people imagine what it would be like to join a full FERC-jurisdictional RTO [in the West where] you would have a market that has to be the ultimate deliverer of services and guarantor of resource adequacy for states as divergent in their public policy goals as, let’s say, Oregon and Utah.”
