A coalition consisting of environmental advocates, zero-emissions generators and Illinois’ consumer advocate has developed a set of principles they say will “protect the cost-effective achievement of state policy goals to the extent possible” under FERC’s ordered redesign of PJM’s capacity market.
While the document doesn’t address applicability of PJM’s minimum offer price rule (MOPR), which sets floors for subsidized units’ capacity offers consistently above clearing prices, it does argue any unit subject to the MOPR should be eligible for the resource-specific fixed resource requirement (FRR-RS) FERC suggested in its order.
The principles also call for the FRR-RS to indicate as clearly and as early as possible whether state programs would be subject to the MOPR, along with providing a transition period so states can enact any laws they deem necessary. However, the document reiterated demands the FRR-RS also preserve states’ abilities to achieve clean energy policy goals.
The Natural Resources Defense Council’s Miles Farmer said that “part of it is to push PJM in this direction as well,” pointing out PJM’s proposal has progressively moved toward the principles, and “to make sure that FERC follows through on FRR-RS.”
The signatories “were all talking to each other around these PJM meetings, and we realized it makes sense to develop these shared principles,” he said, though he declined to offer specifics about who approached whom first.
Several stakeholder groups have proposed market redesigns, which stakeholders have been examining as part of special sessions of the Markets and Reliability Committee on the issue. (See PJM Unveils Capacity Proposal.) While the coalition is not advocating for any specific proposal along with the principles, many of the signatories support a proposal being represented at the meetings by consultants Rob Gramlich of Grid Strategies and James Wilson of Wilson Energy Economics.
Exelon’s Quad Cities nuclear facility, which benefits from Illinois’ zero-emissions credit program. | Exelon
An Exelon representative confirmed the proposal is endorsed by “a large coalition of odd bedfellows,” including the NRDC, Citizens Utility Board of Illinois, Sierra Club, Office of People’s Counsel for the District of Columbia, American Council on Renewable Energy, Exelon, Mid-Atlantic Renewable Energy Coalition, Talen Energy and Public Service Enterprise Group. All but PSEG are signatories of the principles document, which also includes the American Wind Energy Association.
Farmer said the principles have just been published and are expected to gather wider support as they become better known, adding no conclusions should be drawn from anyone who hasn’t signed on yet.
The proponents are all interested in PJM giving states capacity credit for units they subsidize to achieve state policy goals, such as procuring renewable and zero-emissions resources, and declare as a principle the credits should be applicable on a one-for-one basis.
For a unit to be eligible for FRR-RS election, it would need to be removed from the auction with a corresponding amount of load. The principle calls for making election at least four months prior to a Base Residual Auction and would need to be confirmed by a load-serving entity or state power authority at least 30 days before the auction.
Owners could also elect portions of units to be FRR-RS, and there would be no minimum length of time the unit would need to remain elected. Those units would continue to be Capacity Performance resources subject to PJM’s performance requirements and financial consequences.
“I take FERC at its word that it’s going to implement FRR-RS, but it still needs to do so in a way that’s workable so all the FRR-RS capacity is actually credited because setting this all up is not trivial and needs to be done with care,” Farmer said.
FERC on Tuesday granted Mexican wholesale marketer CFE International’s request to sell energy, capacity and ancillary services at market-based rates, clearing the way for the company to compete in U.S. power markets (ER18-1778).
The commission noted CFE International would place itself under FERC’s jurisdiction as a public utility and accepted its market-based rate authority, effective July 1. It also agreed with the company’s request for certain waivers and blanket authorizations commonly granted to market-based rate sellers.
Houston-based CFE International was formed in 2015 to market energy commodities. Its only member is Comisión Federal de Electricidad (CFE), the Mexican government-owned electric utility.
FERC ruled CFE International, as it requested, meets the criteria to be a Category 2 seller in the Southwest region (primarily California, Arizona and New Mexico) and a Category 1 seller in the Central, Southeast, SPP, Northeast and Northwest regions.
FERC will review Category 2 market-based rate sellers using the above regions every three years according to a rotating schedule. | FERC
FERC created the two categories in 2007 with Order 697. Category 1 sellers are wholesale power marketers or producers that own or control 500 MW or less of generation capacity in aggregate per region; do not own, operate or control transmission facilities, other than interconnection facilities; are not affiliated with transmission owners in the same region as the seller’s generation assets; are not affiliated with a franchised public utility in the same region as the seller’s generation assets; and do not raise other vertical market power issues.
Category 2 sellers are those that don’t fit into Category 1 and are required to file updated market power analyses.
CFE International had to clear FERC screens for horizontal and vertical market power. The commission agreed with the company’s claim that neither it nor its affiliate owns, operates or controls generation capacity in the United States but that CFE owns or contracts with capacity in Mexico. The company said its affiliated generation in Mexico could transfer up to 800 MW to the United States via two interties connected to CAISO, making that market the appropriate one to analyze its horizontal market power.
To pass the vertical power screen, CFE International had to show it had an open-access transmission tariff (OATT) on file or a FERC-approved waiver. Because CFE owns, controls or operates transmission facilities in Mexico that can be used by competitors to reach U.S. markets, CFE International had to prove its affiliate had a tariff or offered “comparable, non-discriminatory access” to its facilities.
The company noted CFE does not control or assign access to its facilities or Mexico’s transmission system, arguing all market participants receive access to the system because of their participation in the energy and ancillary services markets managed by the National Energy Control Center (CENACE) ISO. CFE International said participants could provide transmission service over the interties if CENACE cleared their bids in the day-ahead market.
FERC agreed with CFE International that network service in Mexico is comparable to the services provided under the pro forma tariff (OATT) in the United States.
There are three other interties between Mexico and the United States, all through ERCOT. Texas’ Public Utility Commission, which has jurisdiction over ERCOT, said it saw no issue with the order, pointing to a July ruling by FERC easing concerns over potential federal oversight. (See FERC OKs DC Tie Operations Between Texas, Mexico.)
An SPP spokesperson said the ruling won’t have an effect on its markets. He said, technically, CFE International could have already been making offers into the markets.
SARATOGA SPRINGS, N.Y. — The evolving challenges of grid resilience and the past and future of New York’s Reforming the Energy Vision took center stage at the Independent Power Producers of New York’s Annual Fall Conference on Friday.
Since its 2014 launch, REV has fostered cultural change at both utilities and the Public Service Commission, said James Gallagher, executive director of the Smart Grid Consortium, a nonprofit group promoting the use of new technologies in New York’s electric power system. “There’s much more flexibility, more openness to change and more collaborating to partner with outside organizations.”
The issue of resilience remains central, but letting go of command and control has not been easy for the utilities as they struggle to incorporate increasing amounts of distributed energy resources, he said.
“The commission invited utilities to come in with what they call ‘Platform Service Revenue Incentives,’ where they would get rewarded for facilitating local markets,” Gallagher said. “No utility has yet to come forward with an incentive proposal.”
Gallagher met former PSC Chair Audrey Zibelman in Australia and asked her what one thing she would change about how the commission handled REV under her leadership.
“Her one regret was that she permitted and encouraged each utility to have their own [Distributed System Platform],” he said. “She would now make one uniform DSP across the state.”
IPPNY CEO Gavin J. Donohue said a key challenge in public clean energy policy is to continue prohibiting utilities from owning generation, for example, in New York’s Energy Storage Roadmap now nearing final approval by the PSC.
On Sept. 10, IPPNY filed comments with the commission regarding energy storage, asserting that “private investors have a greater incentive to lower costs than utilities under cost-of-service regulation,” and that transmission and distribution should be separated from generation to eliminate the potential for generation-owning utilities to exercise vertical market power “to the detriment of wholesale competitive electricity markets and consumers.”
Sergej Mahnovski, director of growth and innovation for California-based Edison International, said customer demand, as well as regulation, has driven renewable energy growth.
Mahnovski, who used to work in New York, also said utilities initially dismissed REV as overly complicated, but “I always felt that if 10% of REV worked, it would make a contribution.”
Questionable Benefits
Couch White attorney Kevin M. Lang said he doesn’t think the utilities have changed much under REV, and referred to the second set of Distribution System Implementation Plans filed in June this year.
“All Con Edison reported was what they did the past two years, no cost allocation, no looking forward,” Lang said. “REV was about avoiding $30 billion in infrastructure spending, but now it’s about everything. We’re seeing tens and hundreds of millions of dollars spent for questionable benefits.”
Con Ed’s Brooklyn-Queens Demand Management project was meant to avoid the expense of building a new substation, he said, but some analysts estimate that over its 50-year lifespan, the project might cost $4 billion more than just constructing the substation.
“Consumers will use less electricity, but the reason is because they can’t afford it,” Lang said. “Reducing carbon in the atmosphere is a laudable goal, but we need a sense of balance.”
Industrial companies are leaving New York because they can buy power for a fraction of the price in other states, he said.
Laurence M. Downes, chairman and CEO of New Jersey Resources, a natural gas distributor and developer of clean energy projects, shared his positive take on decades of working with state regulators. New Jersey Gov. Phil Murphy earlier this year appointed Downes as chairman of the state’s Economic Development Authority.
“Since the 1980s, New Jersey has launched a host of public policy initiatives related to environmental stewardship … and as a mainly downstream company, we have come away stronger after every one of those,” Downes said. “If it were not for those public policy initiatives, we would not be serving customers literally in every state in the union right now, being in the solar business and being the leader in energy efficiency.”
Electricity is treated as a commodity, but it’s a critical national resource, said Sherrell Greene, president of Advanced Technology Insights.
Greene served as director of nuclear materials programs at Oak Ridge National Laboratory, where he worked for 33 years before founding ATI in 2012.
“Grid resiliency is a classic case of a tragedy of the commons; everybody’s a stakeholder but nobody owns it, nobody controls it,” Greene said. “And resilience does not apply across the board. You may be resilient to a cyberattack, but not to an electromagnetic pulse event.” (See FERC Orders Expanded Cybersecurity Reporting.)
The electric power grid is one of the largest machines ever created, so changing it is a challenge, said Arunkumar Vedhathiri, director of New Energy Solutions at National Grid.
“All of a sudden I have a swimming pool pump that can talk to the grid,” Vedhathiri said. “Consumers are not sure what they want from an energy company, but if you put an interface in front of them, they suddenly have a whole different relationship to their utility.”
He recounted how while on a beach in India last month he got a text message from a colleague telling him to cut energy use on a high peak day. Vedhathiri logged into his thermostat account, changed the setting, and “saved the grid from halfway around the globe.”
NYISO Executive Vice President Richard J. Dewey said New York is home to the oldest power grid in the world, and therefore “has some of the oldest electric infrastructure, which is something to keep in mind as we try to modernize the grid.”
Many New York generating plants also are nearing the end of their design life, he said.
The ISO is “working to establish market rules to appropriately price and value the benefits that renewable resources bring to the grid,” and favors a market approach to achieve whatever resilience characteristics are needed, such as dual-fuel capability, Dewey said. (See NY Debates CO2 Charge for ‘Beneficial’ Load.)
Marc Chupka of the Brattle Group recounted the U.S. Department of Energy issued a lauded study of the grid in August 2017, only to be followed in September by a Notice of Proposed Rulemaking to support coal and nuclear plants, which FERC rejected 5-0 in January.
Whether or not the scenario of natural gas curtailments was raised as a “stalking horse” by coal supporters, the controversy did begin the perception of fuel security as a resource attribute, Chupka said.
Fuel security is a New England winter peak issue, said Rob Gramlich, founder and president of energy consultancy Grid Strategies.
“Here we are with another hurricane and the issue is power — not generation, but the distribution and transmission infrastructure,” Gramlich said. “People need to plan for that. Old reliability contingencies don’t include climate change threats.” (See NEPOOL Debates Fuel Security, Cost Allocation.)
Todd Snitchler, director of market development at the American Petroleum Institute, said his group disputes the notion of natural gas being a dirty fuel.
“Brattle helped us with analysis that showed natural gas scoring very well on efficiency attributes, and natural gas is the enabling fuel for many renewable energy resources,” Snitchler said. “Natural gas is not so much a bridge fuel as a foundational fuel.”
SAN DIEGO — Struggling with a changing landscape of rooftop solar, electric vehicles and Western regionalization, transmission planners voiced their thoughts about an increasingly decentralized grid at Infocast’s 10th Annual Transmission Summit West last week.
“We’re conducting a paradigm shift here. It is not easy to perform transmission planning anymore,” said Bhaskar Ray, a distribution expert with Burns & McDonnell in San Francisco.
Ray sat on one of a dozen panels at the three-day summit, with about 100 in attendance. Speakers addressed topics such as the impacts of community choice aggregation, non-wires alternatives (NWAs) and distributed energy resources.
The overarching theme was a changing market driven by millions of rooftop solar panels and a dramatic increase in the use of EVs, especially in California. The state’s efforts to use 100% clean energy, to create a Western RTO and to spread its energy policies across the West were high on the list of concerns.
“It causes us small heart attacks” when we hear Californians say they are exporting their energy policies, said Kristine Raper, a member of the Idaho Public Utilities Commission, who was part of a panel of state policymakers.
California’s recent passage of SB 100, requiring the state to get all its energy from renewable and carbon-free sources by 2045, and the failure of AB 813, which would have begun the transition of CAISO into an RTO, received a large share of attention. (See California Gov. Signs Clean Energy Act Before Climate Summit.)
Here’s more of what we heard.
Policymakers Debate Regionalization
Energy leaders from Idaho, Utah and other Interior Western states said they’d only be interested in joining an RTO if it served their constituents’ best interests, especially with regard to costs, and if Californians didn’t control it.
“The governance is the piece that causes the most consternation,” Raper said.
AB 813 failed to make it out of the Senate Rules Committee in August, largely because California Democrats weren’t pleased with the idea of their state’s ISO being governed by outsiders from coal-burning states. The bill would have allowed CAISO’s governing body to include out-of-state members.
Several panelists at the summit said they didn’t see why it was necessary to have a single RTO in the West, while others were skeptical that any RTO was necessary.
“I don’t think it would be in my state’s best interests to jump two feet into a large-scale RTO,” said Cynthia Hall, vice chair of the New Mexico Public Regulation Commission.
Hall said she’d like to first see the effects of expanding the Western Energy Imbalance Market, possibly to a day-ahead market, which is a more incremental step requiring less commitment on the part of member entities. Public Service Company of New Mexico, for example, applied to join the EIM last month. (See PNM Seeks to Join Energy Imbalance Market.)
California leaders and interest groups had expressed similar sentiments after AB 813 stalled in committee.
In a separate panel on regionalization, Laura Nelson, with the Utah governor’s office, said the pros and cons of a Western RTO have yet to be determined. Market efficiencies could be offset by problems with policy and governance, she said.
“We are concerned about what those costs and risks might be, and we don’t fully understand the benefits,” Nelson said.
DERs Will Prove More Challenging
The increasing role of DERs arose in several panel discussions.
“We see them moving forward aggressively,” said Neil Millar, CAISO executive director of infrastructure development.
The ISO predicts the generating capacity of residential solar panels and other behind-the-meter DERs will grow from about 8,000 MW today to 17,000 MW in the near future, Millar said. That will put a strain on systems that were meant to distribute energy from central power plants, not to gather it from rooftops.
“We have to look at a much broader range of assumptions, scenarios and operating conditions,” he said.
Patrick Damiano, the president and CEO of ColumbiaGrid, agreed.
“DERs are invariably coming to the system,” he said. Utilities will lose control of generation and information, while consumers will gain it, he said.
What’s needed for planning purposes is greater transparency of DER usage and a way to model the effects of so many scattered generation sites, Damiano said. The amount of data that needs to be collected is daunting, he said.
“In some ways that integrative-resources process has become more disintegrated,” he said. “It’s not a statement that it’s a good thing or a bad thing. It’s just reality.”
Non-Wires Alternatives Gaining Ground
The rapid growth of DERs occupied much of the discussion on NWAs, which also include battery storage and other changes to the grid that don’t necessarily involve large-scale infrastructure projects, such as new transmission lines.
Louis Ting, director of planning and development for the Los Angeles Department of Water and Power, said the department is experimenting with numerous pilot projects to serve its 1.5 million customers in the 500 square miles of the city.
“On the non-wires alternatives, it’s been a very interesting journey to say the least,” Ting said. With little room to build new infrastructure, LADWP has been working to optimize its resources, including by leasing rooftops for solar power and talking with EV owners about drawing energy from the vehicles’ batteries, he said.
In the Pacific Northwest, Avista Utilities still mainly relies on traditional modes of generation such as natural gas, but the company is seeing increased interest from its customers in alternatives that allow them to produce their own power, Avista engineer Curtis Kirkeby told the summit audience.
“Our biggest customers are asking how they can play,” including by putting generating assets on their structures, he said. “We’re getting a lot of pressure to have alternatives for them.”
The utility has been working hard to figure how best to incorporate DERs and to become more proactive with planning, he said.
“Transmission planning has been done a certain way forever,” Kirkeby said. Now, he said, “it changes every single day.”
VALLEY FORGE, Pa. — PJM and some stakeholders are at odds over whether access to the transmission grid is a right generators purchase through interconnection upgrades or an opportunity granted by load to serve its needs. The philosophical difference is playing out in efforts to streamline the process for capacity resources seeking exceptions to offering into Base Residual Auctions.
PJM has proposed allowing generators to request exceptions from multiple auctions at once and allow timing as an acceptable reason for an exception. It also would clarify the documentation required by the RTO and its Independent Market Monitor for being removed from capacity resource status.
Lowman Step Up Substation | Central Alabama Electric Cooperative
Exelon, which initiated discussion of the issue, offered a proposal that differs from PJM’s only in not requiring a status change for units that are continually approved for an exemption and don’t offer into a BRA after three consecutive delivery years.
That is potentially the difference between whether the unit must relinquish its capacity interconnection rights (CIRs), which grant access to inject generation into the transmission system. If not enough CIRs are available, generators must pay for system upgrades to address their needs or risk not being allowed to sell all the power they can produce. Excess CIRs can have value and be sold.
At last week’s Market Implementation Committee meeting, Gary Greiner with Public Service Electric and Gas supported Exelon’s position, arguing that because generators spend millions of dollars for the upgrades the CIRs are the companies’ property.
Monitor Joe Bowring and ODEC’s Mike Cocco defended PJM’s proposal, arguing that load has spent billions to develop the transmission system that makes the rights possible. Bowring said the CIRs are for units that want to provide capacity for load and that “hoarding” them without committing to provide capacity is “effectively blocking” new units that do want to make that commitment.
“Imagine if [companies] had a benefit to restricting access to other competitors. … That does not make sense,” Bowring said. “If you can’t provide the capacity, it doesn’t make sense to block others who can. … You don’t own the right in perpetuity to inject power into the system because you paid for” necessary upgrades.
“It’s not a ‘forever’ property right. Many of these capacity injection rights were assigned to generators without them incurring any interconnection costs. They have an obligation to clear the capacity market within a three-year time frame or they lose these rights,” Cocco said.
David “Scarp” Scarpignato searched for middle ground.
“I agree with Joe,” he said. “There is a potential hoarding issue here. But there’s also on the other side, people pay for some rights.”
He explained that units that have received exceptions would become uncommitted capacity resources rather than energy-only resources and would keep their CIRs if they pass PJM’s annual deliverability tests.
Exelon’s Jason Barker noted that generators maintain CIRs only until one year after deactivation of the unit, so it “doesn’t exist in perpetuity.”
“The question is whether you’re meeting the requirements of the [Capacity Performance] paradigm, which changes on a regular basis,” he said.
He pointed out that generators’ interconnection service agreements would also need to change and there would be a “necessary discussion” if PJM made a proposal to change them.
Roy Shanker, an economist who often represents individual generators, said the key is determining whether a generator has no intention to offer into the auction or is simply delayed in doing so.
“If you aren’t trying to make progress toward [becoming a CP-compliant unit within three years], it is a form of withholding,” he said. “If you identify a market power issue, you fix it. … All this other stuff is irrelevant.”
VALLEY FORGE, Pa. — Generation reserve margins might drop and fuel-assurance risks could increase if coal and nuclear units retire sooner than anticipated, according to the preliminary findings of a NERC study focused on PJM and ERCOT.
PJM staff confirmed at the RTO’s Planning Committee meeting on Thursday that NERC had discussed the study at its own Planning Committee meeting earlier last week. The draft report has been sent out to members of NERC’s PC for comment, with the reliability overseer planning to present the final version to its Board of Trustees at its meeting on Nov. 6-7.
NERC spokesperson Kimberly Mielcarek said the target for public release is “before the end of the year.”
She declined to provide details before the study is final but pointed to the PC agenda, which outlines the study’s history.
NERC began soliciting policy input in May 2017 from stakeholders, proposing to conduct “an assessment of the potential impacts on Bulk Power System (BPS) reliability that could be caused by accelerated retirements of traditional baseload generator resources … to understand and address reliability challenges associated with the changing resource mix.”
NERC’s report would address accelerated closures of units like the Oyster Creek nuclear plant (shown in 1998), which shut down on Monday.
NERC staff analyzed aggregated supply and demand projections for the study, along with engineering studies on specific retirement scenarios. They also reviewed regional processes for managing plant deactivations.
According to the agenda’s description, the study found that “when generation retirements exceed or outpace needed replacement resources, the BPS is less capable of withstanding contingencies, unplanned facility outages and extreme conditions.”
It added that “replacing retiring coal-fired and nuclear generation with natural gas-fired generation provides essential reliability services but can result in near-term stress on the natural gas infrastructure and create challenges to fuel deliverability in extreme winter conditions and major natural gas contingencies.”
Managing those issues will require “continued adherence to rigorous resource adequacy assessment and transmission planning processes” as “large amounts of generator retirements can result in extensive network upgrade requirements” and “potentially the increased use of out-of-market solutions such as reliability-must-run (RMR) designation to address resource adequacy issues,” NERC said.
VALLEY FORGE, Pa. — PJM has scheduled a two-day workshop on enabling distributed energy resources to “ride through” frequency fluctuations but postponed action on a task force on the issue in the face of stakeholder concerns.
PJM’s Emanuel Bernabeu told the Planning Committee last week that the workshop is the first step in developing a guidance document for how DERs should implement a ride-through standard and presented a problem statement and issue charge to create a DER Ride Through Task Force. The proposal met with immediate concern from representatives of transmission owners, who felt it focused on jurisdictional issues rather than safety and reliability.
“That gives us pause,” FirstEnergy’s Jon Schneider said. “The spirit of this initiative is really to find the right balance … so it can support the bulk transmission system and the distribution system. … What’s resonating is jurisdiction rather than safety.”
“Absolutely what we want to do is what you described,” Bernabeu said.
Duquesne Light’s Tonja Wicks also voiced concerns, including that a focus on interverter-based technologies that was in previous versions of the proposal had been removed. That focus was challenged as not being technology-neutral during the proposal’s first read at last month’s PC meeting, but Wicks said the scope could be overly broad without it.
The reticence threw a wrench in PJM’s plan to receive approval for the task force in advance of the two-day workshop, which has already been scheduled for Oct. 1-2. Bernabeu received no concerns with his explanation of the issue at the monthly Operating Committee meeting earlier last week. There, he highlighted three disturbances within the past 12 years that were triggered by large amounts of renewable generation disconnecting from the grid in response to frequency fluctuations. A 2006 outage in Europe — which Bernabeu called “one of my favorite blackouts” — identified the threat from many small generators collectively tripping in what’s been termed the “50.2-Hz Problem.”
“Basically, they did not have this concept of ride-through,” Bernabeu said, adding that similar issues occurred in two subsequent incidents in Southern California and Australia in 2016. “You would think we would have solved this.”
A challenge in PJM’s territory, he said, is that the vast majority of DERs aren’t under PJM’s authority and instead follow state and local regulations. Staff hope the task force will settle on a standard that can then be provided to state and local regulators as guidance. The issue charge calls for developing a PJM-wide “profile consisting of an abnormal voltage and frequency performance category and specified trip settings, if adjusted from the defaults.” As an alternative, the rule could specify minimum ride-through and trip times and defer to distribution utilities on implementation details, the issue charge said.
The topic isn’t “overly complex,” Bernabeu said, but will require a broad group for input.
“We can’t ignore the fact that it’s the vast majority of DER sources. … What we want to establish is consensus across the footprint on specific standards,” he said. “If we succeed, everyone will embrace it.”
Staff agreed to postpone requesting a vote on the proposal to address TOs’ concerns, but they also asked if there was any issue with holding the workshop as scheduled on an “ad hoc” basis. No one opposed.
Vote Delayed on Capability Testing
Staff had also agreed prior to the meeting to postpone a vote planned on revisions to Manual 21 that would change some of the procedures for generators’ annual capability testing. The proposal has created concern because it could reduce units’ capacity injection rights. (See “Skepticism of Gen Capability Changes Continues,” PJM Operating Committee Briefs: June 5, 2018.)
PJM’s Patricio Rocha-Garrido also presented an analysis of the effective load carrying capability (ELCC) for wind units. The study calculated ELCC values for each year from 2009 through 2017 using the 12,540 MW of wind units projected to be operating in 2021. It found that the mean ELCC is 11.5% of the nameplate capacity and the median is 10.2%. The numbers backed up PJM’s argument for using median capacity factors for wind rather than mean. The median of capacity factor values PJM calculated for wind output from 2015 to 2017 was 7.9%, while the mean was more than twice as high at 16.7%.
Some stakeholders were critical of the analysis, saying it didn’t account for geographic differences and that using historical numbers for expectations of future performance ignores technology improvements.
“I don’t think we should be using any assumptions on the future, because what do we assume?” Rocha-Garrido said in response. He added that while GEMARS, PJM’s hourly loss-of-load-expectation tool, is capable of more detailed analyses, the study was in relation to the installed reserve margin, which is calculated at the RTO level, so “it’s immaterial to me where [the units] are located.” He acknowledged that units could receive a higher value if they were able to increase their output during the hours tested but said he doesn’t “see a significant difference” between PJM’s methodology and alternatives suggested by stakeholders.
Dave Mabry, representing the PJM Industrial Customer Coalition, said he was still trying to understand the differences between the RTO’s study and a similar study by General Electric that came to different conclusions. He suggested that perhaps ELCC is the metric that should be used for measuring wind capacity.
Rob Gramlich, representing the American Wind Energy Association, criticized what he felt was a low amount of data provided and said he appreciated PJM tabling the vote for further discussion.
“We still have a lot of concerns,” he said.
IRM, FPR Reduced
PJM is recommending a 15.7% IRM and a 1.0887 forecast pool requirement (FPR) for next year’s Base Residual Auction, both of which are slight reductions from last year. The IRM recommendation fell 0.1% and the FPR — which reflects the reserve margin to account for peak loads and generator outages — dropped 0.0011, both based on the 2018 capacity model.
Update on Integrating Cost-containment Guarantees
PJM’s Mark Sims outlined staff’s work on integrating cost-containment guarantees in its analysis of developers’ proposed transmission projects. The five-step process will standardize the cost-containment measures offered in each proposal, present them in a visual way, compare them and allow staff to choose the “most economically efficient” proposal. Sims said it will all be implemented into a comparative matrix and that stakeholders should expect to see more details about each of the five “boxes” in the coming months.
“You would expect to see this as part of the overall decision-making process,” he said. “This is our high-level concept. We are into the weeds with the [Independent Market Monitor] on several of these boxes.”
He said “the most challenging pieces right now are” figuring out how to standardize the proposals and then crunching the numbers to evaluate them. Staff sought input from a “large corporate lender” and are not anticipating lender risk being “a huge factor” in evaluation, he said.
LS Power’s Sharon Segner, who led the effort to incorporate cost guarantees into PJM’s evaluations, voiced her approval of the progress. (See “Delay Approved for Cost Containment Comparisons,” PJM MRC/MC Briefs: Aug. 23, 2018.)
“This is all sounds very good,” she said. “It is a hard assignment, and we very much appreciate what you’re doing. But this is an important discipline to establish.”
First M-3 Experience
Dominion Energy’s Ronnie Bailey briefed stakeholders on 13 violations of its system planning criteria his company plans to correct— implementing for the first time the TOs’ new process for supplemental projects, which is detailed in Tariff Attachment M-3. (See AMP Offers ‘Best We Can Do’ on PJM Tx Planning.)
In accordance with the M-3 processes, Dominion will follow up at a subsequent meeting with how it plans to address the issues.
FERC Orders on Tx in Calif.
PJM and American Municipal Power have agreed to revise their proposals for developing transmission-replacement processes to reflect FERC’s Aug. 31 rulings that Order 890’s transparency provisions do not apply to “asset management” projects that provide only “incidental” increases in transmission capacity.
The orders (EL17-45 and ER18-370, AD18-12), which rejected complaints by California regulators and others, were discussed at a special session of PJM’s Markets and Reliability Committee that met briefly after the Transmission Expansion Advisory Committee meeting. (See ‘Asset Management’ not Subject to Order 890, FERC Rules.)
PJM’s Chris O’Hara said the focus during the RTO’s stakeholder process hasn’t included maintenance.
The RTO and AMP will revise their proposals so they can be presented at an Oct. 16 meeting on the issue and prepared for consideration at the Oct. 25 MRC meeting.
“I think the goal from PJM’s perspective is we have an ongoing process and in that process, we want to provide the appropriate level of process and transparency while avoiding any unproductive litigation that may come from it,” O’Hara said.
AMP’s Lisa McAlister said including maintenance has “never been AMP’s goal.”
VALLEY FORGE, Pa. — In a rare occurrence, half a dozen residents opposed to PJM’s largest-ever congestion-reducing transmission project attended last week’s Transmission Expansion Advisory Committee to protest the RTO’s reconfirmation that the project would be beneficial to the public.
The $366.17 million project proposed by Transource Energy would consist of two separate 230-kV double-circuit lines, totaling about 42 miles, across the Maryland-Pennsylvania border — one between the Ringgold substation in Washington County, Md., and a new Rice substation in Franklin County, Pa., and another between the Conastone substation in Harford County, Md., and a new Furnace Run substation in York County, Pa. (See Line Opponents Set Sights on PJM in Public Campaign.)
PJM’s annual re-evaluation of the project’s benefit-to-cost ratio found that it had increased to 1.42 from a 1.32 evaluation published in February. The RTO’s threshold for considering such market efficiency projects is 1.25. The new evaluation included an increase in the project’s cost from its original $340.6 million estimate. PJM’s Nick Dumitriu said he spent an extensive amount of time attempting to make the analysis as comprehensive as possible and said “there are good reasons why” the ratio increased.
However, Vice President of Planning Steve Herling admitted “you can never know you have all the data” for evaluating a project and that “you have to put a stake in the ground” to determine what set of information is used.
“It’s unfortunately a moving target,” he said. “We’ve had lines where the supplemental analyses [found], based on the passage of time, the need erodes.”
“How do you expect us to have trust in your figures when you’re telling us now you don’t know,” asked Patti Hankins, one of the objecting residents of Harford County. She noted that PPL told Pennsylvania regulators it could add another cable on an existing right of way that parallels the proposed route. “That’s a hard thing for us to swallow,” she said, when state officials “all understand there’s existing infrastructure that can support this” upgrade.
PJM has previously confirmed that PPL also proposed a project to address the congestion on the AP South interface, which the Transource proposal also targeted. But PPL’s proposal only upgraded a nearby substation, didn’t include utilizing the extra space it has on its existing line and failed to achieve a benefit-to-cost ratio that exceeded the 1.25 threshold, RTO officials said.
While staff acknowledged the residents’ concerns, Herling said the decision to move forward with the project is now in the hands of state regulators to determine whether it should receive necessary permits. He added that staff “will certainly support” the commissions with any analyses they request.
“We’re not in a position to essentially usurp a state’s authority and take action on determining whether or not the project should move forward,” Herling said, indicating that staff will go back to the drawing board if the project is denied. “Our audience right now are the two commissions, and … we will abide by whatever decisions Pennsylvania or Maryland require us to make.”
The states’ consumer advocates showed interest, with representatives from both agencies asking questions about PJM’s analysis process. Gary Alexander from the Maryland Office of People’s Counsel questioned the urgency of the project, asking why Transource hasn’t yet entered into contracts with suppliers.
Herling said the company is getting bids. “I don’t know what the sequence of activities will be for executing those contracts,” he said.
FERC could also throw a wrench into PJM’s analysis. The Markets and Reliability Committee endorsed Tariff revisions in August that would exclude generating units with facility study agreements (FSAs) and suspended interconnection study agreements from PJM’s base case for analyzing market efficiency projects. The RTO says including these units causes unrealistic benefit estimates for proposed transmission projects. (See “Market Efficiency,” PJM MRC/MC Briefs: Aug. 23, 2018.)
Staff acknowledged that projects may need to be re-evaluated if FERC accepts the revisions.
“I think we’re going to have to look at units on a project-by-project basis” to determine if FSAs made a difference, Herling said. “We just don’t have time to run sensitivities ahead of time.”
However, he said if FSAs were removed from the Transource evaluation, the ratio would actually increase “based on current factors.”
The math did little to reassure the residents, who said they were being forced to waste time on a process that should be an easy decision.
“From the ground, the people see that PJM is not working in the interest of the ratepayers,” Harford County resident Aimee O’Neill said. “We must simply slog through it. … You are making it a very expensive process [when it] is apparent [there is] an alternative to a greenfield project.”
Herling said the current process will continue for the Transource project, but he conceded that staff needs better engagement with states.
“They have a process, we have a process, and we need to change that moving forward,” he said.
CARMEL, Ind. — MISO last week said it might rely on a long dormant analysis to create a pricing structure to compensate resources for delivering energy to restore the system in the event of the real-time market ceasing to function.
Speaking at a Sept. 13 Market Subcommittee meeting, MISO Director of Market Services John Weissenborn said a five-year-old white paper on the subject provides good recommendations for compensating resource owners and allocating costs when portions of the system are islanded.
MISO’s Steering Committee directed the Market Subcommittee to take up the issue in July on recommendation from the Reliability Subcommittee after nearly five quiet years on the topic. (See MISO Stakeholders to Reconsider Restoration Pricing.)
The white paper proposes a framework that allows MISO to make real-time pricing adjustments for islanded areas to facilitate real-time and day-ahead market settlements while providing generators the ability to make further revenue adjustments to ensure adequate compensation for the production costs of providing energy.
MISO said the pricing relies on the monitoring of generator output and load served within an island. Generators within a separated area would receive an hourly restoration cost recovery calculated by multiplying the number of megawatt-hours served by either 110% of their FERC-approved rate or $100/MWh, whichever is greater. Asset owners could also file a restoration energy rate with FERC that includes start-up, fuel and variable operation and maintenance costs with FERC and submit the approved rates to MISO.
To recover from a total blackout, MISO would turn over generation control of islands to local balancing authorities (LBAs) until those areas can be turned back over for dispatch. Restoration pricing would be in effect from the first partial hour of the blackout to the last partial hour prior to re-synchronization with the grid. Until MISO establishes a firm, interconnected grid, LBAs will have control of connected market generation, though the RTO’s system will have begun generating LMPs.
Weissenborn said the issue would require a Tariff filing. He added that MISO “isn’t looking for a 14-page” standalone filing, but “something we can provide in the Tariff to capture our intent to cover this compensation if we have one of these events.”
Currently, islanded commercial pricing nodes are assigned LMPs from a functioning nearby pricing node in the footprint.
Weissenborn also said the white paper might need some updating because of its age.
“I’m not saying that we’re going to turn this thing upside down and redo it, but I do think it provides good guideposts,” he said.
It’s unclear whether MISO plans to use the same megawatt cost values in an updated version of the pricing calculation.
Weissenborn said the restoration pricing structure will not impede the restoration energy plans of LBAs already in place. In its white paper, MISO said its “strategy to restore the system to normal operation does not rely on economic commitment and dispatch but instead addresses the immediate need for energy supply needed to support stable power system operation.”
“We’re going to first think about getting the lights back on, but then we’re going to have to contemplate compensation,” Weissenborn said.
Stakeholders at the meeting asked MISO to involve the Independent Market Monitor in drafting Tariff language. Others urged the RTO to consider the extraordinary incidental costs of weather-related events, such as utilities providing lodging and meals for working employees when their homes have been destroyed.
Weissenborn said he would return to the Market Subcommittee in November for more discussion. He said MISO may convene a special stakeholder group to help create the pricing structure.
VALLEY FORGE, Pa. — PJM staff have incorporated stakeholder input into their recommendations resulting from the quadrennial review of the variable resource requirement demand curve, the RTO’s Jeff Bastian told last week’s Market Implementation Committee meeting.
Staff have decided to recommend no changes to methodologies for several figures, while reducing the cost of new entry values by several hundred dollars, Bastian said.
He said staff hadn’t come to a decision yet on whether major maintenance costs should be included in fixed or variable operations and maintenance calculations.
“We’ve got to go with one or the other. We can’t have two VRR curves,” he acknowledged.
Review of Fuel Cost Policy Rules
Stakeholders endorsed a problem statement and issue charge to review several parts of the fuel-cost policy (FCP) rules and cost-based offer procedures hashed out last year. Sponsor John Rohrbach, who represents ACES on behalf of the Southern Maryland Electric Cooperative, said he is seeking “some modest discussions” to fix “little mistakes.” The proposal was also sponsored by Old Dominion Electric Cooperative and Panda Power Funds.
Rohrbach suggested that the rules could potentially be improved to determine whether self-scheduled units and zero-marginal cost wind and solar generators need FCPs. Rohrbach also questioned whether generators should have to confirm annually that their FCPs remain compliant and suggested creating a “safe harbor” from regulatory action for “minor” FCP violations and crediting generators for self-reporting potential violations.
It would also address timing issues that can arise when units change ownership.
Transmission Constraint Relaxation Removed
Stakeholders also endorsed new language in Manual 11 allowing transmission constraint penalty factors to set shadow prices for violated constraints. The current practice of relaxing transmission constraints doesn’t let the penalty factors set prices, which results in inefficient clearing prices that don’t reflect market conditions, PJM’s Angelo Marcino explained. The proposal, developed jointly by PJM and its Independent Market Monitor and resulting from an IMM problem statement was also preferred over the status quo.
Marcino said PJM won’t be making changes to market-to-market transmission paths until MISO and NYISO have upgraded their systems, which he said isn’t likely until at least next April.
Exelon’s Sharon Midgley thanked the Monitor and PJM for providing analysis on market impacts that helped her company become comfortable with the proposal.
The Monitor previously determined that in 2017, the revisions would have increased net load payments by $13.5 million, or 0.06%, and increased net generation credits by $10.1 million, or 0.04%. (See “Transmission Constraint Penalty Factor,” PJM Market Implementation Committee Briefs: Aug. 8, 2018.)
Automating Offer Confirmation
PJM’s Susan Kenney detailed the RTO’s plan to automate verification of price-based offers above $1,000/MWh to ensure they don’t exceed the reference cost-based offer on price-based segments.
Kenney said the price-based offers will be capped at $1,000/MWh unless they have the same megawatt blocks, use of a bid slope and fuel type as the referenced cost-based schedule, along with lower start-up offers, no-load offers and incremental energy curve prices per segment. Additionally, the price-based schedule must be updated whenever the cost-based schedule is decreased.
The requirements concerned Gary Greiner of Public Service Electric and Gas, who questioned whether the proposed changes came about as the result of challenges and time delays associated with the new bid verification process or simply for administrative ease.
“I like the flexibility of being able to bid our units in the most creative way we can,” he said, adding that PSE&G wouldn’t support the changes if their only goal is convenience.
Credit Debate
PJM’s Hal Loomis presented a proposal to allow market participants to provide surety bonds as credit for all activity except financial transmission rights portfolios. Surety bonds have different legal language but are “a parallel” to letters of credit the RTO already accepts as collateral, CFO Suzanne Daugherty explained.
However, Monitor Joe Bowring was concerned that surety bonds rely on rating agencies. When staff indicated ratings agencies are reliable, Bowring responded that the agencies’ involvement in the 2008 financial crash “might indicate that’s not quite accurate.”
Daugherty responded that the agencies have undertaken many changes since then. In response to a question from Bowring, she said staff compared best practices with other regional grid operators but didn’t go beyond that to ask other exchanges. She said surety bond issuers used to be too inflexible for energy market needs — requiring an itemized list of claims they might have to pay — but have since become much more “comfortable” with the industry’s needs.
Another “key difference,” she said, is that surety bond issuers, which have a right to investigate and request documentation before paying claims, now generally must pay within 30 days. They previously had no time limit.
PJM’s experience with letters of credit is that they are paid within two days without any investigation, she said, because the banks usually have other collateral. But she said staff does not anticipate a “daunting difference between the two.”
A proposal developed by the PJM Credit Subcommittee would have a $10 million cap per issuer for each member and a $50 million aggregate cap per issuer.
Exelon’s alternate proposal would allow using surety bonds for all credit requirements with a $20 million cap per issuer for each member and a $100 million aggregate cap per issuer. ERCOT and NYISO allow use of surety bonds with lower caps, Exelon’s Midgley said, but higher caps are necessary in PJM because its peak load is twice that of ERCOT’s.
“We see this as a cost-saving opportunity for members” that will also allow diversification, Midgley said. Since both proposals structure surety bonds like letters of credit, Exelon’s proposal would allow surety bonds to be applicable to all market activity, consistent with letters of credit. PJM staff said the proposal was acceptable.
