Texas regulators last week praised ERCOT for its response to stakeholder criticism over how it handled an early March cold-weather event that prompted it to ask generators to reschedule planned outages.
Market participants publicly aired their concerns with ERCOT during a Technical Advisory Committee meeting March 27, arguing that the grid operator did not give the market a chance to work and that it had not adequately shared its insight into the market. (See ERCOT Generators Upset over Early March Weather Event.)
Since then, ERCOT has begun assembling a task force that will consider improvements to communications and procedures during anticipated emergency conditions; increasing the market visibility of ERCOT forecasts; reviewing how planned outages are delayed or withdrawn; and whether to develop cost-recovery mechanisms for outages postponed or canceled because of reliability reasons.
That was enough for the Texas Public Utility Commission to wave off a presentation by ERCOT Senior Director of System Operations Dan Woodfin during its open meeting Thursday. Woodfin had planned to deliver the same presentation he gave during two hours of discussion before the TAC.
“I’m happy to see you have a process now and you’re working on it,” Commissioner Arthur D’Andrea told Woodfin. “That’s promising to restore some confidence in the market and make some changes.”
“I would like the market participants to work this out at ERCOT, like we typically do,” PUC Chair DeAnn Walker said. “ERCOT acknowledges they can do things better. I’ve told everyone I’m not interested in going back and punishing anyone for anything that happened. I don’t want anyone dwelling on putting more arrows in Dan, because he got more than he deserved at TAC.”
The PUC opened a proceeding on ERCOT’s outage scheduling processes (Project 49378) and was moved to action after South Texas Electric Cooperative filed a complaint. STEC said it received an instruction to reschedule an outage at its 400-MW, lignite-fueled San Miguel plant less than 12 hours before maintenance work was to begin.
“ERCOT exercised what amounts to a free capacity call option … at great risk to both those generators and the market that have to perform maintenance or risk being subject to forced outages during the period of the lowest reserve margins the ERCOT market has ever seen,” STEC said.
Oncor ARR Reduced by $218M
The commission consented to Oncor’s request to reduce its annual revenue requirement by $218.8 million as a result of the Tax Cuts and Jobs Act of 2017 (Docket 48325).
The PUC directed Oncor to apply a 3.25% carrying charge to the amount of federal income tax expense it collects above the amount it would have collected since Jan. 1, 2018.
The commission also consented to staff’s wholesale transmission service charges for transmission and distribution service providers operating in the ERCOT system (Docket 48928).
Sempra-Oncor-Sharyland Hearing
The PUC held a prehearing conference Monday to accept exhibits for its April 10-12 hearing on proposed transactions involving Sempra Energy, its Oncor subsidiary, Sharyland Utilities, and Sharyland Distribution & Transmission Services (Docket 48929).
The companies in October announced deals worth $1.37 billion, with Sempra buying a 50% stake in Sharyland D&T and Oncor acquiring transmission owner InfraREIT. (See Sempra, Oncor Deals Target Texas Transmission.)
AEP Texas, Oncor Propose Asset Swap
AEP Texas and Oncor have filed an application with the PUC requesting transfer to AEP Texas of Oncor’s distribution assets and associated certificate of convenience and necessity rights in the Rio Grande Valley cities of McAllen and Mission (Docket 49402).
Under the proposal, AEP Texas would acquire Oncor’s distribution assets, valued at about $18 million, and about 54,000 retail distribution customers. Oncor acquired the customers during an asset swap with Sharyland Utilities in 2017. (See Texas PUC OKs Settlement in Oncor-Sharyland Asset Swap.)
AKRON, Ohio — A U.S. bankruptcy judge signaled Thursday he will not confirm a reorganization plan for FirstEnergy Solutions that would have absolved its parent company from liability for environmental damages from its coal and nuclear power plants.
FirstEnergy’s Akron, Ohio, headquarters
Bankruptcy Judge Alan Koschik of the Northern District of Ohio ruled orally from the bench that the “disclosure statement” FES must send to creditors describes a reorganization plan the court would find “patently unconfirmable.”
In other words, the judge has — at least for now — ruled the reorganization plan as proposed will not be confirmed.
FES said late Thursday it will submit a revised disclosure statement.
“Working with our advisors, we have already initiated action to address the court’s ruling and will submit a new request to have the disclosure statement approved in a timely manner,” said FES CEO John Judge. “The company remains focused on a plan that will significantly strengthen its financial position and allow it to exit Chapter 11 in 2019.”
Koschik said the restructuring plan giving broad protection to parent FirstEnergy Corp. does not meet case law established by the Sixth Circuit Court of Appeals.
Environmental groups, including the Sierra Club and a coalition led by the Chicago-based Environmental Law and Policy Center, had challenged the attempt to limit parent FirstEnergy’s environmental liability for months. The Ohio Consumers’ Counsel had also weighed in.
“Judge Koschik correctly determined that debtor FirstEnergy Solutions’ extraordinarily broad releases of environmental liabilities and responsibilities make the proposed reorganization plan ‘patently unconfirmable,’” wrote ELPC Executive Director Howard Learner in a statement released after the hearing.
Attorneys representing EPA, the Nuclear Regulatory Commission and other agencies weighed into the case aggressively in recent weeks saying FES lawyers had ignored them.
They made it clear they consider FirstEnergy responsible for power plant environmental damages and labeled the reorganization plan a “scheme.”
Koschik initially was not certain the bankruptcy court had the broad powers ascribed to it by FES attorneys to protect the parent company far into the future.
Complicating the situation was the court’s approval of a settlement FirstEnergy and FES negotiated last summer, with the concurrence of the major creditors. In exchange for indemnity, FE agreed to pay FES $600 million in cash and about $400 in services and limited guarantees.
While the judge approved that settlement, separating the two companies, he explained since then he did not approve the details absolving FE from future claims for environmental damage.
But in the months following that September 2018 court ruling, FirstEnergy ballyhooed the approval as proof it would now be profitable as a fully regulated, delivery-only company. That news helped push FE’s share price to a high of $42.13 in the last 52 weeks.
The stock tumbled more than 4% Thursday afternoon, closing at $39.44 on the New York Stock Exchange.
In filings late last month, opponents said approval of the proposed restructuring would make it difficult or impossible to file claims against FE over coal ash or nuclear contamination.
The OCC argued that, under the proposed reorganization, “FirstEnergy would be shielded from any claims or causes of action related in any way to the debtors’ businesses and property, including from any liability for the costly decommissioning of its power plants.”
“Were funds for decommissioning to be inadequate, for example, consumers or taxpayers might be (unfairly) called upon to fund FirstEnergy and FES’s power plant decommissioning liabilities to federal and state governments,” the OCC said.
ATLANTA — Despite the ongoing shift to renewables, the Eastern Interconnection has sufficient inertia to maintain system frequency for at least the next five years, according to a study released Thursday.
The Eastern Interconnection Planning Collaborative (EIPC), a group of 20 planning coordinators, conducted the study in response to a request by NERC’s Essential Reliability Services Working Group.
The working group had cited concerns about the retirements of synchronous generators such as coal and nuclear, which respond automatically to a frequency reduction by slowing down and releasing more energy into the grid. Asynchronous wind and solar power generators do not respond in the same way unless their inverters have been programmed to provide frequency control.
The EIPC’s study was released as a NERC standards development team (SDT) reviewing other aspects of frequency response issued a request for comment on continuing to rely on FERC Form 714 for data. (See “Comments Sought” below.)
Steven Judd, lead engineer in system planning for ISO-NE and chair of the EIPC Frequency Response Task Force, said the study provided reassurance in the near term and a foundation for future projects.
“This first effort to track the interconnection’s inertial response has established a framework and baseline for system planners to improve the system network models going forward, provide sufficient notice when the changing resource mix could have an adverse effect on frequency response and develop solutions to those adverse effects,” Judd said.
This figure Illustrates a frequency deviation due to a loss of generation and the methodology for calculating frequency response. Value A is the average frequency from t-16 to t-2 seconds. Point C is the lowest frequency observed in the first 12 seconds and Value B is the average from t+20 to t+52 seconds. The black line represents the point at which underfrequency load shed (UFLS) is expected to occur. | Eastern Interconnection Planning Collaborative
In order to prepare for the expected increase in nonsynchronous generation with reduced inertia, the report said planners will need improved frequency responsive power flow simulation models.
The report was based on several analyses, including benchmarking a historical frequency event with spring light load (SLL) cases, and concluded that about 45% of governors were providing primary frequency response, substantially higher than previous NERC studies, which pegged response at about 30%. Thus, for forward-looking frequency measures, 55% of the governors were disabled in the power flow model.
“It is expected future improvements to the modeling of governors through new compliance standards and updated simulation models from the software vendors will reduce the need for artificially disabling governor models to match historical performance,” the task force said.
FERC Order 842, issued in February 2018, requires all new generators seeking interconnections be equipped to provide primary frequency response. (See FERC Finalizes Frequency Response Requirement.)
The EIPC task force tested three frequency events against the 2022 SLL Multiregional Modeling Working Group (MMWG) power flow case:
The loss of 4,500 MW of generation in 2007, the largest historical event seen on the EI;
The loss of 3,100 MW on April 27, 2011, the largest event within the past 10 years; and
The loss of 2,513.7 MW, the most severe single contingency for the EI as defined by NERC standard BAL-002-2(i) Requirement R2.2.
In all three events, frequency response fell no lower than 59.85 Hz, well above the 59.5-Hz initial set point that would trigger under frequency load shedding (UFLS).
Under a fourth benchmark — a 10,000-MW loss modeled to determine the margin available in the EI — the frequency dropped to a low of 59.64 Hz, still above the UFLS set point.
“In other words, the system inertia and primary frequency response will be sufficient even with expected retirements of synchronous generation and increases in nonsynchronous generation,” the report said.
The results of the analysis were submitted to NERC for inclusion in its 2018 long-term reliability assessment.
On a related issue, the SDT for Project 2017-01 (Modifications to BAL-003-1.1) on Thursday issued a request for comments following a three-day meeting last week in Atlanta.
Phase II of the project is considering potential changes to make the interconnection frequency response obligation (IFRO) calculations and associated allocations more reflective of current conditions, considering load response and the generation mix.
The standard authorization request also requires the team to ensure that overperformance by one entity does not negatively impact the evaluation of performance by another and that measurements of primary frequency response are considered in addition to secondary frequency response.
“I think we’ve got a fairly balanced industry [view]” on the standard, said SDT Chair David Lemmons, of EthosEnergy. “Some people think things need to change. Some people are happy with where it is.”
The SDT asked commenters to address the fact that load and generation data from Form 714 is two years old by the time it is applied to actual operations under the standard. In the interim, balancing authority (BA) footprints can change.
Rich Hydzik of Avista said Form 714 was adequate for use under the standard and expressed concern that more current data might be “less robust.”
“I don’t think we want perfection to be the enemy of good here,” he said. “What we’re looking for is a fair allocation on the interconnection and the BAs.”
Greg Park of Northwest Power Pool and SPP’s Daniel Baker noted Form 714 also does not include data from Mexico or Canada.
“I think [714] does an adequate job … 99% adequate,” Park said. “But that 1% is administratively burdensome.”
Hydzik suggested later the data source could be dictated by the “fundamental question” of whether it is generators alone that are responsible for meeting the frequency response requirement (FRR). He noted load reductions don’t provide much frequency response “unless generally you’re paying for load to drop.”
Including load strengthens the case for retaining Form 714, which includes load and generation data, he said.
“If you’re going to make the leap that energy-producing resources actually provide your FRR … then we kind of move into the situation where we look at generation-only numbers and … allocate that way. It starts to look a little bit like [Texas Reliability Entity] at that point. … They have shown us what it looks like to go with the generation approach.”
SPP has cast a longing, yet casual, eye at Western markets for some time.
On Thursday, the Arkansas-based RTO made its long-held interest in the West official by “calling on interested utilities and other customers” to help build a real-time market “that will meet the electricity needs of the Western Interconnection.”
“We’re still a long way off from building anything,” SPP spokesman Derek Wingfield told RTO Insider. “We’re looking for people interested in an SPP market.”
Wingfield said the RTO, which has a footprint that stretches from Louisiana across the Great Plains to the Canadian border, has long had “casual conversations with some in the West” about the possibility of an SPP-designed market. Market services would be provided on a contract basis, allowing participants to maintain their independence from an RTO, Wingfield said.
SPP Region | SPP
SPP’s market would provide an alternative to CAISO’s Western Energy Imbalance Market, which was established in 2014 with the six-state PacifiCorp system as its first member. CAISO announced Wednesday it had added its first publicly-owned utility in the Sacramento Municipal Utility District and says its market has saved members nearly $565 million since it started. (See SMUD Goes Live in Western EIM.)
The RTO did not offer a timeline for its own imbalance market, saying once it found entities interested in market services, it would scope out the market’s needs before talking benefits and timelines.
Monroe would know. He has always been open to discussions with entities interested in joining markets, and he led SPP’s recent effort to absorb the Mountain West Transmission Group, an informal collaboration of 10 electricity service providers in the Rocky Mountains. That effort fell apart last spring, but it gave SPP a deeper insight into the Western Interconnection’s market needs. (See Mountain West, SPP Tout RTO Membership to Colo. PUC.)
In December, SPP will also become the reliability coordinator (RC) for more than a dozen Western entities. The RTO has been working closely with its new customers, future neighboring RCs and regulatory bodies to finalize the governance and operations plans for RC services.
“SPP understands Western utilities’ system needs and approach to business,” said SPP CEO Nick Brown. “Utilities have the daunting task of ensuring electric reliability and affordability for their customers. It’s been our experience that energy imbalance markets are a wonderful way to accomplish that.”
The RTO said its day-ahead market has provided participants more than $2.7 billion in savings since it launched in 2014, and it noted it has provided various services to “dozens of non-member organizations” on a contract basis.
“SPP has experience not only building and administering electricity markets but specifically doing it to meet the needs of a diverse group of customers,” Monroe said.
Pennsylvania lawmakers proposed another $500 million plan to subsidize the state’s nuclear industry and characterized as politically motivated ongoing criticisms that the effort represents a corporate bailout.
State Sen. Ryan Aument (R) introduced Senate Bill 510 on Wednesday, more than three weeks after a similar House of Representatives bill, HB 11, drew reproach for its perceived prioritizing of aging, expensive nuclear reactors over cleaner, cheaper forms of energy. (See Lawmakers Unveil $500M Nuke Subsidy Bill.) Nuclear generation supplied about 42% of Pennsylvania’s net generation in 2017, compared with 4.5% for renewables, according to the Energy Information Administration.
“Powerful special interests have disingenuously branded any support for the nuclear industry as a ‘bailout,’ but in reality, current law stacks the deck heavily against Pennsylvania’s nuclear plants,” Aument said. “Including nuclear energy in the state’s alternative energy plans will help level the playing field for the industry and ensure its long-term viability in Pennsylvania’s marketplace while simultaneously protecting ratepayers from higher electricity bills down the road.”
Three Mile Island
Like its House companion, SB 510 creates a third tier within the state’s Alternative Energy Portfolio Standard (AEPS) program, from which suppliers must buy 50% of their power by 2021. Unlike the House version, however, the Senate bill directs the Public Utility Commission to set credit prices and guarantee between 17 and 23% of Tier III sources purchased include non-nuclear suppliers, like wind and solar. The first two tiers of the AEPS include 16 renewable resource types with targets of 8% and 10%, respectively.
“Nuclear energy is the most efficient, carbon-free producer in our system,” Aument said. “The loss of Pennsylvania’s nuclear industry will inevitably lead to increased costs for ratepayers, a less reliable and resilient electricity grid, and a loss of billions of dollars for the state’s economy.”
Like its House companion, SB 510 looks to offset an estimated $4.6 billion in annual costs proponents claim would result from all five nuclear plants in the state shutting down: $788 million in higher electric prices; $2 billion in lost state GDP; and $1.86 billion in costs associated with carbon emissions and harmful criteria air pollutants, including SO2, NOX and particulate matter.
Exelon said it will begin the four-month process of closing Three Mile Island near Harrisburg in June if legislators don’t act. FirstEnergy has also scheduled Beaver Valley for early retirement effective 2021.
“Making long-term energy decisions based exclusively on short-term marginal cost would be foolish,” Aument said. “Far too often, Harrisburg is short-sighted and kicks the can down the road when faced with difficult economic choices. We have an opportunity now to do the right thing for ratepayers by preserving the role of the nuclear industry and avoid repeating the painful and expensive mistakes of the past.”
An analysis from ClearView Energy Partners determined the expanded carve-outs for non-nuclear resources in Tier III mean some of the state’s struggling reactors could still be priced out of the market. Both proposals require the PUC to rank resources based on environmental benefits, meaning low-generating reactors like TMI could be considered the “least beneficial” to operate, given SB 510’s additional targets in the third tier.
Skeptics Unsatisfied
Ryan Boop, Aument’s chief of staff, told RTO Insider the senator would not introduce a bill unless he was comfortable with the language.
“As such, we were very methodical in the drafting of SB 510 and took input from all six [Senate co-sponsors] and their staff members,” Boop said. “As a group, we sought feedback from the Public Utility Commission and various other sources. I think many of the differences in the two bills can be attributed to the additional time we had to draft the language and the additional input we received from the PUC and those other sources.”
But the modifications haven’t engendered any good will from the bill’s critics. Steve Kratz, spokesman for Citizens Against Nuclear Bailouts — a coalition of power generators and energy, business and manufacturing associations — characterized the long-awaited proposal as “disastrous.” He argued similar legislation in New York drove 99% of taxpayer funding for the program in 2017 directly into Exelon’s coffers.
“The ‘consumer protections’ and additional carve-out for renewables touted by the bill sponsors [are] a disingenuous attempt to distract away from the fact that this bill will irreversibly alter electric competition and force consumers to pay higher bills to benefit the special interests of Exelon, FirstEnergy Solutions and Talen Energy and shareholders,” he said.
PJM’s Independent Market Monitor said last month three of the RTO’s 18 nuclear facilities face revenue shortfalls through 2021, a natural reaction to competition. The three plants — Davis-Besse, Perry and TMI — each operate just one reactor, which is the source of their financial strain, the Monitor said. The remaining multiunit facilities, including the subsidized Quad Cities in Illinois, will remain profitable. Even without zero-emission credits, Quad Cities would cover its costs for the next three years, according to the Monitor. (See Monitor Says PJM’s Capacity Market not Competitive.)
The House Consumer Affairs Committee kicks off four weeks of hearings on HB 11 April 8. It’s unclear when the Senate will schedule meetings to discuss Aument’s bill, though it could come later this month.
Old and new will interconnect in an innovative way if researchers at Michigan Technological University can pull off an energy storage concept that pairs some of the state’s abandoned and flooded mines with hydroelectric pumped storage.
Researchers and students at the university are studying the possibility of using an abandoned mine in the Upper Peninsula for underground pumped hydroelectric storage. Representatives from Michigan Tech and the city of Negaunee say floodwaters from the lower levels of the mines could be pumped to higher, dry levels, using old excavations as holding tanks. Such a system would be essentially invisible, leaving the surface undisturbed, they say.
Roman Sidortsov, assistant professor of energy policy, said the pilot landscaping study is focusing on Negaunee’s Mather B, an iron mine that ramped up production after World War II and shuttered at the end of the 1970s.
The two-year pilot, funded by a $50,000 grant from the Alfred P. Sloan Foundation, will likely produce a report this fall on whether an underground pumped hydro storage facility is technologically and environmentally feasible. Sidortsov said the report will be intended for a broad audience, including “developers that contemplate energy storage projects and policymakers who might support them.”
Abandoned mine in Negaunee | reddit user MassaEwas
The research team will hold an April 26 brown bag lunch meeting where students who have been working on various aspects of the study will present their preliminary results, followed by a May 7 community meeting in Negaunee to provide updates on the pilot.
Researchers are at a preliminary stage in the project after holding the first meetings in December. Sidortsov said he and others are now waiting for a few feet of snow to thaw to begin accessing the mine, with student researchers planning on bringing snowshoes this week to assess the area.
“We live in a snow globe up here,” Sidortsov said in a telephone interview with RTO Insider. “We were helped in identifying the mine with city planners.”
For now, the work is focused on a “preliminary analysis to identify next steps,” Sidortsov explained. However, he said early engineering analyses relying on mine dimensions supplied by city planners are “incredibly optimistic.”
“We cannot wait to confirm those numbers,” he said.
According to Sidortsov, the “very, very back of the envelope numbers” show Mather B might be able to support up to a 50-MW nameplate capacity facility that can provide continuous output for up to three hours at a time. The facility would use surplus energy for pumping.
The idea is for a singular storage facility, but Sidortsov said research could show it’s more efficient to install multiple facilities in separate mineshafts.
Timothy Scarlett, Michigan Tech associate professor of archaeology and anthropology, said he and Sidortsov will have a better understanding of the feasibility of the project in July and August.
Until then, “we’ve been trying to under-promise and overdeliver,” Scarlett said.
Meanwhile, Michigan Tech students have already started research on surface water runoff and cybersecurity issues that could affect such a storage facility.
‘Post-industrial Landscape’
The researchers say this initial study is being conducted backward when compared to how a utility might approach a new generation project, where the design and engineering work typically come before community meetings.
Scarlett and Sidortsov said they began their work by engaging community leaders. It’s how they learned the team should choose the Mather B site instead of the original choice, the nearby Jackson mine, where a deadly accident had left miners entombed. Scarlett said the early meetings helped to uncover local sensitivities about different mines in the area. On advice from city officials, the Jackson mine was left alone out of respect for the families of the dead.
“Community members feel differently about different historic mines,” Scarlett said, adding that social acceptance of such a project is important in “post-mining, post-industrial” communities.
“It’s a sensitive issue for the community. In doing some of the research, we encounter things like this,” Sidortsov said.
Both researchers stressed there is no agenda to the research.
“One of the advantages of running a study like this is we don’t have an ulterior motive. Even if we’re proven wrong in our endeavor, it will be a bummer, but it will still be an important discovery,” Sidortsov said.
He said the pilot study will yield important insight into water control and quality, necessary proximity to transmission lines and other information that can be used for similar projects in other mines in the area. About 20 years ago, Michigan Tech cataloged more than 800 mines in the western Upper Peninsula alone.
However, if all goes well, Scarlett said they hope to use the pilot project as a launch to seek funding for a nationwide project on hydro pumped storage in abandoned mines. Sidortsov said even dry mines could host chemical battery storage or completely flooded mines could house compressed air storage.
“We’re not a developer; we’re not proponents of any kind of technology,” Sidortsov said.
But the researchers do have a certain backdrop in mind for such storage projects.
“The idea is to stick with this post-industrial landscape,” Sidortsov said. “What we’re also trying to do is directly appeal to the policymakers in Michigan.”
Surface shot of the Mather B mine hoist house taken sometime during the mid-century | Michigan Tech archives
The two are examining how such a concept might be monetized, boosted either by state-level tax credits or other financial incentives.
“This can be a transmission resource. This can also be the base around which distributed energy resources can be built,” Sidortsov said. “It gives an opportunity for intermittent resources to be connected to the grid. It also does present opportunities for grid resilience because it’s localized and you’re not depending on one large transmission line.”
But Sidortsov said Michigan Tech will look into the facility performing in several ways, including providing ancillary, capacity, generation and transmission services.
“We’re not bound by a particular use,” Sidortsov said.
The two are also hopeful that mine energy storage could help alleviate customer bills in the Upper Peninsula, which has been subject to expensive energy rates and multiple past system support resource agreements that fund aging coal-fired plants needed to serve the transmission-constrained region.
“We’re representatives of that customer group by virtue of our bank accounts, so the pain is personal,” Sidortsov joked.
Prohibitively high energy costs are also a concern for local governments, Scarlett said. “The leaders of these communities have identified this as one of their major concerns to economic development.”
‘Attractive’ Sites
The researchers still must track down the most recent maps of the mine and figure out what entity — if any — might still have rights to the underground areas. Sidortsov and Scarlett say, so far, they know the rock in which Mather B is situated has “soft” upper layers that were heavily reinforced in the 1970s. The upper levels of the mine might only need to be grouted to create a watertight reservoir, they said.
“Unlike a greenfield site that you would have to study, these mines come with a complete geological and hydrological study. It’s another reason why these sites are so attractive,” Sidortsov said.
He also said the mine’s year-round stable climate is a particular advantage for hydropower design. “You have essentially the same conditions year-round,” Sidortsov said. “With other hydroelectric sites, production varies with snowfall, rainfall … how much ice is on the river. Here, you don’t have that problem.”
The researchers also say the Upper Peninsula’s mines’ historic powerhouses might be adapted to connect the storage to the grid.
Even permitting might prove less of a headache, Scarlett said.
“The rights of way might still be there; you may not have to pay for them,” Scarlett said.
The ultimate goal, Scarlett said, is a “respectful design” in harmony with the original function of the mine’s industrial character. He said a plan that disturbs little while repurposing the mine might allow developers to access funds and credits that states or municipalities dedicate to historic preservation and adaptive reuse of historically important structures.
Sidortsov said the idea so far is receiving a surprising amount of bipartisan support in the state.
“Tim and I were just geeking out, then we quickly discovered it wasn’t just us,” Sidortsov said of the project’s roots.
ATLANTA — Despite the ongoing shift to renewables, the Eastern Interconnection has sufficient inertia to maintain system frequency for at least the next five years, according to a study released Thursday.
The Eastern Interconnection Planning Collaborative (EIPC), a group of 20 planning coordinators, conducted the study in response to a request by NERC’s Essential Reliability Services Working Group.
The working group had cited concerns about the retirements of synchronous generators such as coal and nuclear, which respond automatically to a frequency reduction by slowing down and releasing more energy into the grid. Asynchronous wind and solar power generators do not respond in the same way unless their inverters have been programmed to provide frequency control.
The EIPC’s study was released as a NERC standards development team (SDT) reviewing other aspects of frequency response issued a request for comment on continuing to rely on FERC Form 714 for data. (See “Comments Sought” below.)
Steven Judd, lead engineer in system planning for ISO-NE and chair of the EIPC Frequency Response Task Force, said the study provided reassurance in the near term and a foundation for future projects.
“This first effort to track the interconnection’s inertial response has established a framework and baseline for system planners to improve the system network models going forward, provide sufficient notice when the changing resource mix could have an adverse effect on frequency response and develop solutions to those adverse effects,” Judd said.
This figure Illustrates a frequency deviation due to a loss of generation and the methodology for calculating frequency response. Value A is the average frequency from t-16 to t-2 seconds. Point C is the lowest frequency observed in the first 12 seconds and Value B is the average from t+20 to t+52 seconds. The black line represents the point at which underfrequency load shed (UFLS) is expected to occur. | Eastern Interconnection Planning Collaborative
In order to prepare for the expected increase in nonsynchronous generation with reduced inertia, the report said planners will need improved frequency responsive power flow simulation models.
The report was based on several analyses, including benchmarking a historical frequency event with spring light load (SLL) cases, and concluded that about 45% of governors were providing primary frequency response, substantially higher than previous NERC studies, which pegged response at about 30%. Thus, for forward-looking frequency measures, 55% of the governors were disabled in the power flow model.
“It is expected future improvements to the modeling of governors through new compliance standards and updated simulation models from the software vendors will reduce the need for artificially disabling governor models to match historical performance,” the task force said.
FERC Order 842, issued in February 2018, requires all new generators seeking interconnections be equipped to provide primary frequency response. (See FERC Finalizes Frequency Response Requirement.)
The EIPC task force tested three frequency events against the 2022 SLL Multiregional Modeling Working Group (MMWG) power flow case:
The loss of 4,500 MW of generation in 2007, the largest historical event seen on the EI;
The loss of 3,100 MW on April 27, 2011, the largest event within the past 10 years; and
The loss of 2,513.7 MW, the most severe single contingency for the EI as defined by NERC standard BAL-002-2(i) Requirement R2.2.
In all three events, frequency response fell no lower than 59.85 Hz, well above the 59.5-Hz initial set point that would trigger under frequency load shedding (UFLS).
Under a fourth benchmark — a 10,000-MW loss modeled to determine the margin available in the EI — the frequency dropped to a low of 59.64 Hz, still above the UFLS set point.
“In other words, the system inertia and primary frequency response will be sufficient even with expected retirements of synchronous generation and increases in nonsynchronous generation,” the report said.
The results of the analysis were submitted to NERC for inclusion in its 2018 long-term reliability assessment.
On a related issue, the SDT for Project 2017-01(Modifications to BAL-003-1.1) on Thursday issued a request for comments following a three-day meeting last week in Atlanta.
Phase II of the project is considering potential changes to make the interconnection frequency response obligation (IFRO) calculations and associated allocations more reflective of current conditions, considering load response and the generation mix.
The standard authorization request also requires the team to ensure that overperformance by one entity does not negatively impact the evaluation of performance by another and that measurements of primary frequency response are considered in addition to secondary frequency response.
“I think we’ve got a fairly balanced industry [view]” on the standard, said SDT Chair David Lemmons, of EthosEnergy. “Some people think things need to change. Some people are happy with where it is.”
The SDT asked commenters to address the fact that load and generation data from Form 714 is two years old by the time it is applied to actual operations under the standard. In the interim, balancing authority (BA) footprints can change.
Rich Hydzik of Avista said Form 714 was adequate for use under the standard and expressed concern that more current data might be “less robust.”
“I don’t think we want perfection to be the enemy of good here,” he said. “What we’re looking for is a fair allocation on the interconnection and the BAs.”
Greg Park of Northwest Power Pool and SPP’s Daniel Baker noted Form 714 also does not include data from Mexico or Canada.
“I think [714] does an adequate job … 99% adequate,” Park said. “But that 1% is administratively burdensome.”
Hydzik suggested later the data source could be dictated by the “fundamental question” of whether it is generators alone that are responsible for meeting the frequency response requirement (FRR). He noted load reductions don’t provide much frequency response “unless generally you’re paying for load to drop.”
Including load strengthens the case for retaining Form 714, which includes load and generation data, he said.
“If you’re going to make the leap that energy-producing resources actually provide your FRR … then we kind of move into the situation where we look at generation-only numbers and … allocate that way. It starts to look a little bit like [Texas Reliability Entity] at that point. … They have shown us what it looks like to go with the generation approach.”
Stakeholders are urging PJM’s Board of Managers to reschedule the upcoming capacity auction, given the growing pile of issues on which FERC has not yet ruled.
The Joint Consumer Advocates sent a letter April 1 advocating for a temporary delay of the Base Residual Auction currently planned for August, contending it’s the best course of action to avoid possible legal and financial ramifications.
“If auctions are rerun, results refunded or other action taken, it is ultimately the end-use customers, including residential customers, who will bear those risks,” the group said. “These customers are least able to hedge against those risks.”
Likewise, a coalition of utility companies — including Exelon, American Municipal Power, Dominion Energy, EDP Renewables, Avangrid, NextEra Energy Resources, Public Service Enterprise Group and Talen Energy Marketing — said delaying the auction until April 2020 guaranteed the most time for stakeholders to adapt to any market rule changes handed down by FERC in the coming year. Seven dockets remain outstanding, the companies pointed out.
“By all public accounts, commission action does not appear imminent,” the utilities said in their March 29 letter to the board. “Given this inaction, the same concerns that led PJM to reschedule the 2022/23 BRA last August apply with equal force now. If anything, the need for clarity on auction scheduling is more severe now than it was last fall.”
| PJM
The letters come a week after PJM staff presented the Markets and Reliability Committee with four options for the August BRA, including do nothing and run the auction under current rules; file a delay waiver; file a request to confirm existing rules for the interim; or propose an interim rate. Each option came with considerable drawbacks, PJM’s Stu Bresler said during a March 21 MRC meeting. (See PJM Mulls Options for August Capacity Auction.)
It could be the second time PJM decides to delay the BRA after a June 2018 FERC ruling determined its minimum offer price rule (MOPR) was unjust and unreasonable. The RTO proposed a new rate in October and had hoped for a ruling from the commission by March 15 to no avail. (See PJM to FERC: Hurry Up with Auction Guidance.)
Although the utility companies want a delay of eight months — just six weeks before the regularly scheduled May 2020 BRA — consumer advocates want the briefest postponement possible, noting the competing interests of market participants, state utility commissions, legislatures and stakeholders.
“In that [first] waiver request, PJM stated that rescheduling the 2022/23 BRA was appropriate to allow stakeholders, PJM and FERC time to develop and establish appropriate replacement rules within a time frame that allows for the conduct of the BRA in an orderly manner,” the advocates said in their letter. “It is important that the PJM board not lose sight of these goals. PJM’s capacity market represents a large portion of the costs passed along to residential customers throughout the PJM footprint. Uncertainty in market rules and the permanence of market results can increase bids, which in turn increases costs.”
Bresler said PJM staff will reveal their decision for the auction at the April 10 meeting of the Market Implementation Committee.
The U.S. Department of Energy will collaborate with PJM to develop standards aimed at improving the integration of distributed energy resources onto the grid, the RTO announced Tuesday.
Under a new Cooperative Research and Development Agreement, Argonne National Laboratory will partner with PJM’s Distributed Energy Resource Ride-Through Task Force to study ride-through and trip guidelines from the Institute of Electrical and Electronics Engineers (IEEE) and adjust those rules to better serve PJM’s growing share of rooftop solar energy resources.
“Our primary mission is reliability, and we are preparing our system for the advent of more distributed energy resources so that we can seamlessly operate and understand DER behavior, both during normal operations and times of system stress,” said Chantal Hendrzak, executive director of Applied Innovation and Market Evolution for PJM.
“Our team has directly relevant experience in modeling and usage of simulation tools, and it has conducted similar analyses for the DOE and the North American Electric Reliability Corporation that can contribute to this joint effort,” said Ning Kang, an Argonne staff scientist who is leading the project with PJM.
| Cubit Power Systems
The lab also sent Rojan Bhattarai to work on site with the task force. He will analyze regional data, develop power system models with DERs and help PJM stakeholders fine-tune DER operational settings to maintain optimum system reliability.
Before the widespread adoption of DERs, the grid was designed to handle one-way power flows, with energy moving from generating plants through the transmission system, before being stepped down to the distribution system and ultimately transmitted to end-use consumers. The growing volume generation coming off the distribution network is forcing grid operators to rethink the system to accommodate unconventional flows.
PJM said DERs — including solar, battery storage, combined heat and power plants and some wind turbines — currently function on settings designed to respond to unexpected system malfunctions that disrupt power flow. Some sources “ride-through” the event, providing much-needed reliability, while others “trip-off” to prevent system damage. Solar panels and other DERs also can’t tell the difference between a transmission fault and a distribution fault, causing inappropriate responses and overstressing the system.
“For transmission system faults, DERs should stay connected to maintain reliability, while for distribution system faults, DERs should stop producing as fast as possible to ensure safety and protection,” Bhattarai said.
But there’s a key problem: DERs can’t detect where a fault occurred.
“So the challenge for PJM and others is to find a middle ground and come up with one set of operating rules that can ensure DERs function properly for faults on both the transmission and distribution side.”
The IEEE last year updated its standard for voluntary DER interconnection (IEEE 1574-2018), which informs trip and ride-through settings, but — as PJM acknowledges — “offers a fair amount of leeway,” leading utilities to implement different required settings.
“The combined PJM-Argonne team will study the impact of DER trip and ride-through timing in the current IEEE standard to help PJM stakeholders reach a consensus on DER integration,” PJM said. “It will also inform the technical guidance that utilities and states can use to implement DERs across the region PJM serves.”
A new ISO-NE whitepaper attempts to chart a course for the RTO to develop new market-based solutions to overcome New England’s long-term energy security challenges.
The RTO issued the whitepaper to the New England Power Pool Markets Committee just a week after filing an interim proposal with FERC to address winter energy security for the commitment periods covered by Forward Capacity Auction 14 (2023/24) and FCA 15 (2024/25).
The nearly 400-page interim plan calls for a voluntary two-year program to “provide incremental compensation to resources that maintain inventoried energy during cold periods when winter energy security is most stressed” (ER19–1428).
The RTO made the filing despite last month’s rejection of the proposal by the NEPOOL Participants Committee. Members also rejected a proposal by energy services firm Energy New England (ENE) that would have limited compensation to oil-fired and certain natural gas-fired resources, demand response and electric storage resources. (See ISO-NE Steady on Fuel Plan Despite NEPOOL Rebuff.)
New England natural gas flows | EIA
Pulling the Trigger
The RTO’s interim program consists of five core components, including a two-settlement structure, a forward rate, a spot rate, trigger conditions and a maximum duration for compensation.
Under the proposal’s two-settlement structure, resources would be paid or charged for deviations between the forward rate of $82.49/MWh for inventoried energy purchased in a forward position for the entire winter season and the spot settlement rate — $8.25/MWh — representing energy maintained during each trigger condition.
An “inventoried energy day” under the program is triggered for any day in December, January or February when the average of the high and low temperatures on that day, as measured at Bradley International Airport in Connecticut, is less than or equal to 17 degrees Fahrenheit.
The program’s maximum duration of 72 hours of generator compensation is designed to account for the incremental reliability benefit of another megawatt-hour of inventoried energy, decreasing as a resource maintains a greater quantity of inventoried energy, according to the filed testimony of Christopher Geissler, the RTO’s market development economist.
Adding another megawatt-hour of inventoried energy to a resource able to operate for 12 hours may improve the region’s winter energy security; however, if a resource has enough inventoried energy to operate for six months, then adding another megawatt-hour of inventoried energy “is unlikely to have a material effect,” Geissler testified.
Todd Schatzki, vice president of Analysis Group, testified on behalf of the RTO and estimated the program’s costs at $148 million per year, corresponding to approximately 1.8 million MWh of inventoried energy sold forward and maintained during trigger cold days throughout the winter.
“As these assumptions reflect maximum program participation, in a sense, this estimate provides an upper bound on the program’s potential costs, assuming forward settlement of all inventoried energy and no change in the region’s infrastructure,” Schatzki said.
Program participation may differ from assumptions, he said. For example, through lower-than-expected LNG contracting, resources may not supply the maximum eligible quantity of inventoried energy into the program, or resources may supply only a fraction of their capacity through forward settlement, which could lead to higher or lower payments if the number of very cold days differs from the number assumed in setting the forward settlement rate.
Fast and Easy, or Not
FERC in December approved the RTO’s initial Tariff revisions to use an out-of-market mechanism to address concerns about fuel security, filed after the commission in July denied a Tariff waiver to allow the RTO to enter a cost-of-service agreement to keep Exelon’s 2,274-MW Mystic plant running after its capacity obligations expire in May 2022.
The commission encouraged “ISO-NE to work with all interested parties, including NEPOOL, to continue to address their areas of disagreement while developing the long-term market solution.” (See ISO-NE Fuel Security Measures Approved.)
Ahead of NEPOOL discussions over the next six months on a long-term solution, the interim program first had to be simple enough to be designed and filed quickly, and not overly complex to implement, the RTO said.
Second, to be effective, the program should compensate resources that provide winter energy security. And third, “it should be designed consistent[ly] with sound market design principles, most notably providing similar compensation for similar service,” Geissler said.
Looking Ahead
The RTO’s whitepaper now looks at the region’s needs beyond FCA 15. To accommodate the complexity needed in a long-term solution, the document broadly recommends “expanding the existing suite of energy and ancillary service products” in the markets to address “the uncertainties and supply limitations inherent to a power system evermore reliant on just-in-time energy technologies.”
Three core components intended to spur discussion are a multi-day ahead market, new ancillary services in the day-ahead market and a seasonal forward market.
Many New England gas pipelines are subject to high capacity utilization rates, prompting ISO-NE to seek ways to ensure future fuel security for a grid increasingly dependent on just-in-time deliveries to gas-fired power plants. | EIA
The first would optimize energy, including stored fuel energy, over a multi-day timeframe and produce multi-day clearing prices for market participants’ energy obligations.
The second component would create several new, voluntary ancillary services in the day-ahead market to provide, and compensate for, the flexibility of on-demand energy.
The seasonal forward market would see the RTO conduct a voluntary, competitive forward auction to incent and compensate asset owners to invest in supplemental supply arrangements for the coming winter, the whitepaper said.
Referring to the paper, Marcia Blomberg, ISO-NE’s senior media relations specialist, said: “The ISO committed to posting this by April 1 to give stakeholders a basis for discussion as we work with them to refine the proposal to be filed at FERC by Oct. 15.”
