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.”
FERC on Tuesday rejected a request to include pump storage facilities in ISO-NE’s Inventoried Energy Program saying it was outside the scope of the RTO’s recent compliance filing prompted by an appellate remand (ER19-1428-006).
Last June, the D.C. Circuit Court of Appeals found ISO-NE’s Inventoried Energy Program, to go into effect for winter 2023, to be unjust because it would unfairly pay nuclear, coal, biomass and hydroelectric resources for fuel storage (ER19-1428-005). The program pays generators for maintaining up to three days’ worth of potential energy (e.g., fuel) on-site that can be converted into electricity at ISO-NE’s direction.
The court said FERC had failed to consider protestors’ argument that including those resources was improper because they were unlikely to change their behavior in response to the program’s incentives.
“Acceptance of compensation incentives — for a distinct category of generators that are unlikely to respond to those incentives — was arbitrary and capricious,” the court said. (See Court Strikes a Blow to ISO-NE Winter Plan.)
FERC in September issued an order on remand implementing the D.C. Circuit ruling and ordering the RTO to revise its tariff to eliminate those resources from the program. (See FERC Seeking Solutions for New England Winter Reliability.)
The RTO filed the requested tariff revisions in November. But it also noted that stakeholders — supported by Brookfield Energy Marketing, the National Hydropower Association and RENEW Northeast — had filed an amendment to the changes carving out pump storage projects from other hydropower and allowing it to participate in the program.
They said that because pumped hydro resources participate in the markets as binary storage facilities, a subcategory of electric storage facilities (which are permitted to participate in the Inventoried Energy Program), pumped hydro should be allowed to participate regardless of the D.C. Circuit’s ruling that hydroelectric resources are not permitted.
ISO-NE said it did not view the amendment as consistent with the D.C. Circuit’s order but would not oppose including pumped hydro in the program if FERC determined that the amendment met the compliance mandates.
In approving the RTO’s tariff revisions, the commission rejected the amendment as beyond the scope of the compliance filing. “The only question before the commission in this proceeding is whether ISO-NE’s filing complies with the directives of the September 2022 order. Protesters are effectively arguing that the September 2022 order should be modified to exclude a subset of hydroelectric resources from the compliance directive. These protests are essentially late-filed requests for rehearing of the September 2022 order.”
A developer has scrapped its plans to build a 1,240-MW gas-fired generator in central Pennsylvania after environmental groups challenged the plant’s permits.
“Renovo Energy Center [REC] LLC will discontinue development of the proposed combined-cycle plant in Renovo, Pa.,” the developer said in a statement. “After more than 8 years, we do not see a path to a reasonable conclusion of the project’s air permit appeal, and have made the difficult decision to discontinue development.”
REC submitted its air quality application in December 2019, detailing plans for a combined cycle generator fueled by natural gas or ultra-low sulfur diesel. The Clean Air Council, Citizens for Pennsylvania’s Future and Center for Biological Diversity filed a series of appeals to the state Environmental Hearing Board, arguing that the Pennsylvania Department of Environmental Protection (DEP) had awarded several permits that would allow emissions higher than standards in state law.
The hearing board granted the environmental groups two appeals in August 2022, resulting in a partial summary judgment finding that the sulfur dioxide and volatile organic compound limits were too high in the DEP permits. The company dropped its development plans a week after a third appeal was set to move to hearings, following a filing stating that the parties could not reach a settlement.
“Our lawsuit was about protecting Pennsylvania and this environmental justice community from the additional pollution burdens that this plant would have imposed,” Jessica O’Neill, senior attorney at PennFuture, said in a statement following the project cancellation.
“It is a win for Renovo and for all Pennsylvanians when we realize that the fracked gas industry doesn’t make sense — from an economic, energy or environmental health perspective,” she said. “We will continue to push back against facilities and industries that threaten the health of our communities, our workers and the sustainable energy future that Pennsylvanians want and that our children deserve.”
The appeal argued that the DEP approval contained incorrect emissions limits for volatile organic compounds, carbon monoxide and particulate matter; uses outdated global warming potential factors to calculate emissions; misapplied the cost-benefit analysis required by the state; and stated that emission reduction credits sources from outside the state would be accepted without demonstrating that the credits would meet state requirements.
Clean Air Council Legal Director Alex Bomstein said the DEP has a track record of allowing air permits that exceed limits by relying on a developer’s projected emissions for a generator without conducting adequate analysis to verify the figures. The environmental groups hired an expert for their appeals who found that the plant’s emissions would have caused billions of dollars in public health costs for surrounding neighborhoods, which have been designated an environmental justice community.
The group has also been involved in appealing air permits awarded to Invenergy’s proposed gas-fired Allegheny Energy Center in Pennsylvania, with hearings expected in July.
“The way that society is moving, we’re not going to have many more of the large fossil fuel plants. … The market is favoring renewable energy,” Bomstein said, adding that his group is focusing on trying to combat legislation that would impede development of clean energy.
Local environmental groups cited the impact on residents’ health as the basis for their opposition.
“As a great-grandparent, I’m grateful that this power plant didn’t come to fruition because we are now able to protect what is most important — the health of our children,” Sue Cannon, co-founder of Renovo Residents for a Healthy Environment, said in the statement. “I opposed the power plant because I was thinking about the children in this community, especially my great-grandchild, and what the pollution would do to their health.”
The California Air Resources Board plans to vote Thursday on a regulation requiring new passenger and short-distance switch locomotives to be zero-emission starting in 2030 and new freight locomotives to be zero-emission starting in 2035.
The proposal is meant to reduce emissions. Diesel-powered locomotives emit greenhouse gases, oxides of nitrogen (NOx) and fine particulate matter, with train tracks running through many densely populated areas of the state.
“Exposure to toxic and harmful diesel emissions is known to lead to cancer and increases in asthma, cardiopulmonary illness, hospitalizations and premature mortality,” CARB says on its website. “Communities near rail operations bear a disproportionate health burden due to their proximity to harmful emissions.”
Trains have generally been regarded as a cleaner form of transportation than big rigs, producing fewer emissions per ton of cargo carried. But a CARB analysis shows that as trucks decarbonize, trains will become the bigger polluters.
California’s current emissions limits will make trucks the cleaner mode of freight transportation starting as soon as this year, CARB says. Regulations to be implemented beginning in 2024 will gradually increase the differences between truck and train emissions until trucks are 100% zero-emitting and trains are not, CARB says.
“Results show that as California’s current truck regulations are implemented through 2023, trucks are producing less particulate matter (PM2.5) and [NOx] emissions,” the board’s website says. “By 2023, trucks will be the cleaner mode to transport freight. Beyond 2023, future CARB regulations will further reduce truck emissions, eventually bringing them to zero.”
The state’s Advanced Clean Trucks regulation, adopted by CARB in June 2020, will require truck manufacturers to sell an increasing percentage of zero-emission medium- and heavy-duty trucks in the state from 2024 through 2035.
The U.S. Environmental Protection Agency approved a Clean Air Act waiver for the rules on March 31, clearing the way for the state to launch the zero-emission program starting with model year 2024. (See Groundbreaking California Clean Truck Rules Win EPA Waiver.)
CARB adopted its Advanced Clean Cars II regulation in August, requiring all new cars sold in the state to be zero-emission or plug-in hybrid by 2035. (The EPA restored California’s long-held waiver for passenger vehicles in March 2022, after the Trump Administration revoked it in 2019.) So far, 17 states have adopted California’s clean car rules.
In-use Locomotive Regulation
CARB is tackling locomotive emissions by proposing similar rules. Its “in-use locomotive” regulation would phase out diesel trains and replace them with zero-emitting locomotives over time.
The regulation would require locomotive operators to begin funding their own trust accounts based on emissions starting in 2024.
“The dirtier the locomotive, the more funds must be set aside,” CARB’s website says.
The funds could be used to buy or rent the cleanest “tier” of diesel locomotives through 2030. They could also be used to purchase or lease zero-emissions (ZE) locomotives, to fund ZE locomotive pilot and demonstration projects, and to pay for ZE locomotive infrastructure.
Sierra Northern Railway received a $4 million grant from the California Energy Commission for a hydrogen powered switching locomotive.
Under the proposed regulation, locomotives older than 23 years would be prohibited from operating in-state starting in 2030. “Switchers,” short-haul locomotives used to move train cars, and passenger locomotives with original build dates of 2030 and beyond would be required to “operate in a ZE configuration,” CARB says. More powerful “line-haul” locomotives would have to be zero-emitting if built after 2034.
Where the locomotives will come from remains in question. Only a handful of hydrogen fuel-cell and battery-powered trains are in experimental or development phases in the U.S. and Canada.
Canadian Pacific Railway made test runs of North America’s first hydrogen-powered locomotive last year and is seeking to have two more on the tracks by the end of 2023. (The railroad’s name changed to CPKC on April 14, when it merged with Kansas City Southern.)
The railroad intends to produce its own hydrogen at two railyards in Calgary and Edmonton, including using solar panels to power an electrolysis plant in Calgary that makes hydrogen from water.
In March 2021, the California Energy Commission awarded Sierra Northern Railway $4 million to develop a hydrogen fuel-cell switcher locomotive for use in West Sacramento, California, where it now operates an older high-polluting diesel engine. That project remains in development.
WESTMINSTER, Colo. — SPP Markets+ stakeholders last week kicked off the development phase of the grid operator’s proposed “RTO-light” service offering in the West, heating up the race with CAISO to create a regional market.
Meeting for the first time, the Markets+ Participants Executive Committee (MPEC), comprised of potential participants and stakeholders that have financially committed to drafting the market protocols, tariff and governing documents, agreed to accelerate the timeline to file the tariff at FERC.
MPEC now plans to make the filing by December or early next year. CAISO plans to file a tariff for its competing Extended Day-ahead Market (EDAM) before the year is up.
The Energy Authority’s Laura Trolese, the MPEC’s newly elected chair, said speed is of the essence because some Western entities need to decide between the two markets within a year.
“They need an alternative to evaluate against in order to be able to make that decision,” she told RTO Insider. “While it may seem that we’re racing through this, we have been working on developing a market now for years, and we’ve had these same discussions. Yes, there are some new things, but we’ve had the same discussions and been working on putting a market together for four years together with some of the same faces in these previous efforts, some of the same faces that have been working through the EDAM process.
“We have a lot to draw from and to work from. It’s not starting from scratch and reinventing the wheel,” Trolese said.
The decision was just one of many stakeholders made during the two-day meeting. The MPEC also:
approved extending the participant funding agreement deadline to May 1, allowing as many as four interested parties to formally commit to Markets+’s development;
endorsed the first development phase’s scope of activities, tasks and deliverables;
agreed with SPP staff’s proposal to allow entities to begin participating in Markets+ once FERC approves the tariff next year, even though some day-ahead functions may be unavailable; and
approved stakeholder group charters, leadership and rosters.
The MPEC will oversee four working groups (design, seams, transmission, and operations and reliability) and five task forces that are expected to meet on a three-week cadence. Committee members amended their charters to allow the MPEC to reevaluate membership and voting once new funding agreements are executed.
The committee will meet in-person on a quarterly basis, with briefings to occur virtually as needed. The three-person Interim Markets+ Independent Panel (IMIP) provides final decision-making authority and a link to SPP’s Board of Directors. The panel, all SPP directors, plans to hold its meetings after the MPEC’s.
“The stakeholder process and the governance process that this group is engaged in is an ideal fit for the Western mindset,” said IMIP member John Cupparo, a Colorado native who professes a “don’t-fence-me-in” mindset. “It’s both challenging and rewarding. It will be some ups and downs along the way, but in the end, I think we’re getting a great product.”
“For those of you who haven’t seen it, it’s really an interesting process,” Eric Blank, chair of both the Colorado Public Utilities Commission and the Markets+ State Committee, told his committee Friday. “I really encourage you to watch, even independent of the substance. RTOS in the East that are staff-driven. This is really stakeholder-driven, and people just vote. It’s really unique.”
It’s that stakeholder-driven culture that SPP hopes will be the difference for Markets+.
“I’ve spent an awful lot of time in rooms like this talking about market evolution in the West … but I do believe that this is one that really is going to succeed,” said IMIP Chair Steve Wright, who previously has headed both the Bonneville Power Administration and Chelan (Washington) Public Utility District.
He pointed to the SPP-administered Western Resource Adequacy Program, the West’s first regional reliability planning and compliance program, as laying a “great foundation” in the West.
“Now we’re in a place where we actually had something that really works and we can build even more from that. This governance model, as applied to the West, can produce a market design for the West and by the West. SPP’s role here is not to make the decisions. Our role here is to facilitate and assist you in coming up with a market design that you want.”
The IMIP’s first voting item Wednesday was to approve the MPEC’s endorsement of a change to its voting structure that gives the independent sector a greater voice.
‘Frankensteining’ the Markets+ Tariff
The Markets+ Design Working Group will do much of the heavy lifting over the next few months, working with SPP staff to draft the tariff that will eventually be filed at FERC.
Staff said they have already “Frankensteined” together the best elements of markets previously approved by FERC into boilerplate language. Stakeholder groups will rework the basic tariff language to better fit Markets+’s unique design, with the MDWG reviewing their work.
“I can’t wait for the first ‘Mad Wag’!” SPP’s Chris Nolen said, sounding out the working group’s acronym.
“We started with a blank slate. We’re not bolting Markets+ onto an existing code … it has to fit comfortably and exist on its own. We drafted it that way,” Nolen, a senior attorney and tariff expert, said. “We borrowed pieces that worked well for many other tariffs. It gives us an easier process to justify those scans at FERC. To that end, when we draft this tariff, it should be, at least as I see it, the best tariff yet of the best ones.”
MPEC Leadership Promises Collaboration
Trolese’s first order of business after being elected chair of the MPEC? Adjourning a lengthy discussion for lunch, a move that was greeted with rousing cheers.
Both Trolese and Vice Chair Brian Cole, with Arizona Public Service, said they plan to ensure the committee collaborates on recommendations that benefit the region as a whole.
“My goal is to find ways for all of us to come together, to make decisions together,” Cole told MPEC members. “I don’t want this to sound like a campaign speech, but you’ll have that from me, without exception.”
Trolese said her role is to facilitate decision making and ensure everyone’s voice is heard and “that they’re given the opportunity to be able to express their concerns, but also to make sure that we’re sticking to the timeline that we committed to and we voted on and that we’re able to deliver what we set out to deliver, which is to get this tariff up and filed at FERC by Q1 of 2024.
“I think it will be a challenge to balance speed and inclusion, but I think it’s something that we’re going have to do in order to get this thing up and going,” Trolese said.
Director of Western markets and strategy for TEA, Trolese has spent the past 16 years in Washington with either Bonneville Power Administration or the Public Generating Pool. Much of that time has been spent on market development in the West. Efforts to create an RTO go back to 1995, she said.
“Our success in the West has been incremental,” Trolese said. “The Pacific Northwest has some of the lowest rates in the country, so the value proposition of lowering rates can be a challenging one, when they have some of the lowest-cost power, they have pretty clean power, and they have the lowest rates.”
MSC Gets Down to Business
The Markets+ State Committee wasted little time in getting started, holding a conference call Friday to discuss the MPEC’s actions and the MSC’s next steps.
Blank encouraged MPEC members to contact the group and its support staff with their ideas and recommendations for the development of Markets+.
“The goal of the MSC is to become informed as the process evolves, participate, get our questions asked and answered, get our concerns raised and addressed, and try and limit what happens on the back end,” Blank said.
The MSC is comprised of regulators from nine Western states. However, members amended the group’s charter Friday to allow participation from other Western states and Canadian provinces. The California Public Utilities Commission has asked to join the MSC and British Columbia regulators have also expressed interest.
The Western Interstate Energy Board (WIEB), comprised of 11 Western states and two western Canadian provinces, is serving as the MSC’s support staff. The WIEB has hired as its support AESL Consulting, which provides strategic regulatory and public policy support to public utilities, led by founder Ed Garvey and former MISO executive and Minnesota commissioner David Boyd.
“We have had nothing but offers of support to the extent we need it from SPP. They’ve been very cordial,” Boyd told the MSC. “I won’t put words in their mouth, but I think they recognize the value that regulators bring or have brought to their markets and therefore, the need to do a lot of work on the front end to expedite implementation on the back end. To the extent we need resources, I’m quite confident SPP will be supportive.”
SPP staff already has amended the stakeholder groups’ charters to allow MSC members to participate. They have advisory roles on the working groups and voting roles on the task forces. The WEIB has recommended assigning three commissioners to relevant groups; the board and its consultants will staff each stakeholder group.
The MSC plans to hold another call Friday to vote on the charter amendment and begin making stakeholder group appointments. It will begin its normal cadence of meetings in May.
FERC on Thursday partially accepted NYISO’s second compliance filing for Order 2222, directing the ISO to submit another within 30 days to correct several inconsistencies in its tariff revisions allowing distributed energy resource aggregations to fully participate in its markets (ER21-2460-003).
The commission found NYISO’s revisions listing what constitutes a small generating facility “appear to refer to the same type of interconnection” in two different places. The commission told NYISO to either remove one of the listings or explain why including both is not redundant.
FERC also found that NYISO had revised the definition of energy resource interconnection service (ERIS) in only one of the two relevant sections of its tariff, leaving the other unchanged.
Third, FERC said that NYISO’s revisions concerning market participation agreements, although partially settled, still included language from the first compliance filing that had already been found to be noncompliant. FERC said NYISO needed to remove “language requiring aggregators to attest that the aggregation has been authorized by the distribution utility and relevant electric retail regulatory authorities to participate in NYISO’s markets.”
Lastly, FERC directed NYISO to submit informational filings every six months detailing its stakeholder process in developing ancillary service market rules allowing DER aggregations to participate until Dec. 31, 2024, by which it needs to submit yet another compliance filing that includes the proposed rules. (See FERC Clarifies CAISO, NYISO Order 2222 Rulings.)
FERC partially approved NYISO’s first compliance filing in June 2022, with the ISO submitting its second later in November. In the next month, the commission granted NYISO an extension until 2026 to fully complete Order 2222 implementation, although the ISO said at the time that it might not need that long. (See FERC Gives NYISO Until 2026 to Complete Order 2222 Compliance.)
FERC on Thursday approved the compliance filings of six transmission providers, including those of NYISO and CAISO, with Order 881, though it found that most of them had failed to sufficiently explain their timelines for calculating and submitting their required ambient-adjusted line ratings (AARs).
Issued in December 2021, and upheld in May 2022, Order 881 directed transmission providers to end the use of static line ratings in evaluating near-term transmission service, and implement AARs for short-term service and seasonal ratings for long-term service (RM20-16). (See FERC Orders End to Static Tx Line Ratings.)
FERC did not specify a specific timeline by which transmission providers must submit their ratings, but it did order them to submit their own in their compliance filings. The commission had argued that providers “already manage similar timing issues” regarding other topics such as load forecasts, renewable energy production and generation bid deadlines, and that deadlines for AAR calculation and submission should be “not significantly different” from those they already calculate.
But though it approved their filings, the commission found that Arizona Public Service (ER22-1863), Black Hills Power (ER22-2303), Louisville Gas & Electric and Kentucky Utilities (ER22-2305), and Tampa Electric (ER22-1546) each failed to include such a timeline.
NYISO (ER22-2350) said that it expects to calculate AARs on a 48-hour basis, with submissions by transmission owners to be provided to the ISO hourly. But it also told FERC that it and TOs are “still developing technical procedures describing the mechanics of AAR submissions,” the commission said.
However, in each of these five cases, FERC acknowledged that “these timelines may not be determined until closer to AAR implementation and therefore that additional time may be necessary to comply with this requirement.” NYISO and the four utilities will need to submit another compliance filing by Nov. 12, 2024, ahead of their deadline for implementation of July 12, 2025.
In Tampa Electric’s case, the commission also took issue with the utility’s proposal to backdate its table of contents changes to June 1, 2022. FERC said this plan “could cause confusion because it would reference a section of [its tariff] that is not in effect.” To prevent potential misunderstandings, FERC set the table of contents revisions to take effect on the same day as the new tariff. However, the commission did suggest it was open to a future filing from the utility explaining why an earlier effective date would be justified.
“Our Order No. 881 compliance orders are bright points in today’s meeting,” Commissioner Allison Clements tweeted that afternoon. “They represent the beginning of a bigger opportunity to squeeze more juice out of our existing system at a relatively minimal cost to customers, using grid-enhancing technologies.”
NYISO
The commission had also ordered RTOs and ISOs to create systems and procedures to allow transmission owners to electronically update transmission line readings at least hourly and give TOs the ability to use more advanced dynamic line rating technology, which takes into account more factors than just air temperature when calculating ratings, if they choose.
FERC found that both NYISO and CAISO mostly complied with these directives. But both did not adequately explain certain definitions, the commission said.
Although NYISO provided for seasonal line ratings, it did not “define ‘seasons’ to include no fewer than four seasons in each year,” FERC said. The commission also nixed the ISO’s proposal that its TOs, rather than itself, were responsible for sharing transmission facility ratings and methodologies. NYISO has until June 19 to submit a compliance filing correcting these two deficiencies.
NYISO had also proposed revising its day-ahead market congestion settlement procedures to quantify the impacts of when the ratings employed in the market differed from those used in transmission congestion contract auctions. But FERC rejected this proposal as well, though without prejudice, noting that NYISO could file these revisions as a separate proposal.
“While the commission in Order No. 881 acknowledged a connection between the transmission line rating requirements and financial transmission rights markets, the commission declined to direct any changes to financial transmission rights markets, and therefore these revisions fall beyond the scope of this compliance proceeding,” FERC said.
CAISO
CAISO’s (ER22-2362) proposal only partially complied with Order 881’s requirement that transmission providers post line rating exceptions or temporary alternate ratings on its Open Access Same-Time Information System or another password-protected website, FERC said. And the ISO’s proposed definition of “transmission line ratings” fell short of the order’s requirements, it found.
The ISO had proposed defining “transmission line rating” as the “maximum transfer capability of a transmission line, computed in accordance with a written transmission line rating methodology and consistent with good utility practice, considering the technical limitations on conductors and relevant transmission equipment (such as thermal flow limits), as well as technical limitations of the transmission system (such as system voltage and stability limits).”
“CAISO asserts that the definition encompasses transmission line ratings for electric system equipment that includes more than just overhead conductors … [such as] circuit breakers, line traps and transformers,” FERC noted. But the commission said the definition needed to reflect the order’s wording.
“While CAISO states that its proposed definition encompasses electrical system equipment beyond just overhead conductors, we find that the absence of tariff specificity renders the proposed definition unclear on this point,” the commission said.
FERC said CAISO’s proposal also only partially complied with Order 881’s requirements for designating exceptions and alternate line ratings.
“CAISO proposes to coordinate with [participating transmission owners] in their development of exceptions or alternate ratings for both near-term and longer-term transmission service for the set of circumstances set forth in the pro forma” tariff, the commission noted. “However, CAISO does not propose tariff language stating that exceptions will be re-evaluated by the transmission provider at least every five years, nor does CAISO explain the absence of such language.”
FERC gave CAISO until June 19 to submit another compliance filing for these failings.
