ERCOT is leaving significant amounts of money on the table by not using real-time co-optimization (RTC) of energy and ancillary services in its market operations, a study by the ISO’s Independent Market Monitor has concluded.
In its study filed last month with the Public Utility Commission of Texas, the Monitor found ERCOT last year could have realized savings of $257 million in congestion costs, $155 million in ancillary services costs, about $4/MWh in energy costs and $10 million to $12 million in production cost savings (Docket No. 47199).
The Monitor recommended ERCOT and the PUC implement RTC “as expeditiously as possible.” Noting that ERCOT has said it will cost about $40 million and take four or five years to begin using the process, the Monitor said the annual production cost savings and its analysis “provides quantitative evidence of [RTC’s] benefits and improved market efficiencies … [that] more than justify the implementation costs.”
“It’s the key missing link in our market,” IMM Director Beth Garza said last month in Houston. “Our market is dependent on pricing during significant scarcity intervals. My fear is that as we get to the point where we see tighter reserve margins, the likelihood of scarcity pricing increases. And high prices are an indication of the ineffective allocation of reserves.”
The Monitor has consistently recommended the use of RTC since the nodal market went online in 2010, calling it “foundational” to efficient pricing. (See “Monitor Says Wholesale Market ‘Performed Competitively’ in 2017,” ERCOT Briefs.)
The Monitor used historical offers and commitment status of resources from 2017 to simulate the effect RTC would have had on dispatch, prices, costs and system conditions, assuming that market participant behavior would remain unchanged.
It found that “jointly optimizing all products in each interval allows [ancillary services] responsibilities to be continually adjusted in response to changing market conditions.” It also said that RTC improves the accuracy of shortage pricing, pointing out that even using data from a year with high installed reserves, it found there were many intervals where average load prices implied scarcity.
“With RTC, however, the number of those intervals decreased significantly,” the Monitor said. “In an energy-only market that depends on scarcity pricing signals to provide incentive for proper levels of investment, it is important the scarcity pricing reflects actual scarcity rather than the inefficient assignment of reserve capacity.”
The analysis also revealed a “significant improvement” in system reliability because of reduced overloading on network constraints and a reduced use of regulation-up service.
As part of the PUC docket, ERCOT staff also filed a report on co-optimization’s operational benefits and its expected effect on reliability unit commitment (RUC) and supplemental ancillary services markets (SASMs). Staff filed a separate report addressing the benefits of incorporating marginal losses into security-constrained economic dispatch.
ERCOT’s analysis anticipates significant operational benefits from RTC’s implementation, including the timelier procurement of additional ancillary services, more effective congestion management, less manual actions by operators and “an improved management of resource-specific capabilities in assigning and deploying” ancillary services.
Staff said ERCOT has executed 391 SASMs covering more than 2,200 operating hours at average clearing prices of $100/MWh more than the corresponding day-ahead price since the nodal market began. When priced at the $100/MWh premium, they said, the megawatts procured in the SASMs resulted in an $11 million difference.
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The ISO’s scarcity pricing study indicated it will likely realize production cost savings and reduced consumer costs by incorporating marginal losses in system dispatch decisions. The analysis also projected increases in unit make-whole payments and start-up costs, “which could indicate possible additional costs if marginal losses are implemented.”
The PUC last year directed ERCOT and the Monitor to produce the studies as part of its efforts to improve market performance. The Monitor has made the simulation program code, data and use instructions available on ERCOT’s website.
July Begins with Another Monthly Demand Record
ERCOT wasted no time setting a new monthly demand record for the third straight month when the system recorded demand of 69.6 GW on July 3 during the 4-5 p.m. hour. July’s previous high was set last year at 69.5 GW.
System demand also topped the old record during the 5-6 p.m. hour.
The ISO has now recorded four new monthly highs this year. Staff has forecasted demand will exceed 70 GW in July and August, with a new summer peak of 72.97 GW expected next month.
Real-time prices topped out at $71.85/MWh during the interval ending at 2:30 p.m. on July 3.
The grid operator has yet to issue a conservation appeal this summer. It says it has 78.2 GW of capacity available, with a planning reserve margin of 11%. (See ERCOT Gains Additional Capacity to Meet Summer Demand.)
Garland Generating Units Return to Mothballs
ERCOT has approved two separate requests by the city of Garland to return 572 MW of generating capacity to mothball status this fall.
The ISO on Friday approved a notification of suspension of operations (NSO) for two units at Garland’s Spencer plant, effective Oct. 3. The two gas-fired units have a total capacity of 118 MW.
ERCOT earlier had approved an NSO for the city’s 454-MW, coal-fired Gibbons Creek facility, effective Oct. 1.
The grid operator determined the generation resources were not necessary to support transmission system reliability during their unavailability.
Both units were returned to seasonal status this spring.
VALLEY FORGE, Pa. — Facing what they called an “impasse” in stakeholder negotiations that began more than two years ago, PJM staff attempted to suspend the Transmission Replacement Processes Senior Task Force (TRPSTF) on Thursday, seeking to cease meetings until FERC responds to two compliance filings on the issue.
“It’s clear that we made progress here … [but] it appears that we are effectively at an impasse,” PJM attorney Chris O’Hara said in the early afternoon of what was scheduled as an all-day meeting, adding that it is “important that we get more guidance” from FERC. He confirmed the decision to suspend the task force was “informed by comments from [CEO] Andy” Ott.
Following stakeholder criticism, the group’s chairman said Friday that at least the next meeting, on July 31, will go on as scheduled.
PJM and its transmission owners submitted the filings in March in response to a commission ruling that TOs weren’t properly complying with their obligations under Order 890 to provide stakeholders with adequate information on “supplemental” projects — transmission expansions or enhancements not required for compliance with reliability, operational performance or economic criteria. (See Group Contests ‘Supplementals’ Ruling as PJM, TOs Advance.)
The ruling allowed for moving TOs’ responsibilities from the Operating Agreement to a new Attachment M-3 in the Tariff, but PJM and the TOs requested additional detail on how and when projects would receive stakeholder consideration.
“We are resource-limited at PJM,” O’Hara said, echoing comments Ott made at the Members Committee meeting on June 21, when the CEO took the unusual step of directly addressing members prior to a final vote on incorporating cost-containment measures into competitive bidding for transmission projects. Ott warned that implementing the measures would force staff to triage other revisions to the Regional Transmission Expansion Plan. (See Cost Containment Clears MC Vote Despite PJM Plea.)
“Stakeholders have indicated that their highest priority is that we focus on cost containment and [return on equity] capital structure commitments,” O’Hara said. “We have to dedicate our resources to implementing the processes that are on the table.”
Stakeholder Reaction
Many stakeholders were shaken by the announcement.
“I am baffled by the conclusions that a vote on anything at the [MC] indicates a stakeholder preference or prioritization. That is not what was in front of the membership. That is not what we were voting on,” said Carl Johnson, who represents the PJM Public Power Coalition.
American Municipal Power’s Steve Lieberman said the stakeholder process is designed for up-or-down votes on single issues, not votes that “enact a change in lieu of something else.”
Adrien Ford of Old Dominion Electric Cooperative said she was “taken aback” by the decision being made “without input from stakeholders.”
“It’s just a little disappointing to me right now,” added Ford, who joined ODEC a year ago after almost nine years with PJM. “This is unprecedented.”
AMP’s Ed Tatum said he was attempting to sort through his reactions to respond thoughtfully and “not in pure anger.”
“I’m pretty pissed off about this … but I think you probably already know that. The whole idea that we just stop a process here without the senior committee looking at it — that’s a bit tough. It goes against anything we’ve ever done in the stakeholder process,” he said. “PJM is once again jumping into a situation and preventing the process from moving toward a natural conclusion. You have done the PJM stakeholder process a great disservice today.”
The decision came unexpectedly in a meeting that started with reviewing proposals for the end-of-life supplemental project process. Supplemental projects are developed by incumbent TOs outside of PJM’s scrutiny because they are not required to fulfill any reliability obligations from NERC, FERC or the RTO. They’re paid for by the ratepayers in the TO’s zone but included in the RTEP for planning purposes. AMP and other stakeholders have argued that TOs are increasingly finding ways to funnel projects into those categories to build them without competitive bidding. (See Report Decries Rising PJM Tx Costs; Seeks Project Transparency.)
AMP and ODEC had offered a “hybrid” proposal on how PJM and TOs should implement their compliance filings. They discussed where the proposal aligns with and differs from the plans already outlined by PJM and the TOs.
O’Hara later attempted to end the discussion after TOs reiterated their refusal to negotiate anything beyond the filings. “I actually expected to spend hours with the comments and positions, and this was surprisingly short,” he said.
Tatum noted that stakeholders could have bypassed the task force and taken their proposals directly to the MC and the Markets and Reliability Committee. “We chose not to do that because we respect the stakeholder process, and I wish PJM had the same amount of respect for it,” he said.
Tatum was among the supporters of the cost-containment proposal, whose opponents have argued its sponsors violated the stakeholder process by bringing it directly to the MRC without any vetting through lower committees.
O’Hara later walked back his statement that the cost-containment vote at the MC indicated it was stakeholders’ highest priority. But he pointed out there is just one month to get a TRPSTF solution approved and implemented before the next RTEP cycle.
“We can’t build a consensus here. We need to focus on implementing what the commission ordered. We have resources; we just can’t have them going in two different directions,” he said.
‘Much Ado About Nothing’
PJM’s Ken Seiler, who chairs the Planning Committee, explained that staff are already dealing with implementing the cost-containment proposal and Attachment M-3, along with considering the grid resilience concerns, five separate planning models and “hundreds” of generation interconnection requests, all “without upsetting the apple cart.”
“Your assessment that consensus isn’t going to happen here is indeed correct, but we’ve known that for two years,” Tatum said, adding that he takes issue with the reasoning for waiting until FERC responds. “The purpose of this effort is to give stakeholders an opportunity to say what they would want to see to understand TO end-of-life project decisions.”
O’Hara said it might be “much ado about nothing,” as PJM expects FERC to respond soon.
Ford asked that no meetings be canceled until the MRC, which created the task force, has a chance to consider the issue. Greg Poulos, executive director of Consumer Advocates of the PJM States, asked that PJM write out an explanation of its reasoning that he can share with his members.
When pressed by Tatum, PJM’s Janelle Fabiano — an in-house expert on Manual 34, which spells out the stakeholder process — said she would “imagine there will be an announcement” at the MRC but wouldn’t commit to anything without discussing the issue with other staff.
O’Hara said Thursday that the RTO must receive the commission’s responses to the compliance filings at least five business days before the task force’s next scheduled meeting, on July 31, to avoid cancellation.
But PJM’s Fran Barrett, who chairs the TRPSTF, sent an email to stakeholders on Friday confirming a discussion at the MRC on July 26 and clarifying the TRPSTF will still hold its July 31 meeting. Barrett was unable to attend Thursday’s meeting.
“At that meeting, we will further discuss my recommendation as conveyed by Chris O’Hara yesterday that we seek guidance from the MRC whether to suspend TRPSTF meetings pending FERC action on the submitted compliance filings, complaints and request for rehearing,” he wrote. “In addition, we will discuss whether there is a workstream that we could focus productively upon that is distinct from the pending TO, PJM and transmission customer filings associated with Docket [EL16-71] and the Attachment M-3, such as end-of-life criteria for baseline upgrades.”
In what spelled a victory for CAISO’s Department of Market Monitoring, FERC on Friday approved a set of changes to the ISO’s congestion revenue rights auction to address a market the Monitor and state regulators contend forces ratepayers to become unwitting partners in losing transactions.
Ratepayer auction revenues compared with congestion payments for auctioned CRRs | CAISO Department of Market Monitoring
The most significant — and controversial — change approved by FERC limits allowable source and sink pairs for CRR transactions to those that align with typical supply delivery paths. Transactions using non-delivery sources and sinks currently (such as between two generator locations) represent about 81% of the auction shortfall, the ISO noted in arguing for the change. FERC acknowledged that the elimination of some source-sink pairs from the auction process will limit market participants from using certain non-delivery paired CRRs as hedges.
Protesters failed to persuade the commission that the changes were discriminatory or violate open access by eliminating legitimate financial hedging opportunities. CAISO received pushback on the proposal during its development because it staunches a lucrative flow of profits to financial traders, but ISO said the current structure pays out about $100 million a year more in CRR revenues from the day-ahead market than bidders paid in the CRR auction.
Other parties offered alternative proposals to address the revenue shortfall, including changes to CRR modeling and different auction structures. But FERC said the question before it was whether CAISO’s proposal is just and reasonable, not “more or less just and reasonable than protesters’ proposed alternatives.”
“We note that CAISO has an ongoing stakeholder process, which is the appropriate forum for market participants to discuss any further changes to CAISO’s CRR auction process,” FERC said (ER18-1344).
“We find that, on balance, the potential loss in market functionality is acceptable given the scope of the auction revenue shortfall CAISO is attempting to remedy,” the commission said.
Another Tariff change will require the CRR process to use an annual transmission outage reporting requirement more closely aligned with day-ahead models, alleviating the auction shortfall and making expected payouts to CRR holders more predictable and less volatile. CAISO’s analysis had found that a misalignment between transmission outage reporting data and the auction model was another key driver of the auction shortfall. Outages that impact congestion and capacity in the day-ahead process were not reflected in the CRR auction model, causing the system to be modeled with fewer constraints.
Under the changes approved by FERC, participating transmission owners must submit all known and planned maintenance outages affecting the CRR process for the following year by July 1, earlier than the current requirement of Oct. 15. While this change had support among several trading and energy companies, Pacific Gas and Electric and Southern California Edison said the reporting is too early and might reduce the flexibility of market participants to schedule outages. FERC said the new outage requirement will increase auction flexibility.
Among the protesters to the proposal as filed were the Western Power Trading Forum, Calpine, DC Energy and Vitol, who said CAISO’s changes will restrict legitimate hedging activity. CAISO referred to the changes approved by FERC last week as “Track 1A,” which the Board of Governors approved in March. (See CAISO Moves Ahead With Market Changes.)
More Changes Afoot
The CAISO board last month approved “Track 1B” changes to tackle who pays for revenue inadequacy, which now go to FERC for approval. (See CAISO Board Approves More CRR Auction Changes.) The 1B changes alter the current process in which all revenue inadequacy is allocated to measured demand, which includes electricity load and exports. That process does not consider the location of constraints on the system and creates an incentive to profit from differences between the CRR auction model and the day-ahead market model.
A second component of the 1B changes reduces the amount of system capacity released in the annual process from 75% to 65%, to provide greater assurance that CRRs obtained in the annual process will be feasible in the monthly process and reducing the amount of payment reductions resulting from revenue inadequacy charges.
The changes approved by FERC last week will be in effect for the 2019 CRR auction, which begins this month. The Track 1B changes are targeted to improve efficiency of the monthly CRR auctions to be held in 2019.
CAISO unveiled its plan to overhaul CRR auction earlier this year in response to a long-running complaint by its Monitor, which argued that financial interests have saddled ratepayers with more than $500 million in excess CRR-related costs over the past five years. (See CAISO Overhauling CRR Auctions.)
HERSHEY, Pa. — New Jersey Board of Public Utilities President Joe Fiordaliso is so exasperated by PJM that he’s considering pulling the state from the RTO. And New Jersey is not alone in its frustrations, regulators said at the Mid-Atlantic Conference of Regulatory Utilities Commissioners annual meeting last week.
“I will not allow New Jersey to be the Cinderella of PJM,” Fiordaliso said in an interview he sought out with RTO Insider. “It’s not rocket science to make people feel a part of the process. I don’t feel a part of the process. … Pick up the phone. … That’s all we want.”
Cinderella’s story, of course, ended happily. Fiordaliso’s mood last week was more like Patrick Swayze’s declaration in Dirty Dancing: “Nobody puts Baby in a corner.”
Fiordaliso said he doesn’t feel PJM is “serving New Jersey well” and that he’s “been disturbed about it since I assumed the [BPU] presidency” in January. And while he proudly states that the Garden State is one of PJM’s “founding fathers” — “the ‘J’ stands for New Jersey,” he reminds — the tension could be the beginning of the breakup.
“I’m exploring it, let’s put it that way,” he said of whether he would push the state toward leaving the RTO.
“I have to work what’s in the best interest of the ratepayers and the citizens of the state of New Jersey. If I don’t feel that PJM is providing that, then I have to start looking at other options. … If PJM is not in my corner on that, then I guess we have nothing to talk about.”
Other States
Although he declined to name anyone else, Fiordaliso indicated other PJM states may share his perspective. While commissioners in other states weren’t as outspoken, several said they shared his frustrations.
“I think you would find a number of states that certainly would have the same concerns that he has,” said Illinois Commerce Commissioner John Rosales, the president of the Organization of PJM States Inc. (OPSI). “I’ve made this clear to [PJM CEO] Andy [Ott] that the communication could be better.”
“With regard to people being frustrated enough to consider other options, I will say it’s been bandied about a bit,” said a Maryland Public Service Commissioner who spoke on condition of anonymity. “I’m not sure Maryland is there quite yet, but if the states are pushed too far, I think more than a few states will come to similar conclusions. … There’s a lot of frustration with an entity like the market operator trying to mitigate or overcome state policies. States are sovereign states, and they have every right to set their own policy. We don’t obtain that right from the market operator. The states don’t exist to serve the market; the market exists to serve the states.”
W.Va., Pa. Staying Put
Regulators from West Virginia and Pennsylvania said they are not considering leaving the RTO.
West Virginia Public Service Commissioner Brooks McCabe said he has heard no discussions about his state considering leaving PJM. He advised states to “keep the powder dry; don’t get into fights you don’t need to get into.”
The Pennsylvania Public Utility Commission said in a statement that it “values the role that PJM plays in the wholesale markets. Pennsylvania is not considering withdrawing from the RTO.”
However, there are tensions in Pennsylvania as well.
The Pennsylvania legislature’s Nuclear Energy Caucus said in a Feb. 9 letter that the lawmakers are “losing confidence in the ability of wholesale electric markets to … ensure stable prices for our citizens and a reliable and resilient electrical grid.” (See PJM Responds to Pa. Concerns About Baseload Plants.)
PUC Vice Chairman Andrew Place told RTO Insider in May that he agreed with FERC Commissioner Robert Powelson, a former Pennsylvania regulator, that there is an “erosion of confidence” in RTO stakeholder processes. Place said “PJM is swimming and drowning in capacity” and that its capacity repricing proposal “only worsens that.” (See Powelson: ‘Erosion of Confidence’ in Stakeholder Process.)
FERC on Friday rejected PJM’s repricing proposal and instead ordered the RTO to expand its minimum offer price rule to include existing generation receiving state subsidies — including New Jersey’s and Illinois’ nuclear plants and generation supported by renewable portfolio standards. (See FERC Orders PJM Capacity Market Revamp.)
Commissioner Cheryl LaFleur, who dissented, said the ruling could force states into “reregulation.”
“I am particularly troubled that, as a result of today’s order, the commission will be hamstrung in its ability to openly and honestly engage with the states about whether this proposal will meet their needs, and how they might operate under this construct,” she wrote.
PJM Responds
PJM spokeswoman Susan Buehler said in a statement that the RTO is a “customer service organization” and is “always striving to enhance our communications.”
But because of the diversity of PJM — 13 states and D.C. — she said, “It is likely on any given matter one or more states may have a view opposite of PJM and possibly opposite other states. We attempt to find solutions that work for all interested stakeholders and members. PJM is independent of our members and stakeholders; we execute our mission of reliable operations, nondiscriminatory markets and long-term transmission planning.”
‘Very Disappointing’
Illinois’ Rosales told RTO Insider in May he agreed with criticism that PJM has not been sufficiently responsive to the states, calling the RTO’s capacity repricing filing “very disappointing.”
Rosales said he is not pushing for Illinois to withdraw from PJM but would not “hinder” it. Commonwealth Edison, a utility owned by Exelon, is the sole PJM member serving load in Illinois.
“We would not stand in their way if they decided they wanted to go to MISO,” Rosales said, adding that the idea of Illinois creating its own single-state RTO has “never come up … in conversations with this commission.”
Commonwealth Edison did not respond to a request for comment.
Rosales said communication has improved since PJM’s annual meeting in May. He said he had a one-on-one meeting with Ott there, and “it seems to be going a little better.”
However, for the first five months of this year, “I can understand the states saying that we’re really having bad communications,” he said. The issue, he said, was that PJM often sends mid-level envoys to meetings who can only communicate messages, rather than decisionmakers who could answer for the RTO. That lack of direct engagement has improved, he said.
“It always seemed like they wanted to [improve], but let’s see where they go from here,” he added.
McCabe: Stay Engaged
West Virginia’s McCabe said the states have issues “that we can effectively address” with PJM.
“Just because we have disagreements doesn’t mean we have to get mad and leave the discussion. I am one for staying at the table. I’m very comfortable in a somewhat contentious environment as long as everyone is at the table and really trying hard to not just clarify their positioning properly but to understand the position of the opposing parties. We need to focus more on that,” he said. “At some point, we’ll have to make some of those tough decisions, but I think we have time.”
Fiordaliso said he believes he’s getting “lip service” and “being patronized” by PJM. Specifically, he feels PJM failed to defend the state in a recent FERC fight with NYISO over transmission construction costs. (See PSE&G on the Hook for Bergen-Linden Costs.)
“We feel that PJM should be supporting New Jersey’s position regarding another entity,” he said. “They submitted a letter in support but never used the word ‘support.’ That’s disturbing to me. … We would like more support. Shouldn’t PJM be defending N.J.’s position? … I’m sure they listen, but I wonder how much they hear.”
He recounted an April OPSI meeting in Jersey City that he said PJM decision-makers did not attend. “We’re looking at [these] beautiful Lower Manhattan lights, and I jokingly say to my colleagues in OPSI, ‘Look at those lights. New Jersey ratepayers are paying for them,’” he said. “I don’t mind New Jersey paying for what it gets, but I’m not willing to pay for what New York gets.”
Buehler said transmission cost allocation is beyond PJM’s authority. “Understandably, there are many factors to consider and many equity implications related to FERC’s goal in establishing cost allocation — ensuring that the beneficiaries of transmission reinforcement, either systemwide or specific, are assigned the cost obligation,” she said.
Fiordaliso wants more individual and direct communication from PJM in ways that make states feel like “partners” in the market and said he doesn’t feel RTO staff want to do that. He acknowledged that disagreements are inevitable but said, “Many times out of disagreement comes a better product.”
“I would like to see them to say, ‘You know what, New Jersey? Some of your ideas maybe are pretty good. Let’s see what we can work out,’” he said. “I find us more in contention with PJM rather than in cooperation with PJM. And that disturbs me.”
He said he purposefully declined PJM’s invitation to a luncheon it was hosting at last week’s MACRUC meeting because “I’m annoyed.” He questioned why PJM staff did not inquire why he didn’t attend. He conceded that they probably didn’t get the message and don’t have a “next step” planned.
PJM’s size may play against it, as there are “diverse interests between the many states,” he said, but added that staff have “an obligation, as we do, to try to get us all together.”
“Might I be wrong? Maybe I am. But they have to show me I am wrong,” he said. “My door is always open. My phone works. Call me. Come to my door. I’m willing to meet you more than halfway.”
HERSHEY, Pa. — In the days just before FERC announced it was rejecting both of PJM’s capacity proposals and suggesting its own, market participants and officials from states within the RTO’s footprint were still vigorously debating the issues those filings were meant to resolve.
Several panels last week at the Mid-Atlantic Conference of Regulatory Utilities Commissioners’ annual summer education session focused on related issues, including nuclear subsidies, the impact of state policy initiatives on power markets and how RTOs are faring 20 years into their existence.
The panel on nuclear subsidies became controversial when audience members took issue with the interests of the panelists. Moderated by Maryland Public Service Commissioner Anthony O’Donnell, the panel included Steve Aaron, representing a group called “Nuclear Powers Pennsylvania”; Kathleen Barron, Exelon’s senior vice president of competitive market policy; and Anne George, ISO-NE vice president of external affairs and corporate communications. The panel generally supported states providing compensation for generation attributes that aren’t valued in markets.
Direct Energy’s Marji Philips pointed out from the audience that while nuclear units provide carbon-free generation, the nation hasn’t solved the problem of what to do with nuclear waste.
Philips said her time at PECO Energy, now an Exelon subsidiary, taught her that nuclear plants have been a positive asset.
“Shareholders did very nicely for the cost recovery on these nuclear units a long time ago, as they should have. They were very efficient when gas was setting the margin,” she said. “But the idea that customers are repaying for them again is absolutely true, and this is money that could go to other resources that could provide flexibility. … Admittedly we’re caught in a transition where we still need a lot of the conventional generation, but I just had to challenge the idea that funding nuclear is an absolute necessity.”
O’Donnell, who created the panel, accepted the criticism and said he attempted to secure a panelist “from a utility that has a different view” but was unable to do so.
“I know that it has to be an important part of the discussion going forward,” he said.
Todd Snitchler, director of the American Petroleum Institute’s market development group and a former Ohio regulatory commissioner, said he offered to sit on the panel. He also contended it should have discussed the issue of states blocking pipeline construction that would deliver gas to other regions.
The comment was a reference to New York’s longstanding objection to allowing a pipeline that could connect Marcellus region gas supplies to New England. Because of concerns about inadequate pipeline capacity, ISO-NE has asked FERC to approve a plan to prevent the retirement of Exelon’s gas-fired Mystic plant, which is fueled by shipments of liquefied gas. Subsidy proponents have used the situation as evidence of the need for national fuel security subsidies. (See FirstEnergy Calls out FERC ‘Failure’ to Act on Resilience.)
Snitchler also noted that the PJM fleet is more fuel-diverse now than ever before, and that there were no complaints about diversity when gas prices were higher.
“We’re trying to design a market that values what that fuel security is, and then anybody that can bring that to the market will be able to participate,” George said. “We’re in this kind of transition that’s evolving rapidly, and that’s what’s brought a lot of these issues to a head and everybody’s struggling with what to do with it.”
O’Donnell confirmed there is currently no initiative to bail out the only nuclear plant in Maryland, Exelon’s Calvert Cliffs. But there is an ongoing legislative study on the state’s renewable portfolio standard, which has sparked “some interest” in whether it is “inclusive enough” because it doesn’t include nuclear. Connecticut is currently considering whether to include nuclear in a program that pays for output from renewable resources.
He noted that Calvert Cliffs remains “relatively healthy,” so a discussion on state subsidies is “coming to Maryland but not here yet because of other pressing” needs.
Irreconcilable Differences?
In a later panel, former Pennsylvania Public Utility Commission Chairman Glen Thomas suggested that states concerned about markets crowding out preferred resources “have to think long and hard about whether [they] want to renew their vows to markets or get a divorce.”
He referenced the nuclear panel, noting that more than 50% of New England’s megawatts are subsidized, which has suppressed prices so much that generation needed for reliability is uneconomic.
“I worry that that could bleed into PJM if we’re not very, very careful,” he said. “There’s ways to pursue state environmental policies that are consistent with the market, but many of the policies that are being set up right now are not consistent with the market. That’s not only a problem in the states where they’re happening; it’s going to be a problem in the entire region if we’re not prepared to address it.”
Randy Elliott, regulatory counsel for the National Rural Electric Cooperative Association, said co-ops have a different opinion because they operate with a different business model.
“Our fallback position has been trying to secure the right to self-supply our own capacity … and have that count toward our capacity requirements,” he said. “We’re trying to get our different business model accommodated with the existing regulatory structure in the three eastern RTOs.”
“Any of these resources that may be receiving some sort of state subsidy, I’m not convinced that they automatically tank the capacity market,” said David Hunger, vice president at Charles River Associates. “As long as these resources face the performance risk in Capacity Performance … and that risk isn’t passed off to consumers, or passed off to someone else through some contract, for the life of me, I can’t figure out why they have any incentive to offer other than their competitive offer, which is their opportunity cost.”
Abby Hopper, CEO of the Solar Energy Industries Association, struck a middle ground, advocating for respecting state decisions but driving those decisions to look forward to new technologies rather than figure out how to maintain old ones.
“I think state policy is critically important, and recognizing and respecting the role of states to make decisions about what kind of generation they want, how they want to support that and sort of what their priorities are is important, and the wholesale market should respect that,” she said. “I think we are at a critical point in the history of the evolution of these markets. I do not have that same level of alarm. I do see an incredible amount of opportunity.”
In the conference’s opening panel, former FERC Commissioner Phil Moeller, now an executive vice president at the Edison Electric Institute, argued for dynamic rates that respond to changes in demand.
“You need those right price signals. I think it’s the way to move the system in a way that helps people … I’m open to all kinds of creativity,” he said, adding that pricing “has to be on the table” because of the “dynamic nature” of a system “driven by physics.”
Greg Poulos, executive director of the Consumer Advocates of the PJM States, said costs are “always an issue” for consumers and that real-time rates are a concern because residential customers don’t have the capability to follow price signals or impact prices through their actions. He shared the view that the discussion shouldn’t be about “getting money to” existing resources to keep them operating.
“It should be focused on the consumers. Not just some consumers, but all consumers,” he said.
In the concluding commission roundtable, D.C. Public Service Commission Chair Betty Ann Kane said the biggest change in regulatory processes over the past 11 years is that “things don’t lend themselves to that firmness that we used to have.”
“There’s more and more judgment that goes into [decisions] and there’s more and more policy,” she said. “You have these things — jobs, climate, policy — that’s much harder to measure, and it’s much harder to know if you’re making a good decision.”
Past and Future
In a panel on how RTOs have evolved over the past 20 years and where they’re going, PJM’s Darlene Phillips argued they are fulfilling their purpose.
“I think we got what was originally envisioned, which was reliability at lowest cost,” she said.
Ohio Public Utilities Commissioner Beth Trombold said the ongoing resource switch from coal to gas and renewables is having the biggest impact, but that “I think there’s obviously political pressures. Each state has politics to navigate.”
Phillips said states have “options” about procuring resources for their citizens and that providing capacity was not a “mandatory function” of RTOs.
“It was a service that was offered, and many states took advantage of it,” she said, noting the RTO would be “OK” with states returning to a regulated industry or developing their own integrated resource plans.
Rob Gramlich, president of Grid Strategies, argued that RTOs should stick to their original goals of operating real-time grid dispatch for reliability and doing regional transmission planning.
“Stop trying to be regional energy policy makers,” he said. “Consumers will do well under one scenario if [grid operators] stick to what they’re supposed to do, and they’ll probably do worse if they don’t.”
“It’s our responsibility to make sure those energy markets are working as they’re designed,” Phillips said. “Politics is deep. Economics sometimes can take a backseat to the politics, both at the federal and the local” level. She said she would be “hard pressed” to think of who might have lost by being in an RTO.
“I think that everyone got a piece of this pie in some shape or form,” she said.
Greg Carmean, executive director of the Organization of PJM States Inc., commented from the audience that load-serving entities were supposed to obtain adequate capacity for customers, while the Base Residual Auction was intended to be, as the name implies, residual, but that “mission creep” at PJM had expanded its role to be the main outlet.
Gramlich said the idea of LSEs being responsible for hedging — rather than relying on the regional capacity market — is effective, such as in ERCOT, where “it’s their job [to hedge], and they know they’ll pay $9,000 energy prices if they don’t.”
AARP’s Bill Malcolm said in the next 20 years, “I think the whole country will be in an RTO,” though he conceded that it’s a “Hail Mary” in the Southeast.
Phillips said “a larger portion” of the country will be in an RTO and that “we’ll be further along than we are today with seams and coordination.”
Gramlich took it even further.
“I think every country is going to have large regional balancing markets,” he said, adding that there will be more microgrids, but the “broad regional market will be best option” for those who can’t afford their own microgrid.
FERC last week ordered settlement procedures over Pioneer Trail Wind Farm’s request to recover $826,926 annually to provide reactive supply and voltage control in MISO.
The commission said the amount requested by the 150-MW Illinois wind project could be unjust and unreasonable but allowed the rate schedule to go into effect July 1 subject to refund (ER18-1473).
Construction of Pioneer Trail Wind Farm in 2011 | White Construction
“Pioneer Trail appears to have incorporated costs that may be unrelated to the provision of reactive service, including portions of ‘Turbine Generator Erection,’ ‘Turbine Generator Options’ and ‘[Supervisory Control and Data Acquisition System]’ costs in its accessory electric equipment cost category,” FERC explained.
Pioneer Trail, owned by E.ON Climate & Renewables North America, said it followed the reactive power rate methodology approved by FERC in 1999 for American Electric Power. The facility’s generation interconnection agreement with Ameren Illinois stipulates that it must provide reactive service, but Pioneer Trail claims it has been providing reactive power support to MISO without compensation since beginning commercial operation in 2012. It said it meets MISO testing requirements for voltage control capability because its turbines contain a power electronics system that regulates voltage and power in real time, allowing them to perform like a conventional synchronous generator.
“Pioneer Trail notes that there are differences in the types and quantities of equipment providing reactive power support between synchronous and non-synchronous generators, such as a wind turbine generator, but argues that, in both types of facilities, the costs of the generators/exciters, [generator step-up] transformers and accessory electric equipment can be separated from the remaining plant investment, and the portion of those costs attributable to the production of reactive power can be determined by applying an allocation factor,” FERC said.
Pioneer Trail pointed out that FERC has accepted reactive service rate schedules “for several similar non-synchronous wind generation facilities,” including three in the MISO footprint. The wind farm also acknowledged that its turbines will have a higher reactive power revenue requirement than traditional synchronous generators because there’s more equipment involved.
Ameren challenged Pioneer Trail’s revenue requirement filing, saying the calculation includes several errors and “over $19 million of indirect costs that are largely unexplained,” including about $13 million of network upgrade costs that “are not properly included in the calculation of reactive power rates.” Ameren also said Pioneer Trail’s calculation does not use FERC’s Uniform System of Accounts and contended the wind farm erred in only using 2017 operations and maintenance costs, instead of multiple years.
One thing is certain about the fuel security study PJM has begun: Many will be upset with the results no matter how it turns out.
In fact, just about everyone seemed unhappy with the scope and assumptions PJM officials outlined Thursday during a special Markets and Reliability Committee conference call.
Exelon’s Sharon Midgley urged PJM officials to broaden its proposed scope, while Calpine’s David “Scarp” Scarpignato lobbied for a narrower focus. James Wilson, a consultant for state consumer advocates, expressed concern that RTO officials were already moving on to potential “solutions” before understanding the problem.
The range of comments echoed the larger resilience debate sparked by the Trump administration’s bid to provide subsidies to struggling coal and nuclear plants.
The RTO said the goal of the study is identifying locations with fuel delivery risks, evaluating how resources can reduce them and determining the need for additional mitigation efforts.
PJM Vice President of Operations Mike Bryson and other RTO officials told stakeholders the study is a continuation of resilience efforts since the 2014 polar vortex, which led to tougher nonperformance penalties under Capacity Performance.
Under the revised plan described by officials last week, PJM will use a base load scenario with a 50/50 peak for winter 2023/24 (134,435 MW). The extreme winter case will be based on the three cold spells in the past 45 years that each lasted for 14 days (1989, 1994 and 2017/18).
| PJM
It will look at two “credible” pipeline disruption scenarios: a “medium impact” disruption that cuts downstream capacity by 50% and a “high impact” event eliminating downstream flows.
During last week’s two-hour meeting, Exelon, the nation’s largest nuclear operator, and Calpine, the largest natural gas generator, took opposing views of the appropriate scope.
Exelon’s Midgley said PJM’s analysis should look at the entire winter period rather than just a two-week cold spell. For example, she said, if oil inventory is depleted during a cold snap, the system may have difficulty meeting load later in the season. “We don’t want to cast the net too narrow … as we’re trying to think about the realm of possibilities,” she said.
Calpine’s Scarp responded that PJM should avoid overly extreme scenarios. “If you want to get really extreme, you can say it’s really cold out, a meteor strikes and there’s a tsunami that hits all at once,” he said. “At some point you’ve got to draw a line. [Consumers are] only willing to pay so much for this.”
Midgley said exclusively focusing on extreme weather would be too narrow. “Cyber and physical attacks can create fuel disruptions far more catastrophic than those caused by the recent bomb cyclone,” she said.
9/11 Invoked
In its written comments last month, Exelon invoked the terrorist attacks of Sept. 11, 2001, to make a similar point. “Constraining the study assumptions to the severity and duration of recent historical weather events is the equivalent of what the government and the airline industry did on Sept. 10, 2001, and fails to reflect all realistic potential scenarios that PJM could face,” it said.
It also said PJM should analyze “simultaneous weather and man-made infrastructure/cyber events,” suggesting that terrorists might wait for a lengthy cold spell to launch an attack. “The highest stress resilience scenarios arise when extreme weather co-occurs with an infrastructure disruption. Therefore, any baseline scenario should jointly consider the extreme weather scenario as occurring simultaneous with a high-impact, 90-day infrastructure disruption scenario.”
And it asked the RTO to evaluate “a realistic but extreme” scenario “that disrupts 80% of the natural gas pipeline infrastructure across the entire PJM region for six months,” representing “the severe threat that a major state adversary might pose.”
An Exelon spokesman said later that PJM’s proposed scope “gravely underestimates the resilience risks facing” the region.
“At a minimum, PJM needs to look at a case where all financially stressed nuclear units will retire to better understand and potentially mitigate resilience risks,” he said.
Premise Questioned
In their joint written comments, the Sierra Club and four other environmental organizations questioned the focus on fuel, noting that most outages result from transmission and distribution problems, not generation.
The environmental groups also challenged PJM’s proposed base capacity portfolio, which assumes an installed reserve margin of 16.6% — the minimum requirement in the RTO’s 2017 Reserve Requirement Study — rather than the 23.9% margin that resulted from the 2017 Base Residual Auction or the 22% margin from the 2018 BRA.
PJM also proposed a “stressed portfolio” that would have included additional coal and nuclear retirements beyond the base case and a “high-stressed” portfolio with still more coal and nuclear retirements that are replaced with natural gas.
Casey Roberts, senior attorney in the Sierra Club’s Environmental Law Program, said she was relieved that PJM has eliminated, for now, the “high stress” portfolio scenario “that had no basis in fact.”
“However, PJM couldn’t give a clear answer as to whether fuel-free resources (renewable energy and demand-side) would qualify as fuel-secure,” she said in an email after the meeting. “They also don’t seem to be taking stakeholder input seriously, as demonstrated by their lack of plans to respond to specific comments, and failure to reach out to groups with expertise on demand response and [energy efficiency resources] that participate in wholesale markets.”
The environmentalists and Advanced Energy Economy said that while PJM promised a “fuel-neutral” analysis, its proposal favors solid and liquid fuels and ignores the resilience contributions of renewables and demand-side resources.
Use of Confidential Intelligence
Roberts and consultant Rob Gramlich of Grid Strategies also questioned PJM’s plans to incorporate in the analysis confidential information from the Department of Energy on cyber and physical threats to fuel delivery infrastructure.
“The suggestion that DOE’s natural gas disruption scenarios will not be reviewable by stakeholders or even all of the PJM staff involved is also highly concerning, particularly if those disruption scenarios will be the basis for profound changes to [the capacity market] with enormous impacts on consumers,” Roberts said.
“There is a ‘credible’ scenario and then a DOE scenario,” said Gramlich, who coauthored a study asserting that resilience is more a function of transmission and distribution than generation. (See Report: Customer Needs Should Lead Resilience Effort.)
“I don’t think DOE should get to plug in assumptions if other interested parties don’t — certainly not ones the consumers who might be forced to pay more don’t get to see,” he said.
Consultant James Wilson said that although PJM’s approach to the analysis is appropriate, “they seem fixated on a particular approach to addressing the problem that may be costly and inefficient.”
In later comments to Bryson, Wilson questioned PJM’s statement in a FAQ document that the study will identify “the adequate level of required fuel security.”
“The study cannot do this,” Wilson said. “Only policymakers can make this call.”
Wilson said fuel security risks can be broken into three groups: plant outages, weather-related load levels and others “for which there is substantial historical data”; a second group regarding whether plants have firm gas transportation or oil backup, which he said “are uncertain but … are rather easily influenced by incentives”; and a third group that includes pipeline failures and cyber or terrorist attacks.
“There is no history upon which to base any assigned probability” to the third category, Wilson said.
Thus, he told Bryson, PJM should focus on evaluating scenarios and potential resilience metrics, “and not try to quantify unconditional risk (you can’t), or identify a ‘required level’ of something, or otherwise get too far ahead in selecting a particular extreme scenario for planning purposes.”
Exelon Seeks Distance from Coal
Like Exelon, FirstEnergy Solutions also argued in its written comments that PJM should consider more extreme scenarios, including a “pipeline failure impact on a large number of plants.”
“Any criteria to assess fuel security that are broad enough such that resources of all technologies and fuels can qualify as being ‘fuel secure’ will likely result in a system less secure than the status quo with natural gas as an even more dominant fuel source,” said FES, whose coal and nuclear plants could benefit from fuel security payments.
| PJM
Exelon, however, called for a broader resilience focus that does not lump coal and nuclear together, saying fossil fuels “stand to exacerbate the severe weather events that are interrupting electric service to customers in the first place.”
“If PJM plans to meet its fuel security challenges by retaining resources that burn coal or by incentivizing the addition of oil storage, it will be contributing to the very problem it is trying to solve,” Exelon said. “Planning a generation system that is resilient must include planning for a system that is both able to withstand interruptions and also does not contribute to interruptions by exacerbating climate change.”
Next Steps
PJM officials said they hope to complete Phase I of the study — the identification of potential system vulnerabilities and development of criteria to address them — by late July or early August. They will provide an update on their progress at a special MRC meeting July 26.
The completion of the initial analysis will lead to Phase II, a stakeholder process expected to run through October to develop methodology to incorporate vulnerabilities into PJM’s markets “if needed.”
In Phase III, the RTO said it will seek to address specific security concerns identified by federal and state agencies. Officials said any proposed capacity market changes would need to be filed with FERC by January to be in effect for the 2019 BRA.
POUGHKEEPSIE, N.Y. — Artificial intelligence, transmission needs and markets versus mandates topped the discussion at the Renewable Energy Conference hosted by the Business Council of New York State, the Hudson Renewable Energy Institute and Marist College’s School of Management.
AI will transform society and the energy sector, said John E. Kelly III, senior vice president for cognitive solutions and research at IBM.
“When I joined the company in 1980, my first job was to figure out how do we put 1,000 transistors on a tiny chip for our mainframes; today, we put 15 billion transistors on a chip the size of your fingernail,” Kelly said.
He shared how the benefits of AI stem from the exponential curve in data growth. He described how IBM’s Watson platform can absorb 30 years of data in a few minutes and then continue to “learn” as it interacts with people and individual case decisions, whether in health care or the energy industry.
The world’s fastest supercomputer requires 12 MW to mimic what the human brain performs on 20 W of electricity, Kelly said, but AI can spot what no human could. For example, when Australian energy giant Woodside adopted Watson, the computer determined that most hand injuries occurred around 11 a.m., so the company now sends text messages to rig workers at 10:45 a.m. to remind them to take a break or have a cup of coffee, reducing the accident rate.
“You are going to be disrupted and transformed by this technology,” Kelly said. “We’re finally going to be able to take advantage of the integration of renewable energy and traditional energy in ways that we couldn’t before.”
The industry spent many years talking about smart meters and gathering data, but not much was being done with the information, he said. AI can make sense of the high volumes of data produced by smart grids and distributed energy resource sensors, which can overwhelm the capabilities of human programmers.
“These machines will recognize patterns of disruption, predict capability for your equipment and your power lines, and I think ultimately it’s going to lead to a seamless distribution and storage of energy among all sources, and there will be very few humans involved in that real-time optimization and predictive capability,” Kelly said.
Darren Suarez, director of government affairs for the Business Council, asked whether the state will deliver on its energy policy promises, including 3 GW of solar by 2023; 1.5 GW of energy storage by 2025; and a 40% reduction in greenhouse gas emissions, 2.4 GW of offshore wind and 50% of electricity coming from renewable sources by 2030. (See NY Releases ‘Roadmap’ for 1,500-MW Storage Goal.)
The council emphasizes the importance of relying on markets rather than mandates to achieve the state’s environmental goals, Suarez said.
The state’s many programs, such as Reforming the Energy Vision, have been driven by the executive branch, led by Gov. Andrew Cuomo since 2013, rather than the legislature, which entails risks for longevity, Suarez said.
The state’s environmental targets might “have no staying power” if another governor with contrary ideas comes to office, as has happened at the federal level with President Trump pulling out of the Paris Agreement on climate change, Suarez said.
Consolidated Edison’s consultant IHS anticipates U.S. renewable volumes will double by 2040, driven by solar and land-based wind, said Joseph P. Oates, chairman of Con Ed’s non-utility businesses.
Oates oversees 1,100 MW of renewable energy projects around the country, ranging from a 1-MW behind-the-meter solar project in Brooklyn to the 350-MW Copper Mountain 3 solar project near Las Vegas, which covers 8 square miles.
“If you were going to power New York City’s load just with solar, you’d have to cover the five boroughs with panels,” Oates said. Alternatively, relying solely on offshore wind would require more than 800 of the newest 12-MW turbines.
State and regional efforts to decarbonize the economy are driving renewable energy growth in the Northeast, but in New York, “you need to do some energy efficiency, and that’s really a key strategy because it is the least expensive way to decarbonize,” Oates said.
“Today we’re at a little over 1,700 MW of renewables in New York state,” NYISO CEO Brad Jones said. “We need to get to 17,000 more by 2030. We think about 14,000 of that is going to be solar and wind upstate because land is cheaper — and available.”
If that forecast is accurate, “we have got to make sure we have enough transmission available to move that energy downstate to our load centers; otherwise we won’t get the benefits of it,” Jones said, who noted the state is “making some good progress” on projects that improve transmission flows from the western to central part of the state. The ISO is also seeking board approval for another line that will approve transfer capability in the Lower Hudson Valley. (See NYISO MC Supports AC Transmission Projects.)
New York hasn’t built much transmission since the 1980s, with 80% of the state’s transmission assets built prior to 1980, he said.
“The system’s quite old, so we need to develop the system in order to bring more renewables downstate,” Jones said.
The 2,400 MW of offshore wind being planned in New York “comes in at a great location in the state, on the backside of our load, so it’s a fantastic location, but we have to figure out how to bring that wind onshore, how to distribute it appropriately, so we don’t have great impacts on the system,” Jones said.
Kevin T. Knobloch, president of New York OceanGrid, owned by Anbaric Development Partners, made a case for planning “open access” offshore wind energy transmission before the first turbines go in the water.
Anbaric has filed HVDC interconnection requests for 800 MW into the Farragut substation in Brooklyn and for 800 MW into the Ruland Road substation on Long Island for its hoped-for offshore wind grid.
Knobloch, who served as chief of staff at the U.S. Department of Energy from 2013 to 2017 and is a former president of the Union of Concerned Scientists, said, “New York can and should design and build a planned open-access offshore wind transmission system in which generation and transmission are separately constructed and owned.
“There’s a concern that if you follow our recommendation and plan it out from the start, that will slow down the process. We disagree and believe there’s a missed opportunity if regulators ask the first offshore wind generation developers … to also build transmission and run their own direct cables to shore,” Knobloch said.
Long-term planning from the start not only minimizes environmental impacts of laying unnecessary cables but also sends a signal to investors that the state is serious about this new multibillion dollar industry, he said.
Order 888 in 1996 showed that “FERC, from a public policy perspective, has long had concerns about monopolistic disincentives that don’t necessarily align with the public interest, or frankly, that of the grid operators,” Knobloch said.
“It’s no accident that Texas has the greatest amount of installed wind capacity in the country, and it has a lot to do with Competitive Renewable Energy Zones,” Knobloch said. “They figured out pretty early on that we have a good sense of where our wind resources are. We have a pretty good sense of where we need to deliver that clean electricity to the demand zones — let’s map it out, let’s plan it ahead of time, and the wind generators get to plug into this backbone.”
Dennis Phayre, business development director for EnterSolar, a commercial and industrial solar developer based in New York City, said, “Most of the generation that’s going to need to get built in order to reach these goals is going to be utility-scale, and it’s going to be upstate, so the need for transmission does not go away with renewables.”
The intermittency of wind and solar has become much less unpredictable, with new tools like Watson allowing forecasts of output 24 — or even 48 — hours in advance with up to 97% accuracy, so the “problem” of intermittency has largely been solved, Phayre said.
“There’s certainly some tension between transmission and renewables, but there’s probably more complement than there is tension,” Phayre said. “The question is, what complementary value does on-site generation provide at the right locations?”
“There’s no doubt that transmission infrastructure is required, which is easier to say than do,” said Craig Orchant, managing partner of investment banking firm Ansonia Partners. “The challenge is, you really can’t invest money in power generation unless you know you can deliver it. Transmission is a huge requirement, and it’s been to a large degree unanswered, not just in New York state, but across the region, throughout New England and a lot of other places throughout the U.S. Horror stories you read in PJM in terms of how they’re trying to allocate transmission improvement charges to individual participants in the market is a good example.”
On the plus side, energy projects “have a tremendous amount of capital looking to go to work in them,” Orchant said. “The amount of money that has been raised, and the knowledge base of institutional capital to invest in this industry is really phenomenal. I’ve been doing this for 30 years … and there’s never been so much money looking to go to work.”
Couch White attorney Michael Mager, who represents a coalition of large industrial, commercial and institutional energy customers, said many of the state’s programs and mandates require long-term commitments of customer money.
“For large-scale renewables, we’re looking at 20-year contracts, for offshore wind we’ve been talking about 25-year contracts,” Mager said. “The programs continue going to 2030, so we’re potentially making commitments now to go to 2050 or 2055, so we are making decisions that our grandchildren will be paying for.
“This is not to knock any specific program,” many of which have a lot of benefits, Mager said. “On an individual basis you could probably make a case for every single one of them, including what they may or may not cost, but no one is looking at the total costs.
“Even though we have more and more renewables, and we have a lot of nuclear, the marginal unit for the vast majority of hours is gas-fired, so right now we have low electricity prices primarily because we have low gas prices,” he said. “When we have higher gas prices at some point in the future, then the impacts of all of these programs and long-term commitments layered on top of that, we are concerned it will not be a pretty picture,” Mager said.
Mager was also concerned that every program relies on mandatory customer payments.
“When the Public Service Commission adopted the renewable portfolio standard in 2004, the order said, ‘We believe an important part of the RPS program is to stimulate and complement voluntary, competitive renewable energy sales and purchases, or free markets, so that these competitive markets, not government mandates, sustain renewable activity after the RPS program ends,’” Mager said.
“The RPS program ended a while ago, and we have more mandates than ever before.”
In 2018, it is rare to find someone that has not had multiple generations of a smartphone, adopting newer technology as it improves — ultimately making users’ lives easier and more efficient. However, in the world of rapidly modernizing infrastructure, the U.S. electric transmission system — part of the greatest engineering achievement of the 20th century — remains largely unchanged.
In Australia and the U.K., the story is somewhat different. Regulatory bodies in these countries recognize the radical evolution occurring in the energy industry — such as the growth of distributed generation, the proliferation of electric vehicles and the electrification of heat — is creating unprecedented uncertainty in a historically stable industry. Regulators want electricity providers to engage more effectively with their customers and other stakeholders to understand their needs and how they may change in the future. By instituting innovative incentives and frameworks, Australian and U.K. regulators are rewarding utilities that anticipate and respond to future uncertainty by leveraging innovative tools and business practices. These regulatory bodies have set up structures that encourage utilities to develop a more flexible and forward-looking approach.
In the U.K., for example, the RIIO framework — that is “Revenue = Incentives + Innovation + Output” — is the British energy regulator’s (Ofgem) performance-based framework for setting price controls and ensuring consumers pay fair prices. The RIIO framework financially rewards companies that innovate and run their networks to better meet the needs of customers, specifically focusing on increasing transfer capacity in the most efficient way possible. For example, for National Grid Electricity Transmission (NGET), Ofgem established a baseline ($/MW) that they anticipate network companies having to pay to increase transfer capacity across a specific boundary. However, if network companies develop a more efficient or lower-cost way to provide that same system improvement, half of the savings go to consumers and half of the savings go to the network shareholders. In this way, RIIO is encouraging network companies to think about their business differently than just making investments to add to the rate base.
Corrieyairack Pass Towers on Beauly-Denny transmission line | Scottish and Southern Electricity Networks
RIIO allocates incentives based on a utility’s ability to deliver specific, agreed-upon outputs in categories including safety, reliability, network availability, customer satisfaction, network connections and environmental. RIIO differs from past frameworks in that it establishes longer (eight-year) price controls and expands programs that encourage the growth of smart grids.
In Australia, the Network Capability Incentive Parameter Action Plan (NCIPAP) provides financial incentives to network businesses to improve usage of existing grid assets through low-cost projects. As a part of the plan, which is driven by the transmission owners, the Australian Energy Market Operator (AEMO) conducts independent analysis of network limitations, considering historical congestion, future network flows, and reliability and security implications — ultimately prioritizing the NCIPAP projects that deliver the best value for money for customers. NCIPAPs are intended to reduce congestion and drive reduced wholesale energy prices by alleviating existing transmission bottlenecks without investment in large infrastructure projects, and transmission companies earn 50% greater rate of return on these projects, which are capped at $6 million (AUD) capital spend.
500kv transmission lines in Australia
Conversely, from a U.S. perspective, while a number of proven, advanced technologies exist that can help optimize the existing transmission grid, proliferation has not occurred as utilities are often reticent to adopt emerging technology. From a regulatory perspective, there is limited incentive to choose efficient, low-cost options instead of adding traditional large capital projects to the rate base. This ultimately contributes to the sluggish pace of innovation and propagation of new technology needed to modernize a 21st century grid.
According to the Working for Advanced Transmission Technologies (WATT) Coalition, many of the U.S.’ existing regulatory structures are designed to directly or indirectly incentivize bigger capital investments and projects. This can result in disincentivizing investment in more relatively low-cost technologies that offer significant operational benefits and consumer savings; this is what both RIIO and NCIPAP are trying to address. WATT estimates that if advanced transmission technologies were adopted and deployed broadly, customers could see the cost of electricity reduced by as much as $2 billion per year.
The Energy Policy Act of 2005 has made strides toward policies to progress grid modernization, but it has not necessarily resulted in regulations that encourage the deployment of proven, newer technologies that would benefit grid operations and reduce costs. Instead, incentives are offered for advanced technology only if it is part of a grid expansion proposal and has demonstrated that there is some risk to its deployment. This is a challenge for utilities to embrace, as they will always prioritize reliability and safety over innovation.
Perhaps American policymakers would benefit from looking to our friends in Australia and Europe and how they have established frameworks that incentivize innovation in the electric utility space. Many hardware and software products exist today that can help improve existing transmission grid infrastructure, such as those that uncover and utilize hidden transmission capacity, reduce or reroute power flow on overburdened lines, and reconfigure existing grid elements to optimize various operational scenarios. When adopted and implemented, these technologies will result in consumer savings and improvements to reliability and resiliency — something regulators around the world continue to strive for.
Maggie Alexander is Director of the Western Region at Smart Wires, a modular, scalable, redeployable powerflow control technology company based in Northern California.
FERC on Monday approved part of PJM’s cost responsibility assignments for its updated Regional Transmission Expansion Plan but rejected allocations for four cross-border projects, instituting a Section 206 proceeding to revise the RTO’s Tariff language to address the reasons for its rejection (EL18-173, ER18-614, et al.).
The commission approved 41 projects, but rejected the allocations for the Targeted Market Efficiency Projects b2971, b2973, b2974 and b2975. PJM transmission owners had argued that PJM erred in not allocating project costs to Hudson Transmission Partners and Linden VFT, which operate merchant lines into New York City and had recently converted their firm transmission withdrawal rights to non-firm rights. Those lines would benefit from the TMEPs, other TOs contended.
| Fré Sonneveld/Unsplash
FERC rejected PJM’s argument that the Hudson and Linden facilities should be exempt, noting that PJM’s Tariff says, “Transmission congestion charges are incurred in the zones and merchant transmission facilities in which market buyers experienced net transmission congestion charges, regardless of whether the merchant transmission facility has firm or non-firm transmission withdrawal rights.”
PJM also recognized its requirement to assign TMEP costs in the zones and merchant facilities “shown to have experienced net positive congestion over a two-year historical period as determined by PJM and MISO” but didn’t allocate any costs to Linden or Hudson, nor provide any explanation, the commission said.
It also said Schedule 12 in PJM’s Tariff, which outlines cost allocations, is ambiguous about whether merchant facilities should be exempt from allocations, which PJM argued they should be.
“We therefore find that the most reasonable interpretation of the PJM Tariff is to allocate within PJM its share of the costs of TMEPs to those zones and merchant transmission facilities in PJM that are shown to have experienced net positive congestion over the two historical years, as determined by a TMEP study conducted by MISO and PJM,” the commission said.
FERC denied PJM’s use of two commission opinions and its decision to grant the requests from Linden and Hudson to convert their firm withdrawal rights to non-firm transmission withdrawal rights, saying they provide no guidance because they focus on different issues.
The commission ordered PJM to file new cost assignments that “must reflect Hudson’s and Linden’s pro rata share of the sum of the net transmission congestion charges paid by market buyers of the zones and merchant transmission facilities in which market buyers experienced net transmission congestion charges, as identified through the TMEP study.” PJM has 30 days to clarify the Schedule 12 language or show cause why it shouldn’t be revised.
FERC set the 206 proceeding to adjust Schedule 12 to conform with its interpretation in the order. Parties interested in being involved have 21 days to register. FERC set the refund date for when the proceeding is published in the Federal Register.
FERC also rejected protests from the Public Power Authority of New Jersey, the New Jersey Board of Public Utilities and Dominion, saying PJM adequately addressed them.
