FERC on Monday approved two SPP revisions to its tariff that would provide load-responsible entities (LREs) with an alternative short-term, nonpunitive approach to deficiency payments for their summer resource adequacy requirements (RAR).
The commission accepted the RTO’s proposal specifying that LREs making the deficiency payments will be sufficient for the current year’s RAR (ER23-1216) and a second revision that adds a deficiency payment structure applicable in certain circumstances and based on a sufficiency valuation curve (ER23-1218). The revisions are effective May 2.
Deficient LREs that make the payment are essentially buying capacity needed to make it sufficient for the current year’s RAR from other entities with excess capacity, SPP said. It would then consider those LREs sufficient for the current year’s applicable requirement.
Both revision requests were approved in January by SPP regulators, stakeholders and its Board of Directors after months of trying to reach consensus. (See SPP Board/Members Committee Briefs: Jan. 31, 2023.)
FERC said the proposed revisions are just and reasonable and not unduly discriminatory or preferential. In the first order, it said SPP’s proposal clarifies the responsibilities for both LREs that make deficiency payments, and LREs or generator owners with excess capacity that receive revenues from those payments. The latter group cannot subsequently contract to sell any of that excess capacity being paid revenue distributions to any other entity in the grid operator’s balancing authority area during the applicable summer season.
“We find that this will ensure that SPP can rely on the designated excess capacity for the SPP balancing authority area during the applicable summer season,” the commission wrote.
The RTO said in its request that without an assurance from entities receiving excess capacity revenue that they will not subsequently contract that same capacity to someone else, the BAA could see increased reliability risk if that capacity is contracted and made otherwise unavailable for serving load.
The commission also found SPP’s proposed sufficiency valuation curve to be a “reasonable method” to estimate the value of excess accredited capacity needed to resolve LRE deficient capacity in the RTO’s footprint and to calculate LREs’ deficiency payments after a planning reserve margin (PRM) increase.
FERC agreed with the SPP’s Market Monitoring Unit that this valuation of deficient and accredited capacity is “commensurate with regional resource adequacy needs, without removing the long-term planning incentive of SPP’s current deficiency payment approach.”
It said SPP’s proposed sufficiency valuation curve eligibility criteria is reasonable because it specifies the circumstances under which a deficient LRE may rely upon the methodology following a PRM increase, while ensuring that an LRE unable to meet the prior PRM is not relieved from its obligations under SPP’s deficiency payment mechanism.
SPP increased its PRM from 12% to 15% last year. It developed a mitigation strategy to address members’ concerns that they wouldn’t have enough time to meet the new requirement. (See SPP Board of Directors Briefs: Dec. 6, 2022.)
Entergy (NYSE:ETR) told financial analysts Wednesday that it is investing to improve reliability and resilience and “significantly” expand its clean energy footprint.
“We’re working to improve operational and regulatory outcomes, support our customers’ industrial growth and economic development in our region, invest in renewable clean energy and resilience,” CEO Drew Marsh said during the company’s first quarter earnings call.
On Monday, Entergy’s leadership joined Texas Gov. Greg Abbott and four of the state’s five regulatory commissioners to break ground on the Orange County Advanced Power Station, which will use turbine technology and a plant layout that can support dual fuel capability for hydrogen in the future.
“That facility will ensure that we have moderate and reliable infrastructure to support existing customers and the rapidly growing customer base in our Southeast Texas region,” Marsh said. “The optionality helps ensure the plant’s long-term viability and creates improved energy security and operational flexibility for our customers.”
The 1.22-GW combined-cycle plant’s construction is expected to be complete in 2026. Texas regulators approved the plant last year.
Entergy reported earnings of $311 million ($1.47/share), compared to $276 million ($1.36/share) for the same period a year ago. The adjusted earnings were short of Zacks Investment Research’s projection of $1.36/share.
Entergy’s share price closed at $105.50 Wednesday, a loss of $2.26 for the day.
NextEra Beats Expectations
NextEra Energy (NYSE:NEE) reported better-than-expected results Tuesday of $2.09 billion ($1.04/share), up from 2022’s first-quarter net loss of $451 million (-$0.23/share).
The Florida-based company’s adjusted earnings of $0.84/share beat the Zacks consensus estimate of $0.75/share, the fourth straight quarter it has exceeded EPS expectations.
NextEra attributed the financial performance to a clean energy investment push that has protected it from natural gas price swings. The company says it is the first in history committed to moving past net zero to “real zero” — using only wind, solar, battery storage, nuclear, green hydrogen and other emissions-free sources.
Its NextEra Energy Resources subsidiary added more than 2 GW of new renewables and storage projects to its backlog during the first quarter, bringing the total to more than 20 GW. The company said its Florida Power & Light subsidiary increased its solar portfolio to 4.6 GW during the quarter, more than any other utility.
FPL’s recently filed 10-year site plan proposes to build nearly 20 GW of solar over the next decade.
“We believe the expansion of cost-effective solar and storage will provide a valuable hedge for our customers against volatile natural gas prices,” NextEra CFO Kirk Crews told investors.
NextEra’s stock price closed at $74.076 Wednesday after trading after hours on Monday at $79.10. The price is down 11.6% since the year began.
Global electric vehicle sales are expected to hit a record 14 million this year, up from 10 million in 2022, the International Energy Agency said Wednesday in its Global Electric Vehicle Outlook.
The EV share of the global market has grown from 4% in 2020 to 14% last year and is expected to hit 18% this year.
“Electric vehicles are one of the driving forces in the new global energy economy that is rapidly emerging, and they are bringing about a historic transformation of the car manufacturing industry worldwide,” IEA Executive Director Fatih Birol said in a statement.
The growth in EVs has significant implications for oil demand, as IEA expects they will avoid the need for 5 million barrels of oil per day by 2030. IEA reported earlier in the month that global oil demand is expected to average a record 101.9 million barrels per day this year.
China, Europe and the U.S. are the three leading markets for electric vehicles, with China being the clear front-runner, making up 60% of global sales. Europe is the second-largest market, but the U.S. grew faster last year at 55% compared to 15% in Europe.
China is home to more than half the EVs on the road, with a total of 13.8 million; the IEA credits its manufacturing dominance to more than a decade of strong policy support for early adopters. Electric cars made up 29% of China’s domestic market, beating its 2025 goal of 20% of sales. Sales spiked in China last year because incentives were winding down, but they were still 20% higher in the first quarter of this year compared to a year earlier.
Both the EU and U.S. enacted major policies expected to ramp up their industries, with IEA saying all three markets should see total sales rise to 60% of their domestic markets by 2030.
The U.S. saw EV sales increase nearly 55% to 800,000 last year despite an 8% decrease in overall new car sales. Tesla has dominated the EV market historically, but competition is coming from other manufacturers such as General Motors and Ford.
The U.S. market is expected to continue to grow thanks to the Inflation Reduction Act, which has prompted $52 billion in domestic supply chains. About half those investments are for battery manufacturing, and 20% each covers battery components and EV manufacturing.
“While these investments can be expected to lead to high growth in the years to come, the impact may only fully be seen from 2024 onwards as plants come online,” said IEA.
Policy requirements were an important driver for electrification in the early years, but IEA said it has become increasingly important for major automakers to start rolling EV models to capture market share and maintain a competitive edge.
The report said that battery manufacturing projects around the world are more than enough to meet the ramped-up production of electric vehicles by the end of the decade. Battery manufacturing remains concentrated in China, which dominates production of batteries and other components.
Lithium demand exceeded supply, despite the 180% increase in production since 2017. Battery manufacturing last year took up 60% of global lithium supply, 30% of cobalt and 10% of nickel, when just five years earlier those shares were 15%, 10% and 2%, respectively.
“As has already been seen for lithium, mining and processing of these critical minerals will need to increase rapidly to support the energy transition, not only for EVs but more broadly to keep up with the pace of demand for clean energy technologies,” the report said. “Reducing the need for critical materials will also be important for supply chain sustainability, resilience and security.”
Demand can be cut by using new battery technologies, recycling, and setting policies that optimize vehicle battery sizes, the report said.
ALBANY, N.Y. — NYISO stakeholders discussed the merits and pitfalls of the ISO’s proposed phased window approach to fundamentally rework its interconnection study processes after it was presented in greater detail during the Transmission Planning Advisory Subcommittee’s meeting April 19.
After studying how to expedite its interconnection queue, which has experienced project backlogs and delays since New York passed the Climate Leadership and Community Protection Act in 2019, NYISO recently settled on a three-stage approach that would stack a group of overlapping projects into a queue window. (See NYISO Previews Plan to Expedite Interconnection Queue.)
Stakeholders were mostly receptive but still had many concerns about the proposal, including about its timelines and scheduling; penalties for leaving the queue; and whether certain studies in one phase might be more appropriate elsewhere.
NYISO will take stakeholder feedback from last week’s meeting and address them at the subcommittee’s next meeting on May 5.
Application Review Period
Thinh Nguyen, NYISO senior manager of interconnection projects, summarized the proposal.
“The queue window leverages all the class year processes,” but instead of performing studies at the end, after developers have made significant financial commitments, “it puts all the analyses upfront to be done together so developers can make more informed decisions,” Nguyen said.
Therefore, the critical first step in the queue window would be the application review period. This “pre-act” review would serve as a “project filter,” said Nguyen, because during this time, developers would submit site-control requirements and application fees, undergo initial modeling demonstrations and create their base cases, which are the starting points for any interconnection study, showing much about a project’s feasibility.
Proposed structure of the interconnection queue window approach (*boxes not at scale*) | NYISO
The idea is to enable developers to make important decisions about whether they want to enter or exit the queue without either facing withdrawal penalties or disrupting other potential projects in the queue window. Nguyen also said that the intention of this period is to validate a certain project application’s worthiness and if it can be considered in the interconnection study.
After submitting all required application materials and a nonrefundable application fee, developers would be able to submit a study deposit if they decide they want to proceed into the queue window.
Phase 1
“Phase 1 is similar to late-stage [Class Year] optional physical feasibility studies but is a more limited clustered study, rather than the individual studies as done today,” Nguyen said.
During this period, NYISO would review project design requirements provided by developers to determine a project’s feasibility, such as if existing infrastructure can physically accommodate the project or if it has environmental issues.
This would allow developers with projects identified by NYISO as having potential feasibility issues to decide whether they want to study this issue further or if it is enough to dissuade them from moving on.
Nguyen said Phase 1 “lets developers know if they may run into some problems,” so that they can decide to either exit the queue entirely or rejoin later in another window “without delaying other projects.”
Should a developer withdraw their project in Phase 1, NYISO would refund them 80% of the study deposit, though projects that move forward to Phase 2 and then decide to withdraw would forfeit the entire deposit.
At the end of this period, NYISO would publicly publish every developer’s decision so that others can understand how a given queue window or project could be affected.
Phase 2
Projects that pass Phase 1 feasibility requirements and posted relevant deposits would enter Phase 2, which is “almost like the system impact reliability study but with a twist,” said Nguyen.
Phase 2 would create binding cost estimates that are based on identified equipment and work upgrades necessary to interconnect a proposed project, which is unlike current processes that produce a nonbinding cost estimate.
Nguyen said Phase 2 is “tailored” to gives developers a “heads-up about some of their potential system upgrades that would be beyond the POI [point of interconnection].”
“This could be a step where we can streamline a lot of processes that we have today,” he said.
During Phase 2 the queue’s base cases would also be updated to reflect projects that were either rejected or withdrew during Phase 1 and the ISO performs limited analyses, such as short circuit, localized stability and screening deliverability analyses to generate useful information that reduces Phase 3 study times.
Developers who accept Phase 2’s results and project binding cost estimates would be required to post a project’s dollars-per-megawatt cash deposit before moving to Phase 3. Projects withdrawn during Phase 3 would see 25% of the cash deposit forfeited.
Like Phase 1, project decisions made in Phase 2 would be posted publicly by NYISO.
Phase 3
“Phase 3 is basically the final study for developers to know the certainty of their cost allocations,” Nguyen said.
During Phase 3, NYISO would update relevant base cases to reflect any projects that withdrew and perform any additional analyses needed to determine a project’s final cost allocation based on potential upgrades identified by the ISO.
Doreen Saia, an attorney with Greenberg Traurig, sought clarification, asking whether “Phase 3 is essentially becoming an additional deliverability study and additional SUF [system upgrade facility] study,” which Nguyen confirmed as correct.
Nguyen explained that the structure of NYISO’s proposal intentionally stacks projects together into a single queue window and staggers their study processes to “minimize the potential restudy or interaction between projects as much as possible.” This means, for example, a project might not commence Phase 3 studies until another project finishes its processes in the same window.
“The idea is that subsequent queue window projects will be able to consider upgrades identified in prior queue window projects,” which makes the queue “more manageable, because subsequent projects will know exactly who the group of projects prior to them are and what decisions they have to make,” he said.
Nguyen said that NYISO’s proposed “concept is much better than what we have today because when we studied projects individually, they had no idea what going on with other Class Year members … creating more uncertainty for those project developers.”
A developer who accepts their Phase 3 cost allocations would be required to post security for any system deliverability or facility upgrades necessary for interconnection to complete the queue window study process.
The Phase 3 decision-making period, like the end of the Class Year process, would be an iterative process that repeats until every queue window project member either accepts or rejects their cost allocations.
Stakeholder Comments
Stakeholders shared many concerns, both specific and general, about NYISO’s proposed revisions during last week’s meeting.
Several stakeholders commented that the proposed penalties incurred by developers withdrawing from the queue window may be overly burdensome, prohibitive and unequal, as bigger projects may be susceptible to higher fines than smaller ones. Some singled out the 20% for a Phase 1 departure as too high.
NYISO attorney Sara Keegan, however, said the amount is “consistent with other ISOs,” with SPP taking 20% from projects leaving at the end of its Phase 1 study. Nguyen said this is “a penalty that deters projects that are just not ready yet.”
Mark Reeder, representing the Alliance for Clean Energy New York, concurred, saying how he saw the 20% forfeiture “as the penalty for those starting and not being ready,” which to him seemed good because “we don’t want a lot of people jumping in and then out [of the queue] without a good reason.”
Vitaly Spitsa of Consolidated Edison asked what deliverables would come out of Phase 2 and whether, by this point in the process, developers would have access to sufficient information to make critical decisions about moving ahead in the queue.
Nguyen said that by the end of Phase 2, “developers will know exactly what the potential cost is of their binding POI” and about any necessary upgrades, which “definitely isn’t all the information but is sufficient information for a developer to make a decision about whether they want to move to the next phase.”
Anthony Abate, lead energy market adviser with the New York Power Authority, said NYISO’s illustrations of its queue window were “deceptively simple” and that “the devil’s in the details,” referencing how lengthy discussions during the meeting show that stakeholders need more information about the structure and timeline of the proposal.
Although much of the meeting was spent answering stakeholder questions or addressing comments of concern, some attendees expressed optimism about the ISO’s proposal.
Shane O’Brien, senior director with Aypa Power, said “from the developer’s side, this is a step in the right direction,” because NYISO’s proposal addresses “administrative inefficiencies” and “those downtime wait periods” where developers may be waiting for others before they can make their own decisions.
However, a remark by Saia seemed to best capture the sentiment among the stakeholders present at the meeting.
In reference to how NYISO’s proposal would remove much of the Class Year studies, such as the system impact reliability study or siting and permitting processes, Saia said, “We must make sure that whatever we do in this new process, [former] processes align, because if they don’t, then it’s great that you fixed this, but it’s going to create discordance somewhere else that causes the whole thing to die under its own weight.
“NYISO needs to indicate that you acknowledge and recognize [these concerns] because I don’t think you’re going to be able to get any real signoff on this without those assurances,” she said.
EPA is reportedly poised to propose rules that would require all coal and gas-fired power plants to reduce or capture nearly all of their carbon dioxide emissions by 2040.
The New York Timesreported Saturday that EPA plans to release a rule that for the first time would set limits on carbon dioxide emissions from existing power plants.
The pollution limits would not be technology specific, allowing natural gas plants to either capture their carbon, or switch to “green” hydrogen that is produced without carbon emissions, according a report in the Times that was largely confirmed by The Washington Post.
While carbon capture has proven expensive on power plants, recent federal legislation, including the Infrastructure Investment and Jobs Act and the Inflation Reduction Act, have set up a comprehensive framework that should enable the wide-scale deployment of carbon capture by 2030, the Carbon Capture Coalition said Monday in releasing its 2023 Federal Policy Blueprint.
The IRA increased federal tax credits for electric utilities that capture their carbon dioxide from $30 to $50/ton of CO2 to $85 to $135.
At a press event announcing the blueprint Monday, the coalition’s Executive Director Jessie Stolark said its wide-ranging membership has not had a chance to coordinate a response to the reported regulations yet. The group has focused mainly on market-incentives to encourage carbon capture technology, she added.
“I really want to underscore that our members agree that deploying carbon capture technologies in the power sector is absolutely critical to reducing emissions, as well as providing a more affordable, reliable baseload power and a deeply decarbonized energy grid,” Stolark said.
Shannon Heyck-Williams, vice president of climate and energy for the National Wildlife Fund, who participated in the coalition event, said her group welcomed news of EPA’s plans.
“WF is very excited to see this rule come out,” she said, saying CCS technology could have a role to play with some natural gas plants. “Obviously, we can’t adequately tackle climate change unless we’re really dramatically reducing power sector CO2 emissions. And, frankly, we could get to zero. That’s the goal.”
In response to EPA’s request last year for comments on how it should handle emissions from “electric generating units,” the Edison Electric Institute spelled out a way that it said could encourage cuts without mandating specific technologies.
EEI noted that for now the main way to cut emissions from power plants is to make them more efficient, with both hydrogen and carbon capture technologies not quite ready for mass deployment.
“Both hydrogen co-firing and CCS technology face a number of other challenges that will need to be overcome to enable commercial scale use throughout the industry,” EEI said. “Government and industry are investing in addressing these cost, technology, and infrastructure challenges. With that investment, there is reason to be optimistic that these challenges will be overcome in this decade.”
EEI argued that any new rules should be flexible, saying that hydrogen and carbon capture might work in some regions of the country but be infeasible in others. The agency should allow new power plants to retrofit those technologies when they become viable.
EEI also suggested that the agency would benefit from shifting to mass-based tonnage requirements for regulated units. Previous emissions rules have used a rate-based system.
“Since decreases in (or limits of) a unit’s capacity factor have a direct impact on its CO2 emissions profile, states, EPA, and units can employ a mass-based approach to leverage the emissions reductions benefits of a decrease in capacity factors, while preserving maximum operational flexibility to support overall system reliability by preserving the availability of units for resource adequacy, particularly during extreme weather events or other emergency conditions,” EEI said.
“We’ve got to go with a scale, we’ve got to go with the pace like never before,” U.S. Deputy Secretary of Energy David Turk said at the coalition’s webinar Monday. “My former colleagues at the [International Energy Agency] projected that by 2030, we’ll need to lock away roughly 30 times as much carbon as we’re currently managing, and nearly quintuple that by the middle of the century.”
DOE has made $10 billion available for a suite of carbon management applications, including the recent request for six demonstration projects at coal and natural gas plants, he added. DOE is also working with the Treasury Department to finalize the expanded 45 Q tax credit for carbon capture, said Turk.
EPA’s power plant rules would not be finalized until next year, following a public comment period. The Biden administration hopes to complete the regulations before Republicans could upend them by winning control of Congress in 2024. The Congressional Review Act allows a new Congress to reject regulations finalized within 60 days of the previous Congress.
The administration also is attempting to craft the rules to withstand certain court challenges.
The Supreme Court ruled last June that the Obama administration’s EPA failed to provide “clear congressional authorization” for its Clean Power Plan, which would have compelled generation shifting to reduce carbon emissions from coal-fired power plants. (See Supreme Court Rejects EPA Generation Shifting.)
An upcoming fuel and energy security study will examine the combined impacts of electricity generation trends and extended cold snaps on NYISO’s system reliability, the Analysis Group (AG) told the ISO’s Installed Capacity Working Group/Market Issues Working Group (ICAP/MIWG) on Friday.
The main thrust of the study is to identify circumstances under which available resources will be insufficient to meet both load and required reserves before emergency actions as the New York grid transitions to a greater dependence on renewable resources.
For the near-term, the study will assume NYISO’s continued reliance on fossil fuel-fired generation, followed by increasing reliance on weather-dependent and variable resources over the long term. Within that context, it will examine 17-day cold periods in winter 2023/24 and two other future winters.
AG plans to use historical weather and load data, literature reviews of other RTOs, projected resource demand and supply forecasts, and assumed worst-case scenarios to assess the potential risks associated with NYISO’s transition and the impacts extreme weather events could have on the grid.
The assessment will use criteria such as net load and reserve needs, gas generation availability, interzonal transfers, and environmental constraints to identify hourly energy surplus and deficits in New York at a zonal level.
Paul Hibbard, a principal with AG, said the company conducted a similar study in 2019 that found “a continued reliance on fossil fuels was necessary in the near term,” and that NYISO could build more transmission to “address potential reliability risks associated with increasing variable generation.” (See “Fuel Security Study,” Analysis Group Presents NYISO Carbon Pricing Study Plan.)
Mark Younger, president of Hudson Energy Economics, asked whether the upcoming study will offer any noteworthy changes from the 2019 study.
Hibbard said the company is “kind of repeating what was done previously” given that the methodology and basic source material are similar, but the underlying risk scenarios determining the current study’s assumptions are different because of the passage of time.
Hibbard said the goal of the new study is to “identify circumstances under which resources may be insufficient to meet demand plus reserves without taking emergency actions.”
AG will return in May to give a more detailed presentation on the study’s assumptions, data and scenarios.
In early summer AG will share the study’s initial findings and recommendations, then present the final report later that season.
ECBL Aggregation Manual Updates
NYISO also presented the Friday ICAP/MIWG with draft manual updates for sections covering the economic customer baseline load (ECBL) that adjust the calculations to a five-minute basis for distributed energy resources.
The ECBL, which was implemented into NYISO markets in 2018, provides an estimated energy baseline for the ISO to measure the amount of demand reduction supplied by a demand-side resource participating in a day-ahead demand response program.
This update was one of a series of aggregation manual updates, and NYISO will return to share additional manual revisions on April 27.
FERC said last week that “by operation of law” it would not reconsider its approval of one of NERC’s new cold weather reliability standards earlier this year because of the expiration of the time limit for its response.
The Electric Power Supply Association (EPSA), the New England Power Generators Association and the PJM Power Providers Group had filed a request for rehearing in March of EOP-012-1 (Extreme cold weather preparedness and operations), which FERC approved alongside EOP-011-3 (Emergency operations) in February (RD23-1).
FERC ordered NERC to develop the standards as Phase 1 of a three-phase process to respond to the winter storm of February 2021 that nearly led to the collapse of the Texas Interconnection. (See FERC Orders New Reliability Standards in Response to Uri.)
In a filing Thursday, the commission said that because 30 days had passed without it taking action on the request, it should “be deemed to have been denied.”
Requirement R1 of EOP-012-1 mandates that generator owners (GOs) installing a new generation unit must implement freeze protection measures that allow the unit to operate for at least 12 hours at the extreme cold weather temperature for its location, defined as the lowest 0.2 percentile of the hourly temperatures measured in December, January and February of each year since 2000.
Requirement R2 requires owners of existing generating units to ensure they can operate for at least one hour at the extreme cold weather temperature, either by adding or modifying existing freeze protection measures.
EPSA and the other organizations objected to these requirements on the grounds that they would “require [GOs] to incur potentially significant costs that they lack a reasonable opportunity to recover through rates.” They urged FERC to either initiate a new proceeding regarding cost recovery or remand the standard to NERC for revisions.
However, the commission said these concerns were “outside the scope of the instant proceeding,” and while it did raise several concerns for NERC to address in the next version of the standard — including the timeline for completion of corrective action plans and the grace period for generators to implement those plans and freeze protection measures — it did not provide for any delay in implementation of the standard or for addressing the groups’ concerns.
The petitioners’ rehearing request claimed that FERC erred by saying cost recovery was not in the scope of the proceeding, arguing that the standard “cannot be just and reasonable” as the Federal Power Act requires that reliability standards provide “a regulated entity of a reasonable opportunity to recover its costs.” EPSA said EOP-012-1 also violates the FPA by imposing requirements on registered entities for the modification or construction of generation facilities.
FERC did not specifically refer to these complaints in its filing last week, but it promised that it would address the rehearing request in a future order. It also affirmed that it “may modify or set aside its … order … in such manner as it shall deem proper.”
EOP-012-1 is set to take effect Oct. 1, 2024. The effective date of EOP-011-3 has not been set; FERC said in its implementation order that it will not finalize the standard’s implementation date until NERC submits its proposed revisions to EOP-012-1.
A $615 million project to ease one of the transmission bottlenecks in upstate New York is nearing completion.
State officials last week announced the Central East Energy Connect (CEEC) upgrade undertaken by LS Power Grid New York and the New York Power Authority is now 75% complete with energization of a new substation in Princetown, west of Schenectady.
The 345-kV CEEC runs 93 miles from the Utica area east to the Albany area. The upgrades are designed to not only increase the CEEC’s capacity but improve its reliability and resilience. Steel monopoles are replacing wooden H-frame towers that are more than 60 years old in some cases. Four existing substations along the route are being upgraded, and two new substations have been built and are now in service.
Completion is anticipated later in 2023 and will result in a nearly five-fold increase in capacity.
The CEEC upgrade arose from a December 2015 finding by the state Public Service Commission that a Public Policy Transmission Need existed for new 345-kV transmission facilities to move power from upstate to downstate. LS Power and NYPA submitted a joint proposal in August 2019, and the PSC adopted it in January 2021. Work began the next month.
As thousands of megawatts of wind and solar generation capacity are planned upstate to carry out New York’s clean energy transition, the need for such transmission lines will only grow.
The CEEC is just one of several such transmission projects on the drawing board or in progress across upstate New York, and far from the largest:
The rebuild of NYPA’s 86-mile Moses-Adirondack Smart Path is nearing completion.
NYPA and National Grid began work in December on Smart Path Connect, which will add 45 miles on the north end of Smart Path and 55 miles on the south end, where it will connect to the CEEC.
New York Transco is progressing on the New York Energy Solution, a rebuild of 54 miles of north-south transmission lines in the Hudson Valley south of Albany; the 456th and final monopole was erected earlier this month.
Last year NextEra Energy Transmission New York completed the Empire State Line, which runs only 20 miles but includes a new 345-kV hub for western New York and links to the state’s largest electric producer, the Niagara Power Project.
Work recently began on the Champlain Hudson Power Express, a $6 billion project running 340 miles underground and underwater from Quebec to New York City.
NYPA, energyRE and Invenergy have teamed up on a 175-mile underground and underwater transmission line called Clean Path NY that would run southeast through the Catskills to New York City and is now in the permitting process. With associated wind and solar generation projects, the price tag is estimated at $11 billion.
The planning continues, as New York works toward an emissions-free grid by 2040, with concurrent increases in power demand and variability of power supply.
The PSC in February approved 62 transmission upgrades with a combined capacity of 3.5 GW and an estimated cost of $4.4 billion. Last week it approved an $810 million clean energy hub designed to increase transmission capacity in New York City amid the demand of electrification, with many more upgrades expected there in the decades to come.
LEESBURG, Va. — FERC has become too politicized and should use its independent authority to move the electricity industry forward, two former commission chairs said Tuesday at an event hosted by aggregation company Voltus in Northern Virginia.
Former Chair Neil Chatterjee, now a senior advisor with Hogan Lovells, said he has developed a relationship over the years with Voltus Chief Regulatory Officer Jon Wellinghoff, who chaired FERC under President Obama, because during his tenure at the agency he looked to build on his predecessor’s work through major orders.
Wellinghoff was the force behind Order 745 on demand response compensation, which became the subject of a U.S. Supreme Court case affirming FERC’s jurisdiction over demand side resources, and Chatterjee helped shepherd through several orders expanding its authority in that area.
“A lot of what ultimately culminated in [orders] 841 and 2222, and 845, was me building upon the work that he had already done,” said Chatterjee. “And that’s how FERC needs to be. It was an independent agency because you actually didn’t know the partisan affiliations of the different commissioners.”
Now articles regularly spell out the political affiliation of the commissioners. (For the record, Chatterjee was a Republican appointee, and Wellinghoff, a Democrat.) Chatterjee argued parties should not matter.
“When it comes to something like the proper functioning of markets, and the oversight and the reliability of the grid, these things should be independent and above politics,” he said.
While Chatterjee got the initial Order 2222 through, many compliance filings are still before FERC. Wellinghoff said he hoped the commission would move those through and ensure that market rules for distributed energy resources are in line with the order.
“I hope that FERC does step up under 2222 — that they do carry out the spirit and intent of what you started there and actually ensure that these distributed resources do have a full opportunity to play in this market,” Wellinghoff said. “Because if they do, the potential is huge.”
Some forecasts put 28 million electric vehicles on U.S. roads by 2030, a figure that could double based on EPA’s recent proposed emissions rules. (See: EPA Releases Emissions Rules Aimed at Boosting EVs.) But even the smaller number means the country’s behind-the-meter battery capacity will exceed its generating capacity, Wellinghoff said.
“It’s going to be available to be used, and we have to effectuate the ability to use that resource,” he said. “FERC is in the trenches on that right now.”
Reason to be Proud
U.S. Rep Sean Casten (D-Ill.), a major supporter of FERC on Capitol Hill, said the commission has plenty of authority to move the needle on energy policy on its own, although it sometimes needs a push from Congress to get going. He has introduced a bill — the REDUCE Act — that would remove the state opt-out for wholesale demand response programs, as well as other bills on transmission, and he wants FERC to set a price on carbon to give zero-carbon assets their proper value on a grid awash in resources that have no marginal costs.
“I think a strong case can be made that FERC has authority, but perhaps not the obligation,” Casten said. “And whether it’s the REDUCE Act or others, we find ourselves in Congress saying, ‘Well, let’s just give you the obligation.’”
Casten argued that FERC is the most important agency for climate policy and said its adoption of wholesale competition, which led to rapid growth in natural gas combined cycle plants and a surge in capacity uprates for existing nuclear plants, was the main reason the industry moved away from coal.
“FERC’s power comes from authority and independence,” Casten said. “And I think FERC is a little bit afraid of its own shadow.”
Casten said the fact that former FERC Chair Richard Glick was denied a renomination hearing after endorsing policies opposed by Senate Energy and Natural Resources Committee Chair Joe Manchin (D-W. Va.) — particularly around the climate impacts of natural gas pipelines — has also put a chill on the agency.
“My view is if you are appointed to a term running an agency as powerful as FERC, or a commissioner on an agency as powerful as FERC, you have five years to tell your grandchildren that ‘you have reason to be proud of me,’’’ Casten said.
Worrying about whether a policy will impact a renomination hearing or offend a particular senator is no way to go about the job, he said.
FERC has been impacted by politics long before Manchin denied Glick a hearing, with Wellinghoff lamenting the fact that “Standard Market Design” for RTOs never got off the launching pad under Chairman Pat Wood during President George W. Bush’s first term.
“It used to drive me nuts at FERC when an order came in from an RTO and the words were different for the same thing,” said Wellinghoff. “It’s like we’re in Europe, you know — PJM speaks Italian and MISO speaks German.”
Wood tried to push through a reform that would have the same market design all around the country, but he was ultimately “run out of town” by powerful utility interests who were opposed to having independent markets, Wellinghoff said.
The term “green hydrogen” may be a misnomer under rules the U.S. Treasury Department is designing to determine the size of the federal production tax credit that a producer can claim using electrolysis.
It will come down to the amount of carbon dioxide and other greenhouse gases emitted to generate the electricity most companies will use to produce the hydrogen and whether they tried to net out those emissions with the purchase of renewable power. Even with the greenest method of production, that amount will depend on how green was the electricity used to power the technology.
The argument is more than academic because the Treasury and the Department of Energy are expected to use the calculated level of GHG emissions across regional grids to determine the PTC. Billions of dollars are at stake.
A company will be able claim up to $3/kg of hydrogen produced with renewable or nuclear power, or as low as 60 cents/kg for hydrogen produced by steam reformation of methane, and then only if the resulting carbon dioxide is either sequestered or sold as an industrial gas.
Allison Nyholm, ACORE | E3/ACORE
One of complicating factors is whether to account for those new carbon emissions annually or on an hourly basis. Underlying assumptions are that clean grid power varies by region, by season and time of day. Electrolyzers will create a new, heavy load, likely causing power companies to run dirtier generation during times of peak demand.
In a report published last week, the American Council on Renewable Energy (ACORE) and energy consulting firm Energy and Environmental Economics (E3) argue that calculating emissions on an annual basis would likely lead to lower overall net carbon emissions and higher annual hydrogen production rates than calculating by the hour.
“An annual matching requirement, in which hydrogen producers would need to procure specified clean energy production to match their consumption on an annual basis, would allow electrolyzers to more cost-effectively operate at a higher capacity factor, reducing the cost of hydrogen production,” the report concludes.
The study found that calculating an electrolyzer company’s carbon emissions and efforts to offset them on an hourly basis could force electrolysis operations to shut down during times when the grid reaches peak demand, potentially driving up hydrogen prices.
Earlier studies by other organizations reached the opposite conclusion: that hourly accounting would lead to net-zero carbon in the atmosphere while still cutting the cost of hydrogen. The Treasury has not announced how it will address the issue. In addition to commissioning the study, ACORE has submitted comments to the department.
Arne Olson, E3 | E3/ACORE
“We began with three basic assumptions … that lowering the cost of hydrogen production is a fundamental goal to the tax incentives and should be considered in any analysis,” Allison Nyholm, vice president of policy and public affairs at ACORE, said at the start of a webinar last Wednesday to explain the findings of the report.
“Building out [hydrogen production] to scale requires considering the capital as well as energy costs for hydrogen production, and that … new clean energy development created through the Inflation Reduction Act … will result in lower greenhouse gas emissions, both independently and when combined with hydrogen production at scale,” she said. “Our assumption is that we’re looking at 500-MW electrolyzers that operates at 90% utilization rates. We account for capital costs.”
Noting that electrolyzers remain expensive, Nyholm said one of the objectives of the study was to provide an accurate picture of the cost of hydrogen production across regions and as well as clean energy use.
Arne Olson, senior partner at E3, said one of the underlying assumptions of the study is that “the relationship between supply and demand is purely contractual” across the grid, meaning the sources of power energizing the grid are indistinguishable.
Greg Gangelhoff, E3 | E3/ACORE
“Any new electric load, including hydrogen [production], is served with power from the grid, and all else [being] equal, that’s going to increase carbon emissions, because carbon-emitting sources will need to increase their production to supply that load,” he said.
The only exception would be an electrolyzer and a renewable power supplier both operating completely off-grid, he added.
Companies wishing to use clean power account for the carbon content of grid power they are using by contracting with a clean power producer to “inject” that power into the grid, he said. In other words, the relationship between the supplier and company using it is purely contractual, he added.
Figuring out how the electrolyzer industry would affect the grid over different parts of the nation involved modeling 40 markets on an hourly and seasonal basis.
“The reason for selecting these markets was ultimately to see the impact of electrolyzer operations in a widespread of market contexts,” said Greg Gangelhoff, an E3 analyst. “The benefit of … an annual matching approach, the electrolyzer can ramp down to avoid those highest-priced hours. And by avoiding those highest-priced hours, you are also avoiding some of the highest hourly marginal emission rates … giving you a kind of a double bang for your buck in terms of efficiency and reducing cost.”
