Washington legislators have earmarked slightly more than $4 million to build the state’s first two hydrogen vehicle refueling stations.
However, many details of those first stations — in East Wenatchee and Chehalis — still need to be addressed.
Neither will likely be built until 2022, and the appropriations won’t be made until Gov. Jay Inslee signs transportation and capital budget bills, which he is expected to do soon. The money will not show up until July 1, which is the beginning of the 2021-2023 budget biennium.
Twin Transit in Lewis County is scheduled to receive $2.55 million from the state’s capital budget. The proposed hydrogen refueling station will be in Chehalis, which is 26 miles south of Olympia along the I-5 freeway.
The Douglas County Public Utility District is set to receive $1.5 million from the state’s transportation budget for a hydrogen refueling station in East Wenatchee, which is located on the Columbia River on the eastern side of the Cascade Mountains.
Twin Transit, which serves Centralia and Chehalis, Wash., plans to acquire two buses and 10 cars that would be fueled by a nearby hydrogen fueling station. | Twin Transit
Douglas County PUD is already building Washington’s first hydrogen production facility near East Wenatchee, which is expected to be finished in November and provide hydrogen for the two refueling stations. The $20 million plant is expected to produce two tons of hydrogen per day with plans to expand when more output is needed. (See Wash. PUD Breaks Ground on Hydrogen Plant.)
“We are very excited about the hydrogen fueling stations,” said Joe Clark, executive director of Twin Transit. The transit system serves Lewis County, including the twin cities of Centralia and Chehalis,
The transit authority wants to achieve net-zero carbon emissions by 2030. “For an agency our size, it’s a very aggressive goal,” Clark said.
The transit system already uses lower-carbon diesel fuel. It hopes to start using a wireless electromagnetic induction system to recharge a pair of new electric-powered buses on June 3.
Under the system, an electric bus parks on top of what is essentially a big magnet just below the pavement; the electrical field recharges the bus. Clark said that electric vehicles usually take a few hours to recharge, which would be a hurdle for buses that could have to operate in 16-hour shifts. However, parking a bus over the magnetic-wave system for 10 minutes out of every hour should be sufficient for it to last a 16-hour shift, he said.
The hydrogen refueling station on the agency’s land next to I-5 is a next step in Twin Transit’s efforts. The transit system plans to buy two hydrogen-fueled buses and 10 hydrogen-fueled cars as the initial users of the refueling station.
Unanswered questions so far are the total cost of building a refueling station, plus the annual operational costs. The transit authority won’t start tackling those issues until it gets the state allocation on July 1.
Clark speculated that the refueling station would start serving vehicles in late 2022. If enough private hydrogen-fuel cars and truck starts using I-5, Clark said the transit authority might lease the station to a private commercial business.
Meanwhile, Douglas County PUD is also awaiting receipt of state money on July 1 before tackling an exact location in East Wenatchee for the refueling station, its cost figures and its construction timetable, said PUD spokeswoman Meaghan Vibbert. Its first users will be PUD-owned hydrogen-fueled vehicles.
Douglas County PUD, Twin Transit and other local government agencies have been meeting with two private non-profit entities — the Tacoma-based Renewable Hydrogen Alliance and the Portland-based Bonneville Environmental Foundation — to brainstorm dotting Washington with hydrogen refueling stations, possibly 100 or so miles apart. That concept is still in the initial discussion stage, Clark said.
Even as the electricity sector decarbonizes and appliance efficiency improves, reducing greenhouse gas emissions from buildings will still prove increasingly difficult, industry experts said last week.
A panelist on Texas research firm Pecan Street’s webinar Wednesday, Rocky Mountain Institute’s Amar Shah, said individual building emissions have fallen naturally with the electric sector’s decarbonization efforts. But even with complete grid decarbonization, 70 million-plus homes, buildings and institutions will still burn natural gas and fuel oil, he said.
Shah said direct-combustion emissions in buildings are a “stubborn statistic.” Even as appliances have gotten more efficient, he said, there are simply more of them now as more housing is built and population increases. New natural gas infrastructure is “built and designed and amortized” for 50 or 60 years, Shah said, and homeowners buy gas-burning appliances with no replacement plans for at least a decade.
Colin Rowan, Pecan Street’s communications director, said 40% of global GHG emissions come from the built environment, or human-made surroundings for human activity. He said there’s been a 5% increase in building emissions since 2010.
Rowan said the question remains whether the grid can handle millions more electric water heaters and heat pumps, especially given the unexpected residential demand that ERCOT was unable to meet during February’s winter storm.
Clockwise from left: Tom Paine, ConSol; Colin Rowan, Pecan Street; William Allen, ConSol; Joshua Rhodes, University of Texas at Austin; and Amar Shah, RMI | Pecan Street
Joshua Rhodes, research associate at the University of Texas at Austin, said electrification policy for buildings won’t be a flipped switch. It will take place over time, giving the grid time to adjust, he said.
ConSol Senior Policy Adviser Tom Paine said that although older housing is ripe for electrification retrofits, federal policy remains influenced by special interest groups. As long as that happens, he said, nationwide building electrification won’t gain a policy foothold.
“I don’t think there’s an appetite to cut into the bottom line” of fossil fuel industries, Paine said.
Shah predicted building electrification will continue to be a matter of “local action.” Some states are pushing for total electrification in all new construction by the end of the decade, Paine said.
“But you have a lot of other states,” Shah said, calling out Texas, Pennsylvania and other states that depend on the fossil fuel industry. “And they’re not going to dig into that unless there’s some incentive pushing them,” he added.
Paine also said residential buildings in cold climates are going to be particularly challenged because of heat pumps’ inefficiency in freezing weather. Many rely on backup heat sources that nearly always involve burning something, he said.
“We have a huge range that we have to deal with when it comes to building electrification,” Paine said. “There is no long-term policy in the federal government.”
He said consumer choice will likely become the catalyst for building electrification in places where no cohesive policy exists.
Rowan said building electrification isn’t as straightforward as transportation electrification, where a consumer can purchase a new car and plug it in.
“The technological questions have largely been solved. It’s now a matter of scaling them up,” ConSol Senior Technical Adviser William Allen said.
He said builders needed to be convinced to switch from traditional water heaters to tankless water heaters. A shift must now be made to electric tank models, Allen said, adding, “That’s kind of a hard sell.”
People will have to get used to heat pumps’ lower air temperatures as opposed to traditional furnaces’ “blast of hot air,” Allen said. He also said home chefs will have to relinquish the idea that cooking on gas stoves is better than on electric cooktops. But he said today’s induction electric stoves are a long cry from the tilted, smoking coil burners of yesteryear.
Paine agreed that consumers will drive the changeover, with costs being a major factor.
“When the thing is a natural economic choice, that’s when I think there’s the most opportunity,” he said.
The California Public Utilities Commission proposed Friday requiring electric providers to procure 11.5 GW of new resources between 2023 and 2026 to meet the state’s reliability needs and bolster its transition to 100% clean energy.
“This procurement order is designed to achieve our ambitious greenhouse gas emissions reduction targets for 2030 and to keep us on a clear path to meeting our ultimate goal of 100% zero-carbon electricity resources by 2045,” it said.
In a divergence from most state policies, the proposal would require load-serving entities (LSEs) to include more fossil fuel generation in their resource mixes by adding 1,000 to 1,500 MW in additional capacity from efficiency improvements and expansions at existing natural gas plants.
Clean energy advocates objected to that component, but the CPUC said the state can meet its long-term clean-energy goals while using fossil fuels to support reliability in the next five years.
“The middle of this decade represents an inflection point and a transition; we need to make it through successfully in order to realize our goals,” Administrative Law Judge Julie Fitch wrote. “The potential for a destabilized electric grid and unreliable service if we fail to plan appropriately for the transition is a very serious threat to our ability to realize our long-term goals.”
The proposal would require LSEs, including community choice aggregators and the state’s three investor-owned utilities to procure — in proportion to their share of load in CAISO — 3,000 MW by 2023, another 4,500 MW by 2024, 2,000 MW by 2025, and an additional 2,000 MW by 2026. Batteries, longer-duration energy storage, solar, wind and other renewables would make up 90% of the new resource mix.
California’s last nuclear plant, Diablo Canyon, is scheduled to retire starting in 2024. | PGE
New capacity in 2023-25 would replace 2,280 MW from the state’s last operating nuclear generator, Pacific Gas and Electric’s (NYSE:PCG) Diablo Canyon Power Plant, which is scheduled to retire in 2024-25.
“We are specifically ordering that the resources from Diablo Canyon be replaced with at least 2,500 MW of firm, zero-emitting resources,” the proposed decision says. “We also expect that almost all of the resources procured pursuant to this order will be zero-emitting.”
The firm, zero-emitting resources are expected to be renewables paired with storage that can deliver power 5 to 10 p.m. every day.
The state will also lose 4,200 MW of capacity from retiring natural gas plants, including 3,700 MW from four once-through-cooling plants that the state ordered to close by the end of 2023. (See OTC Plants to Remain Open, Calif. Water Board Rules.)
Resources intended to come online in 2026 must be long-lead-time resources, including geothermal generation and long-duration storage, the proposal says.
An alternate decision proposed by CPUC Commissioner Clifford Rechtschaffen differs from the main proposal by requiring procurement of 500 MW of conventional fossil-fueled generation by PG&E, Southern California Edison (NYSE:EIX) and San Diego Gas & Electric (NYSE:SRE) under a set of conditions that include a five-year time limit on the units’ operation.
His plan would authorize the IOUs to procure another 300 MW of thermal resources that commit to using green hydrogen, in part.
The CPUC plans to vote on the proposed decision and Rechtschaffen’s alternate at its June 24 meeting.
FERC on Thursday accepted PJM’s compliance filing on its rules for fast-start resources, allowing tariff changes to take effect by July on an issue that has been before the commission since 2017 (ER19-2722).
The commission determined in a December order that PJM partially complied with its April 2019 ruling that the RTO’s fast-start pricing practices were unjust and unreasonable because they did not allow prices to reflect the marginal cost of serving load. PJM’s second compliance filing in February sought to answer the commission’s directives on several issues. (See Mixed Ruling for PJM on Fast-Start Pricing.)
“PJM’s proposed tariff revisions set forth the physical operating characteristic requirements for fast-start resources, consider certain resource types fast-start resources by default and, for other resource types, set forth a process for determining whether the resource can meet the fast-start resource physical operating characteristics,” the commission said.
Revisions
FERC ruled in December that PJM failed to provide sufficient detail on its process for determining eligibility for fast-start resources. The commission agreed with commenters that the proposed definition, which would have allowed PJM’s Office of the Interconnection to deem a resource capable of meeting eligibility criteria based on its operating characteristics, gave the RTO too much discretion.
In response to the commission’s directive, PJM proposed adding a new section to its Operating Agreement defining which resources are considered fast-start and a description of the process by which a resource may become a fast-start resource or lose its status. The definition states that a fast-start resource is “capable of operating with a notification time plus start-up time of one hour or less, and a minimum run time or minimum down time of one hour or less, based on operating characteristics.”
PJM control room | PJM
The new section also includes a list of resource types qualifying as fast-start resources, including economic load response participant resources, fuel cells, combustion turbines, diesel, hydropower, battery, solar, landfills and wind.
For other types of resources capable of meeting fast-start operating requirements, PJM proposed a process where a resource can obtain written approval from the RTO, “after advice and input from the Independent Market Monitor,” to have the fast-start designation. The market seller has to provide documentation supporting the capability to meet required operating characteristics, including historical operating data showing the ability to provide energy on one hour’s notice.
“We find that this tariff language sufficiently identifies those resources eligible to submit fast-start pricing offers and does not provide PJM with too much discretion in identification of fast-start resources,” FERC said in the order.
The December order also found that PJM proposed several new types of uplift payments that were not directed by the commission and instructed the RTO to remove those provisions, including:
providing for make-whole payments for following dispatch instructions;
uplift payments for virtual transactions, price-sensitive demand and dispatchable exports; and
lost opportunity cost payments to day-ahead scheduling reserve resources.
The commission in December also rejected PJM’s proposal to apply the offer cap requirements of Order 831 to the composite energy offers under its fast-start pricing proposal. (See New FERC Rule Will Double RTO Offer Caps.)
PJM’s revisions call for only adjusting fast-start offers in the pricing run “when a fast-start resource has been selected in the dispatch run and the resource’s submitted composite energy offer exceeds $1,000/MWh” and will “continue to independently verify the incremental energy offer, start-up cost and no-load cost.”
Market Monitor Protest
The Monitor argued that PJM did not comply with the commission’s directive to properly define the eligibility of fast-start resources, saying that the revised language still gave the RTO “too much discretion” and that there are “no clear standards for verifying which resources that submit start-up plus notification times of less than one hour and minimum run times of less than one hour are capable or not capable of operating according to those parameters.”
It recommended that the commission direct PJM to define a fast-start resource “based only on operating parameters, require that the parameters be accurate based on the resource’s physical capability and prevent resources that do not start in the defined time period from setting price as fast-start resources.”
FERC rejected the protest, saying PJM “added sufficient detail” regarding the process for determining fast-start resource eligibility.
“We find that the Market Monitor’s general concern regarding the submittal of inaccurate offer parameters by resources and the standards for verification of those parameters are outside the scope of the commission’s [Federal Power Act] Section 206 finding,” FERC said.
PJM said Friday it is currently re-evaluating the feasibility of a July 1 implementation date and “the risk associated with implementing during a summer peak month.” The RTO will update stakeholders on the implementation process at the Markets and Reliability Committee’s meeting Wednesday.
FERC last week stuck to its ruling that Tri-State Generation and Transmission Association’s transitional process for interconnection customers is just and reasonable, overriding rehearing requests by a pair of solar developers (ER21-410-001).
The commission in January accepted Tri-State’s tariff modifications to its large generator and small generation interconnection procedures (LGIP and SGIP) and its proposed queue reform. It found the transitional process to be a reasonable means of implementation and resolving the backlog, and that it was consistent with other precedent. (See FERC Accepts Tri-State GI Procedures.)
FERC’s order sticks with Tri-State’s transitional interconnection process, rejecting complaints by solar developers. | Tri-State G&T
Keota Solar and Arevia Power challenged the sufficiency of the process that allows interconnection customers 60 days and an additional cure period to meet readiness and site-control requirements. Under Tri-State’s transitional process, interconnection customers have three options to demonstrate readiness: a contract for sale; inclusion in a resource plan; or acceptance of a provisional large generator interconnection agreement.
FERC said it continued to find Tri-State’s process to be consistent with or superior to the pro forma LGIP and, “therefore, is just and reasonable.”
“Given Tri-State’s stated challenges in operating its interconnection queue,” the commission said, “the proposed transitional process [is] a reasonable means of implementing the queue-reform proposal and resolving the interconnection queue backlog.
Tri-State’s footprint | Tri-State G&T
“Petitioners’ rehearing objections to the readiness criteria indicate frustration with the fact that their respective projects are not ready and cannot proceed in the transitional serial process,” FERC added.
The commission also denied Keota’s separate request for remedial relief under the Federal Power Act and a one-time waiver of certain requirements in Tri-State’s LGIP, which established eligibility for the transitional process’s late-stage interconnection requests (ER21-1206).
The solar developer, after missing several deadlines, requested a limited waiver from requirements that it make a readiness demonstration before entering the transitional process; pay a deposit equal to 100% of the costs for transmission facilities and network upgrades identified in system studies; and subject itself to punitive withdrawal penalties equal to nine times the total study costs.
FERC denied the request, saying the circumstances didn’t meet the criteria for granting the waiver and finding that Keota had not demonstrated that it acted in good faith.
Linda Apsey, president and CEO of ITC Holdings Corp. | House Select Committee
Linda Apsey, CEO of independent transmission developer ITC Holdings Corp. (NYSE:FTXS), cuts to the chase when talking about the regulatory reforms needed to reach President Biden’s goal of decarbonizing the U.S. power system by 2035.
“FERC should repeal or modify unhelpful policies, like Order 1000, that have slowed regional transmission development and simply made it more complex,” Apsey said during a hearing before the House Select Committee on the Climate Crisis on Thursday. “The introduction of so-called competition is not competition. It is nothing more than a regulated bureaucratic bidding process with little appreciable benefit to the consumer.”
Apsey was one four speakers at the hearing on expanding and modernizing the grid, where Democrats prioritized proposals in Biden’s $2 trillion infrastructure package — such as a federal investment tax credit for transmission — and the jobs that a massive transmission buildout might create.
“We already have the innovative technologies needed to increase the efficiency, capacity and flexibility of our electric grid . . . and build new transmission lines so that every city, town and county can access America’s affordable, abundant wind and solar energy,” committee chair Rep. Kathy Castor (D-Fla.) said.
Republicans, on the other hand, called for revisions to the National Environmental Policy Act (NEPA).
Rep. Garret Graves (R-La.) | House Select Committee
“We’ve got to take a fresh look at that [law],” said Rep. Garret Graves (R-La.), the committee’s ranking member. “Not to shortcut our review of the environmental impacts, but to make sure we’re truly focused on the best environmental outcomes but also focused on the project outcomes, the project objectives, because the worst kind of project in the world is a project that never gets finished.”
The industry view, laid out by Apsey and the other speakers, was more technical and pragmatic, focused on what they see as the key obstacles to getting projects built: planning, permitting and cost allocation.
“When it comes to planning across multiple transmission owners, across multiple states, across multiple regions, we don’t necessarily have the processes that facilitate that,” Apsey said. “We would also strongly recommend that FERC require planning studies to include state clean energy standards and realistic estimates for electrification growth.”
Donnie Colston, director of the IBEW’s Utility Department | House Select Committee
“Current processes focus on assigning costs to those customers who benefit immediately and directly from the investment,” said Emily Sanford Fisher, general counsel and senior vice president for clean energy at the Edison Electric Institute, the trade association for investor-owned utilities. “This does not take into consideration the broader benefits of transmission for all customers. It may be necessary to broaden the scope of benefits and beneficiaries considered, particularly as the transmission system, the generation resource mix and policy goals change and are expected to change over time.”
Project delays that increase market uncertainty can also impact vital workforce development activities, said Donnie Colston, director of the Utility Department of the International Brotherhood of Electrical Workers.
“It takes three years to train a journeyman lineman to perform transmission line construction and maintenance,” Colston said. “And we anticipate the need for at least 50,000 new power linemen over the next 10 years. While projects are held up, we are losing valuable training time.”
The ITC Impact
A recent study from Princeton University predicts that the U.S. will need to increase its high voltage transmission capacity 60% by 2030. But many projects take seven to 10 years or more to even break ground because of long planning and permitting cycles, which in turn can make financing difficult. For some, the delays can be project killers, said Michael Skelly, founder and CEO of Grid United, an early-stage transmission developer.
Michael Skelly, founder and president, Grid United | House Select Committee
Approved in 2011, FERC Order 1000 was intended to stimulate transmission planning and construction through competition, but Apsey and other industry insiders say it has not had the desired impact. (See ACORE Panelists Discuss Regulatory Role in Biden Agenda.)
Another study from the American Council on Renewable Energy found 22 transmission projects across the country that it classified as ready to go but expected only about half would be built. The report argued for a transmission ITC as a way to get the projects built. (See Transmission ITC Could Add 20 GW of New Capacity to Grid.)
“A well-designed tax credit for transmission can lower costs for large projects and make it easier to achieve cost allocation agreements, which is a key hurdle to project approval and construction,” Apsey said.
“What we need [are] some successes,” said Skelly, an industry pioneer who tried, unsuccessfully, to develop transmission to bring wind power from the Great Plains to the Southeast. “With a little push from things like the investment tax credit, we can get these projects done. They will unlock tens of thousands of megawatts of new generation, boost today’s level of renewable energy penetration to even higher levels and help address reliability issues.”
NEPA ‘Weaponized’
Emily Sanford Fisher, EEI general counsel and senior vice president for clean energy | House Select Committee
NEPA was signed into law by Republican President Richard Nixon on Jan. 1, 1970. Under original regulations and guidance, a NEPA review was intended to take no more than a year, with final reports of about 150 pages or 300 for “actions of unusual scope and complexity,” according a 2020 report from the Council on Environmental Quality. The CEQ also found that between 2010 and 2018 the average review took more than four years, producing reports that averaged 661 pages.
Adding to delays, for many transmission projects, NEPA reviews have triggered litigation because, as Fisher said, “People don’t necessarily love living near infrastructure, even when they benefit from it.”
Speaking more bluntly, Rep. Dan Crenshaw (R-Tex.) said allocating trillions of dollars for infrastructure would be pointless if NEPA litigation is “weaponized” by environmental groups and the courts. “If we don’t address the permitting issues in this country, far more stringent than most developed nations, we’re never going to get to the part where we build more transmission,” he said.
Rep. Dan Crenshaw (R-Tex.) | House Select Committee
Graves recently introduced the Building United States Infrastructure through Limited Delays and Efficient Reviews (BUILDER) Act, which would ensure “practical project review times” and clarify “the threshold determinations for preparing an environmental document under NEPA,” according to a press release on the bill. It would also require potential “litigants to have participated meaningfully in the NEPA process before filing suit.”
One solution utilities are exploring is using existing rights of way to “piggyback our infrastructure,” Fisher said. Similarly, the Biden administration is looking at using highway rights of way for transmission.
Apsey, on the other hand, called for transmission planning that first identifies areas of high solar or wind resources, as was done in Michigan and Texas, she said. “We know where the wind blows; we know where the sun shines. Right now, we build transmission to interconnect everywhere a generator may site, whether it’s optimal or suboptimal. If we build the transmission where we know the renewable potential is, those renewable developers will locate around the transmission line.”
But any effort to find common ground of permitting reform could be derailed by partisan politics, as seen at the hearing when Graves brought up Biden’s recent decision to waive sanctions on Russia’s Nord Stream 2 gas pipeline.
“We saw President Biden being deemed a hero for shutting down the Keystone pipeline,” he said. “The same administration … just lifted sanctions to allow the Nord Stream pipeline. I am really struggling with what appears to be the hypocrisy here, and I think we have to step in and make sure we are making the right decisions for the global environment, for our allies and for a clean energy future that’s based on America’s resources.”
FERC last week terminated three more Boyce Hydro hydroelectric licenses for projects in Michigan, the latest chapter in the continuing fallout of the utility’s 16-year ownership of the derelict Edenville Dam.
The commission rescinded licenses for the Secord, Smallwood and Sanford hydroelectric projects on the Tittabawasee River, saying Boyce, which filed for bankruptcy last year, lost the properties through condemnation and legal proceedings (P-10809-051, et al.).
Strong storms, an inadequate spillway and years of negligence led to the Edenville Dam’s failure last May. The ensuing flood surge also caused the Sanford Dam to fail and damaged the Secord and Smallwood dams, forcing the evacuations of 10,000 people and leading to a national disaster declaration. FERC had already revoked Boyce’s license for the Edenville Dam before the disaster. (See Michigan Dam with Prolonged Safety Issues Fails.)
Edenville Dam following the breach | Michigan Department of Environment, Great Lakes, and Energy
The four lakes in Gladwin and Midland counties affected by the spillovers (Secord, Smallwood, Wixom and Sanford) remain dry lake beds. The Four Lakes Task Force, a volunteer group comprised of local lake association leaders dedicated to restoring the lakes, now owns the land where the hydroelectric projects sit. The group recently published restoration plans estimated to cost as much as $300 million.
In a press release, FERC said it was coordinating “the safe repair and management of the facilities” with the Four Lakes Task Force and the Michigan Department of the Environment, Great Lakes and Energy.
The commission also said that Four Lakes “has no intent to generate hydropower” from any of the dams and that the state of Michigan supports the decision.
Four Lakes Task Force President Dave Kepler has said FERC’s termination of Boyce Hydro’s licenses are crucial to being able to move forward with lake restorations.
Boyce Hydro filed for bankruptcy in July 2020. FERC still slapped the utility with a $15 million fine in April for its inaction after the breaches.
The commission said the penalty’s recovery is second to the “recovery of damages by victims of the dam breaches.” It noted that “Boyce Hydro’s liquidation plan ensures that the victims’ recovery will be before any recovery of the penalty.”
Boyce was owned by Las Vegas architect Lee Mueller, an heir of the Boy Scouts of America’s founder. Mueller and family members purchased the four dams in order to avoid paying taxes on the sale of an Illinois property. Michigan has sued Mueller over the flooding.
FERC tried for 15 years to get Boyce Hydro to address safety violations at the Edenville Dam, which included failing to increase the spillway’s capacity; performing unauthorized dam repairs and excavation; neglecting to file a public safety plan or follow its own water monitoring plan; and failing to acquire all property rights.
FERC on Thursday rejected the financial transmission rights forfeiture rule PJM has been using for more than four years, saying it was overly broad and could discourage legitimate hedging activity.
The commission also dismissed FTR trader XO Energy’s complaint challenging the rule, saying its case is now moot (ER17-1433, EL20-41-001).
Monthly FTR forfeitures for physical and financial participants | Monitoring Analytics
FTRs allow load-serving entities to hedge the risk of transmission congestion costs and permit financial traders to arbitrage day-ahead and real-time congestion. PJM implemented the forfeiture rule to prevent market participants from using virtual transactions to create congestion that benefits their FTR positions.
In January 2017, FERC ordered PJM to change how it implements the rule, saying the RTO’s focus on individual transactions failed to capture the impact of a market participant’s overall portfolio of virtual transactions on a constraint (EL14-37). (See FERC Orders Portfolio Approach for PJM FTR Forfeiture Rule.)
PJM responded with two compliance filings later that year and began billing forfeitures based on the new approach in September 2017 — retroactive to the beginning of the year — even though the commission had not approved the rules.
Refunds Possible
FERC’s ruling Thursday found PJM’s FTR forfeiture trigger unjust and unreasonable and ordered the RTO to propose a replacement within 60 days that uses “either a different threshold or an alternative approach to triggering forfeiture that strikes a more appropriate balance between deterring manipulative behavior and not burdening legitimate hedging activity.”
It said PJM’s compliance filing also must include information to help the commission to determine whether it should issue refunds and surcharges.
PJM triggered forfeitures if the net distribution factor (dFAX) between the transaction bus and the worst-case scenario bus is at least 0.75 — meaning at least 75% of the energy flowing between the two points is reflected in the constrained FTR path.
The commission said PJM’s filings complied with its January 2017 directive to use a portfolio approach when determining the impact of a market participant’s virtual transactions on constraints related to its FTR positions and that it apply the forfeiture rule to all FTRs, including counterflows. FERC also approved PJM’s use of the load-weighted reference bus and its treatment of all virtual transactions held by entities that share common ownership as part of the same portfolio.
But it rejected PJM’s 1-cent FTR impact test — which determines whether the net flow impacts the absolute value of an FTR by 1 cent or greater — as unjust and unreasonable because “it does not always reflect a material or significant increase in the value of an FTR to justify forfeiture of FTR profits.”
“The 1-cent threshold is in an overly broad application of the FTR forfeiture rule that is likely to disrupt legitimate hedging activity without providing an increased level of deterrence of manipulative activity,” the commission said.
FERC cited a PJM sensitivity analysis that found the new rules were capturing far more transactions than the prior test and noted that from 2016 to 2017, forfeitures under the new rules increased by $9.1 million.
Protesters complained they were forced to curtail their virtual energy trading because the trigger caused forfeitures on electrically distant FTR paths that were difficult to predict in advance of submitting bids and offers.
1-Cent Threshold
“The de minimis 1-cent threshold may result in forfeitures from incidental overlaps between a virtual energy portfolio and FTR position that would not amount to cross-product manipulation,” FERC said. “PJM offers no support for a finding that such a de minimis impact creates the appropriate balance between identifying potential manipulation and not disrupting legitimate hedging activity.”
The commission acknowledged the difficulty in designing a test that avoids triggering any forfeitures because of legitimate hedging. “But while an appropriate balance may trigger some forfeiture due to potentially legitimate conduct, the record indicates that PJM’s method could be adjusted to affect significantly less legitimate conduct while at the same time still providing deterrence to manipulative conduct,” it said.
PJM violated the filed rate doctrine by implementing its compliance filings prematurely, FERC said. To consider whether refunds should be issued, the commission said PJM must provide it information on how the RTO would calculate refunds and surcharges; details of the parties who would receive refunds or be charged surcharges; and information on the magnitude of the refunds and surcharges. “We are reserving judgment as to whether or not to impose refunds; that decision will be informed by PJM’s subsequent filing,” it said.
XO Energy, of Landenberg, Pa., challenged the tariff changes in an April 2020 complaint, saying it quit PJM’s virtual market in December 2019 after receiving $4.3 million in forfeitures. The company asked FERC to order the RTO to change the forfeiture rules or abandon it and adopt “a structured market monitoring approach” like the one used by MISO (EL20-41).
Thursday’s order dismissed XO’s complaint as moot “as it challenges a rate that is not in effect.” The commission also rejected several rule changes requested by the protesters as outside the scope of PJM’s compliance filings.
XO released a statement through attorney Ruta Skučas of K&L Gates saying it is eager to work with PJM and other stakeholders “to develop a more thoughtful and balanced FTR forfeiture rule.”
“This rule will be particularly significant as the volume of renewable resources increases in the PJM footprint and asset owners begin to hedge their intermittent output in the FTR and real-time markets,” it said. “Further, XO believes that refunds will be a significant needed component going forward, as PJM unlawfully over-collected forfeitures for over three years.”
FERC on Thursday reduced Entergy’s base return on equity to 10.37% from 11%, applying the methodology it adopted for MISO transmission owners in Opinion 569-A a year ago (ER13-1508-001).
The order reversed an initial decision issued in 2015 by the presiding administrative law judge governing sales of energy and capacity among the Entergy operating companies (NYSE:ETR). It also addressed briefs submitted in response to a 2019 order seeking input on the commission’s methodology.
The commission said it was not persuaded by the briefs to change its methodology, choosing to continue using the procedure it laid out in Opinion 569-A, which incorporated the risk premium model (RPM) into ROE calculations along with the discounted cash flow (DCF) and capital asset pricing models (CAPM) (EL14-12, et al.).
In 569-A, FERC said that in future proceedings, “parties will have an opportunity to argue that the base ROE methodology … should be modified or applied differently because of the specific facts and circumstances of the proceeding involving that party.”
But, the commission said, “no party has demonstrated that the methodology applied in those proceedings should not be applied to the facts and circumstances of this proceeding.”
It ordered Entergy to revise its unit power sales tariff and submit a report quantifying refunds with interest within 30 days. The new rate was made effective Dec. 19, 2013, when the tariff took effect, prompted by Entergy Arkansas’ withdrawal from the Entergy System Agreement.
| Entergy Arkansas
Commissioner Mark Christie (R) concurred in Thursday’s order, saying that the commission’s policy is flawed because “it replaces judgment with rote application of preset formulae.” He called for a general proceeding to consider changes to the methodology.
He also said the commission should set procedural deadlines requiring FERC to act much more quickly in future ROE proceedings.
“We are today putting into place an ROE with an effective date of Dec. 19, 2013 — roughly seven and a half years ago — ostensibly on the theory that these rates are required to incentivize investment in a future that began, at this point, several years in the past,” he said. “Although a certain amount of ‘lag’ is perhaps inherent in any regulatory system, I do not accept that this degree of delay is inevitable. Going forward, I believe we can and should do better.”
He added, “As indicia of why this commission’s ROE policy needs to be revisited, I would note that as of May 14, 2021, the 30-year U.S. Treasury bond — one of the most commonly used benchmark ‘safe’ investments — was yielding 2.36%. Thus the ROE approved in this order represents a risk premium of approximately 800 basis points. As compared to the 10-year Treasury bond, which was yielding 1.64% May 14, 2021, the ROE approved herein represents a risk premium of nearly 900 basis points.”
He acknowledged that rates on Treasury bonds were somewhat higher in December 2013 — with 30-year bonds slightly below 4% and 10-year bonds slightly below 3%. “On a going-forward basis, however, as well as for most of the past eight years, the risk premium represented by a 10.37% ROE is extraordinarily generous for a regulated utility.”
Commissioner Allison Clements (D) dissented, saying the 569-A methodology including the RPM does not protect consumers.
“The order of magnitude of transmission investment required to achieve [decarbonization, resilience and replacement of aged infrastructure] is unprecedented, which translates into a massive opportunity for utilities and transmission developers. But the value proposition for consumers is in no small part dependent on this commission’s rigorous scrutiny of the rates charged for transmission service, of which ROE is a central component,” she said.
“Given this context, I believe the commission must revisit its existing ROE policy. I appreciate that this policy has been unsettled for years, a state that increases investment uncertainty and extends litigation,” she added. “To be sure, I share the goal of a stable ROE policy that will speed rate proceedings and allow for timely ROE updates as market conditions change. But we should not double down on the desire for near-term stability to strong detriment of consumer protection, and I worry our current ROE policy does just that.”
But FERC Chair Richard Glick, who had dissented on inclusion of the RPM in the May 2020 order, indicated at the commission’s open meeting Thursday that he wasn’t eager to reopen the issue.
“When we issued opinions 569-A and 569-B, I expressed concerns about the commission’s decision to add the risk premium model, because the first ROE order had thoroughly explained why the risk premium model is not an appropriate tool for assessing a just and reasonable ROE,” he said. “I continue to have my concerns, but I also believe we cannot keep on changing our ROE methodology. Companies need to have some level of regulatory certainty if they are going to continue to make multimillion- — in some cases, multibillion- — dollar investment decisions.”
FERC last week ushered through three more unexecuted facilities service agreements (FSAs) between MISO, wind developers and transmission owners.
The unexecuted FSAs are a continuing protest against a 2018 commission order reinstating MISO transmission owners’ unilateral rights to self-fund network upgrades. Wind developers are leaving FSAs unsigned of late, hoping that interconnection customers will again be able to self-fund the upgrades necessary to connect to the RTO’s system. (See MISO TOs’ Self-funding Option Tested Again.)
The unexecuted FSAs stem from Next Era Energy’s 200-MW Heartland Divide II wind project in Iowa with transmission owner MidAmerican Energy (ER21-834, ER21-836 and ER21-837).
Heartland Divide II | NextEra Energy
Once again, the wind developer asked FERC to direct MISO to amend the FSAs by including a provision for the self-funding option’s possible reversal.
Once again, FERC declined.
In accepting the FSAs, the commission said it disagreed with NextEra’s argument for an amendment. FERC also said it wouldn’t take action on allowing interconnection customers to “retroactively annul and reverse … initial funding elections” should it later alter or eliminate the TO self-funding option.
The FSAs “appropriately reflect the state of the law as of the date the agreement becomes effective,” the commission said.
FERC Chair Richard Glick and Commissioner Allison Clements have said that MISO TOs’ absolute right to self-fund could be unfair. They said TOs could engage in preferential treatment among interconnection customers and that customers unable to finance upgrades at more favorable rates could be forced to reimburse TOs at a predetermined rate of return.
The two commissioners did not weigh in on the overall fairness of MISO’s self-funding options in the latest orders.
