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.
FERC on Monday denied ISO-NE’s request for a Tariff waiver to keep Exelon’s Mystic generating plant running, instead ordering the RTO to revise its rules to allow cost-of-service agreements for facilities needed to address fuel security issues (ER18-1509).
The commission’s July 2 show cause order instituted a Section 206 proceeding (EL18-182), finding that ISO-NE’s Tariff is not just and reasonable because the RTO lacks a way to address fuel security concerns that it said could result in reliability violations as soon as 2022. The Tariff currently allows cost-of-service agreements only to respond to local transmission security issues.
FERC ordered the RTO to submit interim Tariff revisions for a short-term, cost-of-service agreement for Mystic within 60 days, and permanent Tariff revisions to address future fuel security needs by July 1, 2019.
The commission also pushed back the deadline for Exelon to submit its retirement decision for Mystic Units 8 and 9 for Forward Capacity Auction 13 from July 6 to Jan. 4, 2019 — one month before the auction.
Commissioners Cheryl LaFleur and Neil Chatterjee wrote concurring opinions, while Commissioners Robert Powelson and Richard Glick dissented in part.
| ISO-NE
The RTO filed its waiver request on May 1, after Exelon said in March that it would retire the 2,274-MW plant when its capacity obligations expire on May 31, 2022.
Exelon later said it “may reconsider” the decision to retire Mystic if the markets could properly value the plant’s contributions to reliability and regional fuel security. (See Mystic Closure Notice Leaves Room for Reversal.) On the same day it issued the retirement notice, the company also announced it would purchase the Everett Marine (Distrigas) Terminal from ENGIE North America “to ensure the continued reliable supply of fuel to Mystic Units 8 and 9 while they remain operating.”
The commission agreed with the RTO that its January Operational Fuel-Security Analysis (OFSA) demonstrated that the loss of Mystic 8 and 9’s 1,700 MW would lead to 87 hours of depletion of 10-minute operating reserves and 24 hours of load shedding during the winters of 2022/23 and 2023/24. (See Report: Fuel Security Key Risk for New England Grid.)
The commission rejected the contention of some intervenors that the RTO had failed to demonstrate a compelling need for out-of-market action. (See Mystic Waiver Request Spurs Strong Opposition.)
‘Inappropriate Vehicle’
But the commission said that the waiver request was “an inappropriate vehicle” because it “effectively creates an entire process that is not in the ISO-NE Tariff” for cost-of-service agreements addressing fuel security. “Such new processes may not be effectuated by a waiver of the ISO-NE Tariff; they must be filed as proposed tariff provisions under [Federal Power Act] Section 205d,” the commission said.
Mystic Generating Station, on the Mystic River in Everett, Massachusetts. A wind turbine owned by the local water authority to power a pumping station is on the right.
Powelson said he “strongly” supported denying the waiver request, “which, if granted, would have amounted to an end-run around” the RTO’s stakeholder process.
“I cannot, however, support prematurely clearing a path towards out-of-market, cost-of-service payments to generators without having fully exhausting all other alternatives,” Powelson said in his dissent. “Unfortunately, rather than working through the stakeholder process, ISO New England acceded to the demands of Exelon and chose to file a tariff waiver.”
Powelson acknowledged that New England states have prevented investors from responding to market price signals by blocking new transmission and gas pipelines.
“While I agree that states have certainly interfered with market outcomes, by no means is this indicative of a market failure, nor does it justify a logical leap to the conclusion that out-of-market support to retain certain existing resources may be necessary,” Powelson said.
Glick called the ruling a “rush to judgment,” noting that the reliability concerns identified by ISO-NE are at least four years away.
“Instead of rushing to install new tariff provisions years before the fuel security concern may arise, the commission, ISO-NE and stakeholders should engage in a thorough process to evaluate potential fuel security problems and identify durable solutions rather than another series of Band-Aids,” he said.
Glick said the commission “has not clearly defined the fuel security problem” it is trying to address, quoting from the majority’s acknowledgement that that “fuel security analyses do not currently have an established methodological framework and that there are no industry standards or best practices for conducting such an analysis.”
He said although the commission’s order allows ISO-NE to argue that its existing Tariff is not unjust and unreasonable, “it is clearly a show cause order in name only.”
“In so doing, the commission cuts off an opportunity for a real debate about what the ISO-NE analysis actually tells us about fuel security. We can expect that ISO-NE will submit Tariff revisions based on that same analysis, without any further discussion of how that analysis should be used or how it could be improved.”
Glick said FERC and ISO-NE could find other solutions to their concerns, such as modifying the RTO’s transmission planning process to incorporate fuel security or “reforms to improve the utilization of existing pipeline capacity, which could potentially include additional hourly nomination service to increase both the transparency of market demand and provide improved price discovery.”
He said he agreed with Powelson that the order could undermine the RTO’s capacity market and its Competitive Auctions with Sponsored Policy Resources construct, approved in March. “By requiring ISO-NE to develop generic tariff provisions for cost-of-service treatment for resources needed for fuel security, the order provides an incentive for resources to seek that treatment rather than retire once uneconomic,” Glick wrote. “At a minimum, we should expect that retiring resources will use the prospect of a full cost-of-service arrangement as little more than leverage in order to extract a large ransom payment for exiting the market.”
LaFleur: No Precedent
Chatterjee wrote a concurrence saying the RTO’s predicament illustrates the need for the interim out-of-market measures he proposed when the commission rejected the Department of Energy’s request for bailouts of coal and nuclear generators. The commission instead initiated its resilience docket (AD18-7).
“Had a majority of my colleagues supported that position, we could by now have measures in place to address near-term fuel security and resilience risks in ISO-NE and other RTOs/ISOs,” Chatterjee said.
But LaFleur said that while she supported the waiver denial, “today’s order does not lend credence to a generic or national resilience need, or an approach to address that need. Rather, today’s order rightly responds to documented and specific regional challenges in New England, including its dependence on a unique generation facility that can be served only by imported LNG.”
Rising state subsidies for renewable and nuclear power require PJM to revamp its minimum offer price rule (MOPR) to address price suppression in its capacity market, FERC ruled Friday.
The commission ruled 3-2 that the rule, which now covers only new gas-fired units, must be expanded to all new and existing capacity receiving out-of-market payments, such as renewable energy credits and zero-emission credits for nuclear plants. Democrats Cheryl LaFleur and Richard Glick dissented, calling the ruling hasty and counterproductive.
The commission’s ruling — a rejection of PJM’s April “jump ball” capacity filing (ER18-1314) and a partial grant of a 2016 complaint led by Calpine (EL16-49) — initiated a Section 206 proceeding in a new docket (EL18-178).
The commission rejected both PJM’s capacity repricing proposal and the Independent Market Monitor’s MOPR-Ex proposal, saying neither was just and reasonable. It agreed with Calpine that the existing MOPR was also unjust and unreasonable but declined to adopt the company’s proposed remedy.
Instead it consolidated the two cases into the new docket for a “paper hearing” on an alternative approach in which PJM would expand the MOPR to all subsidized resources with “few to no exemptions.” FERC also recommended creating a mechanism similar to the fixed resource requirement (FRR) allowing states to pull subsidized resources — and associated loads — from the capacity auction.
Comments on the commission’s proposal are due in 60 days, with reply comments 30 days after that. The commission said it hoped to issue a final ruling by Jan. 4, 2019, in time for the 2019 Base Residual Auction.
PJM spokesman Jeff Shields released a statement saying the RTO “is pleased that the commission is taking action to address the price-suppressive impacts of resources that receive out-of-market payments.”
“The order appears to be a positive step to change competitive electric market design while recognizing the important role states play in influencing the resource mix through retail energy policies,” it continued. “We will begin work immediately to develop the kind of bifurcated capacity construct envisioned by the commission and actively engage stakeholders, including the states, within the timetable laid out by the commission. We seek to ensure markets continue to deliver reliability at the lowest cost, drive investment without imposing risk on consumers, align generator performance with grid operations, support economic development and encourage technology innovation.”
The commission said PJM’s capacity market has become “untenably threatened” by out-of-market payments resulting from state initiatives.
“What started as limited support primarily for relatively small renewable resources has evolved into support for thousands of megawatts of resources ranging from small solar and wind facilities to large nuclear plants,” the commission said. “As the auction price is suppressed [by subsidized resources], more generation resources lose needed revenues, increasing pressure on states to provide out-of-market support to yet more generation resources that states prefer, for policy reasons, to enter the market or remain in operation. With each such subsidy, the market becomes less grounded in fundamental principles of supply and demand.”
All PJM states excluding West Virginia, Kentucky and Tennessee have renewable mandates or goals.
| PJM
According to an analysis by Anthony Giacomoni, PJM senior market strategist for emerging markets, the percentage of the RTO’s load subject to renewable portfolio standards has risen to 8% from 2.15% in 2009. Giacomoni said the percentage will reach almost 13.5% in 2033, with New Jersey, Maryland, Delaware and Illinois hitting 25% and D.C. rising to 50%.
PJM’s Board of Managers submitted the “jump-ball” filing after stakeholders lobbied against capacity repricing, under which the RTO would have accepted bids from subsidized resources in its capacity auctions but then isolate them during a second stage and reset the price without them. Stakeholders were more supportive of the Monitor’s MOPR-Ex proposal, which would have extended the MOPR to all units indefinitely, with carve-outs for states’ renewable portfolios and public power self-supply. (See PJM Capacity Proposals to Duel at FERC.)
Capacity Repricing
The commission said the capacity repricing plan would disconnect the determination of price and quantity in the BRA, undermining its price signals.
“Though the second stage price may not be suppressed by uncompetitive offers from resources receiving out-of-market support, the higher price — created by repricing — would signal that the market would buy capacity from higher-cost resources than actually clear the market and receive capacity commitments,” FERC said. “This would make it more difficult for investors to gauge whether new entry is needed, or at what price that new entry will clear. … Market participants would see the final, second-stage clearing price but would have limited information on which resources received commitments and the first-stage price.”
The commission said the plan would result in a “windfall” to subsidized resources, which “would not only receive the same clearing price as competitive resources, but would then further benefit from the higher price set in stage two of the auction.”
“PJM’s proposal therefore will increase prices for load … [and create] an unjust and unreasonable cost shift to loads who should not be required to underwrite, through capacity payments, the generation preferences that other regulatory jurisdictions have elected to impose on their own constituents.”
The commission rejected PJM’s contention that its approach was similar to ISO-NE’s Competitive Auctions with Sponsored Policy Resources, a two-stage capacity auction to accommodate state renewable energy procurements, which FERC approved in March. (See Split FERC Approves ISO-NE CASPR Plan.) “CASPR does not allow [subsidized] resources unfettered access to the market, [and] it retains and strengthens ISO-NE’s MOPR for all new resources by phasing out the renewable technology resource exemption,” FERC said.
The commission also found that PJM failed to support its proposed materiality threshold for initiating repricing, which it set as either 5,000 MW of unforced capacity across the region or 3.5% of the reliability requirement for any locational deliverability area.
MOPR-Ex
The Monitor’s MOPR-Ex proposal would have extended MOPR to all fuel types while exempting self-supply, public power and electric cooperative resources — which the RTO said were unlikely to suppress prices — along with RPS resources.
The commission said PJM failed to justify the RPS exemption.
PJM said the 5,000 MW of renewables needed to meet RPS requirements in 2018 will grow to 8,000 MW by 2025. The RTO also said the Illinois and New Jersey ZEC programs could subsidize 4,760 MW of nuclear generation and that New Jersey and Maryland have authorized a total of 1,350 MW of offshore wind procurements.
10 of 13 PJM states and D.C. have renewable portfolio standards or goals. | NCSL
“PJM has not shown that the exempted resources have a different impact on its capacity market than those which are not exempted. Moreover, PJM’s assertion that the RPS exemption was based on deference to public policies favoring renewable generation resources is inconsistent with the well-established desire of some states in PJM to support other resources, such as nuclear plants,” FERC said. “In addition … it is unclear why state programs limited to offshore wind should not be eligible for the RPS exemption given that such resources would likely have a market impact similar to other exempted state-sponsored renewable resources.”
The commission acknowledged that it has approved MOPR exemptions for renewables in NYISO and ISO-NE but said those grid operators minimized price suppression by capping the amount of generation eligible for their set-asides.
Calpine Complaint
The commission agreed with a 2016 complaint by Calpine and 10 other generating companies, which alleged PJM’s MOPR was unjust and unreasonable because it failed to address price suppression by existing subsidized resources. (See Generators to FERC: Expand MOPR for Subsidized FE, AEP Plants.)
The company filed the complaint in response to ratepayer-funded subsidies then under consideration in Ohio. Although the Ohio subsidies were later withdrawn, Calpine amended its complaint in response to Illinois’ ZECs program.
“The increase in programs providing out-of-market support, such as ZEC programs, has changed the circumstances in PJM, such that it is no longer possible to distinguish the treatment of new and existing resources in the context of PJM’s MOPR,” FERC said.
But the commission rejected Calpine’s proposal that it immediately extend the MOPR to additional resources and direct PJM to conduct a stakeholder process to develop a long-term solution.
Addressing Double Payments
Although it has previously approved ways for customers to avoid paying twice for capacity because of state policy decisions, the commission cited appellate court rulings that it is not required to do so. “Nonetheless, we do not take this concern — or the states’ right to pursue valid policy goals — lightly,” FERC said.
As a result, it proposed a resource-specific “FRR Alternative” option allowing the removal of subsidized resources from the capacity market along with a commensurate amount of load.
FERC said its approach will improve transparency.
“Though the capacity market side of the bifurcated capacity construct will be relatively smaller, the expanded PJM MOPR will ensure that all resources participating in the capacity market, whether or not these resources receive out-of-market support, offer competitively. Further, the bifurcated capacity construct should make more transparent which capacity costs are the result of competition in the capacity market and which capacity costs are being incurred as a result of state policy decisions. Finally, depending on how load is selected for the new resource-specific FRR Alternative, this capacity construct should help confine the cost of a particular state policy decision to consumers within the state that made that policy decision, whereas the status quo requires consumers in some PJM states to subsidize the policy decisions of other PJM states.”
Dissents
The majority opinion quoted LaFleur’s earlier warning of “‘unplanned reregulation,’ one subsidy and mandate at a time.”
But LaFleur dissented from the ruling, calling the rejection of PJM’s current rules “a troubling act of regulatory hubris that could ultimately hasten, rather than halt, the reregulation of the PJM market.”
LaFleur said 90 days was insufficient time to determine “the most sweeping changes” to PJM’s capacity construct since its inception 12 years ago. She said she would have rejected capacity repricing while calling for further development of MOPR-Ex.
The FRR Alternative “presents resource owners and states with choices that could be difficult to make in advance of the May 2019 BRA, particularly given that some of the state programs are statutory in nature and could require legislative action to reform,” LaFleur wrote. “I do not share the majority’s confidence that this proposal is the obvious solution to the challenge before us, in no small part because it is not clear to me how this construct will actually work.”
In a separate dissent, Glick said the commission rejected PJM’s current Tariff based on “theory alone.” The RTO’s capacity surplus suggests prices are too high, not too low, he said.
He called the commission’s solution “arbitrary and capricious,” reciting a list of federal and state policies that subsidize or reduce the costs of nuclear power and fossil fuels.
“The commission’s real aim is to support certain resources that do not benefit from state efforts to address environmental externalities,” he wrote. “Doing so puts the commission on the wrong side of history in the fight against climate change.”
Commissioner Robert Powelson, who sided with Chairman Kevin McIntyre and Commissioner Neil Chatterjee in the majority, wrote a concurrence defending the ruling as long overdue.
“The issue of out-of-market support for preferred resources is not a new one. In 2013, the commission opened a proceeding to discuss the interplay between state public policy decisions and wholesale markets. In May 2017, the commission continued that effort by holding a two-day technical conference to further explore the issues. After years of open dialogue unconstrained by ex parte restrictions, the commission failed to provide guidance on one of the most pressing issues facing wholesale electricity markets,” he said. “Failure to take decisive action would be a disservice to PJM, its stakeholders and ultimately consumers.”
Next Steps
The commission acknowledged many details remain to be determined, inviting comment on issues including:
The scope of out-of-market support to be mitigated by the expanded MOPR, and how resources become eligible for the FRR Alternative.
How to identify the load removed from the capacity auction.
What MOPR exemptions should be permitted. “For example, should an exemption be included for self-supplied resources used to meet loads of public power entities? Alternatively, should those resources have the option to use the resource-specific FRR Alternative? What, if any, exceptions should be added to the MOPR for existing resources in the capacity auction?”
The length of time resources choosing the FRR Alternative must remain outside the capacity market and the mechanism by which they can return.
How the FRR Alternative would accommodate required reserves and whether any changes to the demand curve are necessary.
Whether federal sources of out-of-market support should be addressed by the commission and how the capacity market changes will interact with PJM’s fuel security initiative.
The commission acknowledged the magnitude of the changes it proposed and said PJM may request a waiver to delay the 2019 BRA, as it did in 2015 during development of Capacity Performance.
CAISO projects it will cost as much as $18.5 million to provide reliability coordinator (RC) services to areas outside its balancing authority, up from an estimate of $12.5 million in its original straw proposal.
The projected head count for the ISO’s RC services also jumped from 31 to 36 full-time employees — and from 50 to 55 full-time equivalents, including contributions from staff in other ISO divisions. The RC program would represent its own cost category within the ISO, alongside system operations, market services and congestion revenue rights services, but some functions would overlap.
By comparison, Peak Reliability, the Western Interconnection’s current RC, had a $45 million budget for 2018, which it said would fall to $31.2 million under a “transitional RC” plan, or $28.7 million if CAISO leaves the organization and all other funders remain. (See Peak Details Vision for ‘Transitional’ RC.)
Reliability Coordinator services will represent a new line of business with its own cost category for CAISO. | CAISO
CAISO attributed its increased estimates, in large part, to the high level of interest in its RC services. (See Most of West Signs up for CAISO RC Services.) The ISO plans to implement the RC program in its own balancing authority area in July 2019, followed by a rollout to other parts of the West starting two months later.
Under the $18.5 million scenario, 9% of CAISO’s $205 million in annual costs would be attributable to RC services, although those costs would be fully offset by fees paid by RC customers. The ISO estimates that RC customers will be charged 3 to 4 cents/MWh.
“This is a [financial] model including a significant portion on the Western Interconnection,” CAISO CFO Ryan Seghesio told stakeholders during a June 27 meeting to discuss the ISO’s draft final RC proposal. Seghesio noted the ISO has received letters of intent from a large share of the BAAs in the interconnection, while also acknowledging the nonbinding nature of those documents — and that some of the BAs have also submitted LOIs to SPP.
“If everybody in the Western Interconnection were to sign up for the ISO, would $18.5 million cover it?” asked Jim Shetler, general manager of the Balancing Authority of Northern California.
“This is the model, yes,” Seghesio said.
Getting the Rate Right
Deb Scott, senior attorney with Salt River Project, asked about the impact on the RC rate if CAISO attracts “less than a significant portion” of the interconnection to its RC services.
Seghesio explained that CAISO will file two different rate structures in its Tariff next year. The first will reflect the implementation of RC services for the existing CAISO footprint, which will not incur significant costs because the ISO already performs many of the reliability functions for its members.
But costs for the services will ramp up after the first non-CAISO members come on board, whether in September 2019 or later in the year, which will trigger use of the second higher-level cost structure for all RC customers, he said. The second structure will be scaled to align with the number of actual customers, so it may not hit the $18.5 million estimate.
Scott pressed for more details on how and when the RC rates would be set considering the uncertainty around the final customer base.
“FERC’s going to approve the rate design,” Seghesio said. “The actual rates won’t be determined until we do the revenue requirement each year, so when we get to the end of 2018, we’ll take the revenue requirement to the [CAISO Board of Governors] for approval, [and] that will kind of set this initial amount. By then we would have a better picture of what the service area will look like, and that will kind of set the rates.”
Gary Tarplee, principal adviser with Southern California Edison, asked whether CAISO’s 55-FTE estimate represents the top-end staffing requirement for an RC covering the full Western Interconnection, or if the number could exceed that.
“This is the full-cost model, whether it’s a significant portion or everybody, this model will work. We’re showing really what the highest cost would be,” Seghesio said.
He later clarified that the full-cost model is driven more by geographical diversity of the customer base than by its size.
“If we get some members in the Southwest and members in the Northwest, we really get to that full-cost model, because that determines the number of desks we really need,” Seghesio said. He said a larger customer base will reduce the rate “because you’re going to have more volume dividing into that $18.5 million.”
Billing Details
CAISO says it would levy a minimum $5,000 annual charge for RC customers with zero to low megawatt-hour volumes because they still require a “constant, although minimal, amount of attention.”
Seghesio also noted that, in response to stakeholder requests, the ISO is proposing to bill customers annually for services.
“The big push [among stakeholders] was not to go to a monthly process,” he said.
In cases of non-payment, the ISO would notify the rest of its RC customers of a pending default (and a potential supplemental bill), and inform the Western Electricity Coordinating Council and NERC.
“We would retain the ability to suspend the customer’s RC services, but we realize that would lead to reliability issues, so I think the plan is that we know we’re going to have to continue to provide reliability services for that entity so it doesn’t impact the overall reliability of the grid,” Seghesio said. “But we would notify WECC that we are no longer the RC of record for that entity.”
The ISO is proposing an 18-month initial commitment for new members to ensure recovery of integration costs, with a 12-month notice required for exiting after the initial period. The proposal calls for one annual onboarding and exit window each April.
CAISO plans to take its RC proposal to its board on July 25. It hopes to execute agreements with members by Nov. 15.
Just the third executive director in GCPA’s 35 years, Foreman has helped guide the organization as it has expanded its regional presence and developed a program geared toward women. The organization has added events in recent years in Louisiana, Arkansas and Mexico, and held its fourth emPOWERing Women’s leadership conference in January.
“With six grandkids scattered across the U.S., it is time to prioritize life,” Foreman told RTO Insider. “I need the time to enjoy them, and they me, while we can. Definitely a hard decision, but I know it is the right one.”
In announcing a series of breakfast seminars in Mexico City, Foreman pointed out last year that the organization is focused on the Gulf Coast.
“The last I checked,” Foreman said, “Mexico is on the Gulf too.”
Robert Downing, a Greenberg Traurig attorney deeply involved in the Mexican market, cited GCPA’s seminars and conferences south of the border as having “encouraged the exchange of knowledge and business contacts between Mexico and Texas.”
“Tom took the initiative to establish strong relationships with power industry professionals involved in Mexico’s historic energy reform,” he said. “These efforts formed the basis for continuing dialogue between industry experts from both the U.S. and Mexico.”
Foreman has been active in the GCPA since its founding in 1983. He joined the organization’s board of directors in 1996, becoming president in 2011 and then being named the executive director in 2013.
“The GCPA board and Advisory Board are deeply grateful to Tom for his exceptional leadership and management, demonstrated by the organization’s accomplishments during his tenure,” Clark Hill Strasburger’s Mark Walker, board president, wrote in an email to the membership.
Katie Coleman, a partner with Thompson & Knight and the board’s treasurer, said Foreman’s announcement was not “entirely unexpected.” Upon taking the leadership position, he told the board he planned to work for five to seven years.
“Tom is going to be hard to replace,” Coleman said. “As a former board member, he has been key in maintaining institutional knowledge. His skill in keeping everyone organized and on schedule has been important to GCPA’s growth.”
The organization has added 13 corporate members during Foreman’s tenure, increasing that number to 132. GCPA claims more than 300 individual members.
“He embodies the core principles of GCPA with his passion to promote healthy and sustainable competitive markets by providing GCPA members with top quality programs, events and business development opportunities,” Walker said. “He has also built a solid professional team at GCPA that shares his enthusiasm and is key to its many successes.”
Walker credited Foreman for the GCPA’s recent growth, citing a doubling of annual scholarships provided to college and trade school students seeking careers in the industry and the development of the GCPA emPOWERing Foundation, which supports women, students, young professionals and leaders in the industry.
Foreman has helped organize and host as many as six major annual conferences and dozens of smaller events that provide education and network opportunities to 4,200 attendees each year, Walker said.
A Houston native, Foreman holds a master’s in engineering and a bachelor’s in electrical engineering from the University of Texas at Austin. He has worked for Gulf States Utilities, the Lower Colorado River Authority (LCRA) and as a consultant to rural electric cooperatives and municipalities. He retired from LCRA in 2012.
The ERCOT system set a new record for June peak demand last week, reaching 69 GW on June 27 during the hour ending 5 p.m.
That shattered the previous record of 67.9 GW, which was set on June 1. The new record withstood strong challenges the following two days, with demand reaching 68.6 GW on June 28 and 68.4 GW on June 29.
ERCOT’s control room | ERCOT
Demand broke the pre-2018 record of 67.6 GW during eight hourly intervals over the three-day span. Real-time average prices only broke triple digits once during that time, hitting $128.98/MWh in the interval ending at 1:30 p.m. on June 29.
Temperatures climbed into the 100s F in much of Texas last week, with heat indexes approaching 110.
ERCOT has projected a summer peak of 72.8 GW in August, which would break the 2016 record of 71.1 GW. 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.)
FERC last week ordered settlement judge procedures over Westar Energy’s tariff revisions updating its transmission and distribution loss factors (ER18-1418).
“We find that Westar’s proposed tariff revisions raise issues of material fact that cannot be resolved based on the record before us,” the commission said. “Our preliminary analysis indicates that Westar’s proposed tariff revisions have not been shown to be just and reasonable.”
| Westar
Kansas-based Westar is seeking to raise its loss factors from 3.07% to 3.47%, based on a study it performed using data and load-flow models from 2016 supplied by SPP. The current figure is a result of a 2013 settlement that locked it in for five years, with an updated study to be filed every succeeding five-year period.
Westar noted that the 2016 data reflect system losses lower than those recorded in 2014-2015 and 2017. It contended that customers would benefit from “locking in” lower loss factors for the next five years, given the settlement’s moratorium provision.
Kansas Electric Power Cooperative and the Kansas Power Pool protested, arguing that the increase and the underlying study were highly complex, “with numerous assumptions that must be understood and vetted.” They said the loss factors were inconsistent with known changes on Westar’s transmission system, pointing out the utility had spent more than $900 million in improvements between 2011 and 2016 that should “portend a decrease in transmission losses … not an increase.”
The two parties further alleged Westar’s study “inappropriately” excluded certain elements that would have lowered the estimated losses for 2016. They said that the utility had not demonstrated the reasonableness of including generator step-up losses in its calculation, nor its use of a top-down method for estimating certain losses while using a bottom-up method for others.
Westar responded that its previous study indicated losses of 3.65%, and that the current 3.07% mark was set by the 2013 settlement, noting that its loss factors do not include losses from generator step-up transformers. The utility contended that its treatment of state estimator losses is proper and that its study normalizes for conditions experienced on its transmission system.
The Nemaha-Marshall Electric Cooperative Association also intervened, saying it was concerned that Westar was incorrectly using annual peak load in applying the loss factors for the association’s wholesale distribution service charges, possibly leading to over-recovering facility service charges and associated losses.
In its reply, Westar countered that it uses the peak load for each facility in its losses calculation and the wholesale customer’s coincident peak when determining its share of the facility.
The Public Utility Commission of Texas last week set a hearing for Oct. 16-17 on Rayburn Country Electric Cooperative’s proposed transfer of 96 MW of load and 130 miles of transmission lines from SPP to ERCOT (Docket 48400).
Parties to the contested case agreed to the schedule during a prehearing conference before the commissioners June 28.
PUC of Texas June 28 open meeting | PUCT
Rayburn Country and NextEra Energy’s Lone Star Transmission filed a request in May to move Rayburn’s SPP load and related transmission assets into ERCOT and transfer an 11-mile, 138-kV line and associated facilities to Lone Star.
The contested case stems from an earlier docket (47342), in which Rayburn had proposed to transfer 190 MW of load from SPP into ERCOT. The two companies have proposed to use a transmission plan ERCOT put together as part of the earlier proceeding to integrate Rayburn’s load.
ERCOT originally estimated the integration costs at $38 million, but a “modified alternative option” suggested by Oncor has lowered the cost to $31.7 million.
SPP also conducted a study of Rayburn’s migration in coordination with ERCOT. The RTO’s analysis indicated annual production cost savings of $14 million to $18 million in its footprint through 2025. SPP’s Texas territory would save $15 million to $19 million over the same period. According to the study, SPP’s transmission customers will see a total increase of $4.6 million in their annual transmission revenue requirements.
Both system operators are among the proceeding’s intervenors.
The SPP load accounts for only 12% of Rayburn’s demand, with the remainder in ERCOT. The co-op owns and operates 367 miles of transmission lines in Texas, 207 miles in ERCOT and 160 miles in SPP’s East Texas footprint.
Lone Star is a transmission-only utility in ERCOT that owns and operates about 624 miles of 345-kV transmission facilities in Texas.
Commission Approves Wildorado Wind Ranch Purchase
During the commissioners’ open meeting, the PUC approved GIP III’s acquisition of NRG Energy’s Wildorado Wind Ranch, a 161-MW facility within SPP’s footprint near Amarillo, Texas (Docket 48139).
Wildorado Wind Ranch
The commissioners ruled the transaction would not exceed the Public Utility Regulatory Act’s 20% limitation on combined ownership and control of installed generation capacity within a power region.
PUC of Texas Chair DeAnn Walker | PUCT
PUC Chair DeAnn Walker modified the order to use the facility’s nameplate capacity in calculating the installed generation capacity’s share. The applicants had proposed the capacity be calculated at 5% of nameplate, based on SPP’s planning criteria, but Walker said “no data was provided in the record” to support their calculation.
The use of nameplate capacity increased GIP III and its affiliates’ generation ownership within SPP to 4,814 MW, or 5.48%.
Walker called for a rulemaking to “clarify” how generating capacity is calculated in the future.
“The rules were originally adopted in 2000, and much has been learned since that time,” she said in a memo.
Powelson tweeted “with mixed emotions” the surprise announcement on Thursday, linking to a statement posted on FERC’s website.
“It has been an honor to serve this great country,” he said. “My family and I are deeply appreciative of this opportunity. FERC is a world class organization. Thanks to you, fellow FERCians!”
Powelson said he will leave the commission in mid-August to become president and CEO of the National Association of Water Companies. His departure could impact how the commission acts on several major initiatives, including the resilience docket FERC opened in January.
A former Pennsylvania Public Utility Commissioner, Powelson has been an unabashed supporter of natural gas and expressed skepticism over the Department of Energy’s effort to prop up struggling coal and nuclear plants.
“Why should we go out there and pick winners and losers in a market?” he said during a conference in March. “To do what? Hurt the other, more efficient units in the market or send bad market signals?” (See Powelson Tells New England to Learn from Pennsylvania.)
A Republican, Powelson was sworn in on Aug. 10, 2017, to a term that was to run through June 2020. His position on the five-person commission will be filled by another Republican, maintaining the GOP’s 3-2 edge.
“I’ll miss [Powelson]’s trenchant takedowns of the coal and nuclear bailout plans and can only hope he’s replaced by someone with as much vigor, expertise and sophistication,” tweeted University of Richmond law professor Joel B. Eisen.
Until a fifth commissioner is appointed, Democratic Commissioners Cheryl LaFleur and Richard Glick will have increased leverage. The two have dissented repeatedly on gas pipeline certificate orders, calling on the commission to consider the projects’ impacts on greenhouse gas emissions. (See Dem Dissents Show FERC Divide on Carbon.)
“This arrangement appears most likely to complicate — but not necessarily halt — the FERC’s approvals of natural gas pipelines and potentially other issues,” ClearView Energy Partners wrote in a note to clients Thursday night. “If Powelson’s seat remains vacant for an extended period of time, the absence of a third Republican vote could delay potential changes to the commission’s 1999 Certificate Policy Statement, which governs natural gas pipeline approvals pursuant to Section 7 of the Natural Gas Act. It is possible that further action on the commission’s ongoing resiliency docket could be delayed if the commission hits a 2-2 impasse.”
The New England Power Generators Association, which represents competitive generators, called Powelson’s departure “a major loss for FERC and all who participate in the dynamic energy markets. Commissioner Powelson has been a true leader on competitive electricity issues for years.”
But environmentalists and anti-fracking activists expressed no regrets over his departure.
“As a FERC commissioner, Robert Powelson was part of the FERC rubber stamp for pipelines,” said Maya van Rossum, leader of the Delaware Riverkeeper Network. “Powelson was not only a stalwart supporter of pipelines, but he was an outspoken critic of any members of the public who opposed pipelines, likening them to jihadists.”
“Powelson’s abrupt resignation doesn’t change the fact that FERC itself needs a massive change,” Mary Anne Hitt, senior director of the Sierra Club’s Beyond Coal campaign, said in a statement. “The next commissioner must be a strong advocate for considering climate change in FERC’s decision-making process, curtailing the dangerous overbuilding of fracked gas pipelines, and stand firmly against reckless coal and nuclear plant bailouts the Trump administration and grid operators are proposing.”
In his new post, Powelson will be running a trade group representing private water utilities serving almost 73 million people, almost one quarter of the nation. While with the Pennsylvania PUC, he chaired the National Association of Regulatory Utility Commissioners’ Water Committee for three years.
“Rob brings to the association tremendous experience at both the state and federal level,” Aqua America CEO Christopher Franklin, president of the NAWC Board of Directors, said in a statement. “He is taking the helm of the NAWC at an important time in the water industry. His unique skills and relationships will help to highlight the capabilities of NAWC member companies in solving some of the challenges facing many mid- and small-sized municipal water and wastewater utilities. Rob also has firsthand experience in working with utilities and regulators to encourage the investment in infrastructure that is critical in keeping our nation’s viable.”
By Tom Kleckner, Michael Kuser, Amanda Durish Cook, Michael Brooks and Rich Heidorn Jr.
Solar power and storage providers differed sharply with local distribution companies and state officials in comments filed this week in FERC’s rulemaking on distributed energy resources.
More than 50 commenters submitted answers to questions FERC posed, differing on whether aggregation should be limited to single nodes and on the roles of RTOs, state regulators and LDCs (RM18-9, AD18-10).
The commission initiated the rulemaking in February, deciding to separate DER issues from its Order 841 on energy storage. The comments supplement testimony from a technical conference in April. (See RTOs, Regulators Set Course for DER Market Participation.)
Below is a summary of the major issues and the range of recommendations FERC received, based on RTO Insider’s review of 40 comments.
How prescriptive should FERC be in its rulemaking?
Most RTOs and ISOs submitted comments, with PJM, NYISO and CAISO urging FERC to move forward while affording RTOs flexibility. “Distributed energy resources can, and do, participate in wholesale markets, and are contributing to grid reliability and resilience in new and important ways,” CAISO said. “The commission should not foreclose options for these resources.”
MISO said FERC should postpone issuing a final rule on DER market integration, calling it “premature.” The RTO said its footprint does not have a high volume of DER installation and said it’s not predicting significant penetration levels, or a need for DER aggregation, anytime soon.
“Commission directives requiring major additions to MISO’s existing market platform would yield almost no benefits given the lack of capability of MISO’s legacy technology system and low regional DER penetration. Prescriptive action would incur very high costs associated with retrofitting MISO’s soon to be retired platform … likely delaying the transition to a far more capable system,” the RTO said.
ISO-NE also pleaded for flexibility, saying its current market rules and the new approach to integrating storage under Order 841 indicate no need for a DER participation model in New England. “The DER participation model envisioned in the DER [Notice of Proposed Rulemaking] would be costly and disruptive, and would produce no additional value for New England,” the RTO said.
Distributed Energy Resources | Clean Coalition
The Advanced Energy Management Alliance called on FERC to create a “participation model” with a checklist for RTOs to demonstrate compliance with minimum requirements, like the one it included in Order 841 on energy storage. (See FERC Rules to Boost Storage Role in Markets.) It said the model should cover issues including market access, measurement and verification, and coordination with LDCs.
The Edison Electric Institute said FERC should “carefully consider the far-reaching impacts” of allowing DER aggregations to participate in the wholesale markets and defer to the grid operators and states on details.
“The proposal has significant implications for the reliability of the distribution system and additional time is needed to install infrastructure and to develop coordination agreements to ensure that the reliability of the distribution system and the [bulk power system] is maintained,” EEI said.
Public interest groups, including the Environmental Defense Fund, Sustainable FERC Project and Union of Concerned Scientists, said it would be premature for FERC to mandate best practices for transmission-distribution coordination. But it said the commission should finalize the DER aggregator participation model it proposed in November 2016. (See FERC Rule Would Boost Energy Storage, DER.)
“Relying on ISO/RTO stakeholder processes alone to eliminate barriers to market participation by non-incumbent storage and DER participation without commission involvement (as EEI suggested) would not likely yield results consistent with efficient functioning of the market or a fair outcome for these resources,” the groups said. “As noted by many commenters, the ISO/RTO stakeholder processes generally favor incumbent stakeholder members and underrepresent emerging technologies and the public interest.
“There is no need to further delay finalizing the proposed rule. Understanding that there might be legitimate reasons for RERRAs [relevant electric retail regulatory authorities] to delay implementation of the rule in their own regions, that may be done by granting a longer implementation timeline for that RERRA or a limited waiver,” the groups said.
The American Public Power Association said FERC must distinguish between “undue barriers to DER participation in wholesale markets and factors that, although they might have the effect of limiting DER participation in those markets, are grounded in legitimate operational, reliability and regulatory considerations.”
The Electric Power Supply Association said “any initiatives or rules to facilitate participation of [DER] must first and foremost be designed to serve reliability and efficiency objectives, not simply to facilitate DERs business model objectives.”
Should FERC permit aggregation of DER beyond a single node?
AEMA and the Solar Energy Industries Association said the commission should allow multi-nodal aggregation. “Aggregation at a node is not aggregation,” said AEMA, calling for aggregation across an area as “geographically broad as technically feasible.”
SEIA said it supports the commission’s proposed 100-kW minimum size requirement. “Even with [a] 100-kW minimum size requirement, however, there is no guarantee that each of the many thousands of nodes across the RTO/ISOs would be of a sufficient size to sustain aggregations and to foster market competition among multiple aggregators. Aggregators should have the ability to compete across a load zone, and allowing multi-node aggregation should reduce the price of delivered power by reducing congestion and alleviating system constraints.”
Limiting aggregations to a single node would hurt the economics of DERs and their value to system operators, “restricting their ability to deploy these resources economically and in response to reliability needs,” said Advanced Energy Economy, which represents more than 100 companies and organizations in energy efficiency, demand response, natural gas, renewables and storage.
PJM said multi-nodal aggregation would be challenging but that its experience modeling DR across multiple nodes shows it can be done. “PJM does not anticipate any significant modifications to modeling and dispatch software, communications platforms or automation tools to implement multi-node DER aggregations,” the RTO told the commission.
But opponents, including Calpine and EPSA, cited the technical conference comments of PJM Independent Market Monitor Joe Bowring and NYISO Manager of Market Design Michael DeSocio, who expressed concern at the technical conference over aggregation over multiple nodes.
“DER aggregation across multiple nodes is inconsistent with the design of the organized wholesale markets, will distort market outcomes and reduce efficiency, and should therefore not be mandated,” Calpine said.
“If the precedent is established now that DER, alone among generation resources, does not need to be nodal, it will be difficult or impossible to reverse that precedent as DER grows based on that approach,” the Monitor said in its filing. “The fact that aggregation may provide some short-term business benefits to the providers of DER is not relevant to defining the correct market design to facilitate the long-term, effective participation by DER.”
The Monitor said DERs can be priced and dispatched at individual nodes and still be aggregated across multiple nodes for settlement purposes.
How much control should local distribution utilities have over DER?
EEI said electric distribution companies “must have transparency and ultimate control over the resources connected to the distribution system” and that regulators must address cost allocation issues associated with distribution system investments needed to facilitate DERs.
“Generally, DER aggregations will increase, not decrease, volatility on the distribution system given its radial design, and because there may be significant changes in power flows that will have to be mitigated to ensure that load can be served under all circumstances,” EEI said.
The Transmission Access Policy Study Group, which represents transmission-dependent utilities, said “DER aggregations can adversely affect distribution systems.” FERC should “defer decisions to those with the best understanding of the relevant distribution systems, including an ‘opt-in/opt-out’ mechanism modeled on Order No. 719-A or, at minimum, an express opt-in requirement for small distribution utilities.”
The National Rural Electric Cooperative Association said FERC’s proposal to allow third-party DER aggregators to participate directly in RTO markets will present bigger challenges for its members than the deployment of DERs on cooperatives’ systems, requiring them to invest in new equipment and software.
“Third-party DER aggregators participating in the RTO/ISO markets will have incentives to operate the DER in response to wholesale market signals, which can pose operational, reliability and safety issues for local distribution cooperatives,” NRECA said.
NRECA also said third-party aggregators may engage in “cherry picking,” potentially preventing cooperatives from using their own or their members’ DER, which “may be a significant part of many cooperatives’ integrated resource portfolios. If those DER resources are available to third-party aggregators, this could severely undermine the cooperative’s ability to manage cost and risks for its consumer-members.”
“These factors were an integral part of the commission’s decision to permit RERRAs to decide whether to allow aggregators to bypass utility demand response programs and bid retail demand response directly into the wholesale markets in Order No. 719,” NRECA said.
Several commenters said they opposed giving LDCs veto power.
AEE said it supports reasonable mechanisms to ensure LDCs, aggregators and RTOs have sufficient operational coordination and situational awareness. “However, distribution utilities should not be given discretion to reject DER registrations in an aggregation for reasons beyond operational coordination and reliability,” the group said. “Allowing distribution utilities a broad veto, even in instances when a DER has an interconnection agreement in place, will restrict DER participation in wholesale markets, erode competition and potentially result in undue discrimination. The interconnection process determines what a DER needs to do to operate in a safe and reliable manner.”
EPSA said FERC should ensure LDCs don’t use their knowledge of their systems and needs for a competitive advantage in developing DERs. “If utilities are allowed to exploit their asymmetric access to information to the detriment of their competitors, even for the short term to speed the deployment of DERs, it will serve to chill merchant investment in this space, which may ultimately slow DERs deployment.”
SEIA also raised market power concerns. “Facing true competition from DERs, certain distribution utilities may have incentives to engage in conduct … to protect their current market positions,” it said.
Should state and local regulators have opt-out rights over DER?
AEMA and the Energy Storage Association said states should not be able to prevent consumers from participating in wholesale markets.
Instead, AEMA said FERC should clarify that states have the right to implement retail tariffs that prohibit participants from direct participation in wholesale markets. “In that instance, customers would choose whether they preferred to participate in a retail tariff or … via an aggregator in the wholesale market. The retail tariff could facilitate wholesale services and enable states to preserve their jurisdiction over retail customers, programs, and activities without impinging on customers’ ability to access wholesale markets,” AEMA said, citing Indiana and Michigan Power’s DR service rider.
But NRECA said FERC should defer to RERRAs’ timetables for implementation because the industry “is not uniformly ready for third-party DER aggregations.”
The National Association of Regulatory Utility Commissioners said it opposed a limited opt-out provision that would allow states to require DERs to choose participation in either the wholesale markets or retail programs, but not both.
“The limited opt-out provision provides no additional benefits or options to state commissions,” NARUC said. “States already have the authority to prevent an asset from participating in a retail compensation program [under the Federal Power Act]. … No FERC FPA-based regulation can require states to allow aggregated DER assets to participate in both RTO/ISO markets and retail compensation programs.”
Xcel Energy asked FERC to suspend the rulemaking pending further technology improvements, saying technology does not exist “to effectively and fairly integrate DERs” into wholesale markets. “In the meantime, states and other stakeholders can serve as the laboratory for policy initiatives in this arena as they move forward with incremental and evolutionary programs involving DER integration.”
How should concern over double payments be addressed?
AEE said “there is little to no risk that customers will ‘pay twice’ for the same service.”
The commission’s proposed blanket prohibition on wholesale market participation by aggregated DERs that participate in retail programs would “arbitrarily exclude many, if not most, existing DERs from the wholesale market, and limit the benefits that the wholesale grid can capture from these resources,” AEE said.
“Dual participation does not equal double compensation,” ESA said.
“Rather than limiting an entire function of DER assets by forcing the asset to participate exclusively in one market, ESA suggests that states examine specific services on a case-by-case basis, with sufficient evidence to demonstrate a justification for the exclusion, to limit a specific combination of two services by the same DER asset.”
ESA cited resources participating in both NYISO and Consolidated Edison’s DR program. “These assets are providing value for both the retail and wholesale markets and should be compensated accordingly — they provide demand savings for consumers and export power onto the grid for system support.”
Calpine said the commission must prevent DERs that receive out-of-market compensation from skewing RTO markets and price formation. “In particular, DERs that are compensated for participating in retail programs will not have to submit offers in the RTO/ISO markets that reflect their actual costs, and would therefore have a competitive advantage over resources that do rely on RTO/ISO market revenues,” it said. “Put simply, DERs should have to choose whether they want to participate in the retail market or an RTO/ISO market, and stick with that decision for a defined period (e.g., for five years, similar to the fixed resource requirement process in PJM).”
Vehicle and battery manufacturer Tesla said RTOs should require proof before allowing restrictions. “RTOs/ISOs should be required to articulate a specific scenario in which a resource would receive more than one revenue stream for only one distinct value.”
SEIA said the most effective solution “is to ensure that wholesale and retail services are clearly defined. Whether two markets compensate the ‘same service’ or ‘distinct values’ is a question that should be addressed on a fact-specific basis.”
