FERC on Wednesday rejected a rehearing request over PJM Transmission Owners’ revised processes for planning supplemental projects, ruling it in compliance with Order 890.
The commission denied a request by American Municipal Power, Old Dominion Electric Cooperative and others seeking rehearing of the commission’s Feb. 15, 2018, ruling that the TOs’ processes for developing supplemental projects fell short of Order 890’s transparency and coordination requirements. FERC also approved PJM’s and the TOs’ compliance filing in response to the February ruling (ER17-179, EL16-71-002).
PJM stakeholders have long complained about the rules involving supplemental projects — transmission expansions or enhancements not required for compliance with PJM system reliability, operational performance or economic criteria. TOs can develop, build and seek reimbursement for such projects without the approval of PJM, which only reviews them to ensure they don’t harm reliability.
The Feb. 15 order approved a proposal to move the TOs’ process for planning supplemental projects from the Operating Agreement to Attachment M-3 of the Tariff but required PJM and the TOs to make changes to the attachment and the OA. (See FERC Orders New Rules for Supplemental Tx Projects in PJM.)
The commission said the rehearing request “largely repeats arguments” made earlier in the docket. “We are not persuaded that the commission erred in the February 15 order, which we believe appropriately responds to these concerns.”
AMP, ODEC and others argued the commission erred in permitting Attachment M-3 because it circumvented the division of filing rights in PJM, including the supermajority vote of the Members Committee required for changes to the Operating Agreement. They also said the commission should have required the TOs to respond to stakeholder comments under the supplemental process.
“Order No. 890 requires that stakeholders be afforded the opportunity to provide meaningful input, and that public utility transmission providers ‘craft a process that allows for a reasonable and meaningful opportunity to meet or otherwise interact meaningfully,’” the commission said. “Its requirements are not so prescriptive as to dictate whether and how the PJM Transmission Owners must respond to that input. While we encourage the PJM Transmission Owners to be as responsive as possible to stakeholder comments, we also realize that not all comments may require answer.”
In addition to AMP and ODEC, those seeking rehearing and challenging the March 19 compliance filing were the Delaware Division of the Public Advocate, PJM Industrial Customer Coalition, Illinois Citizens Utility Board, Office of the People’s Counsel for the District of Columbia and Public Power Association of New Jersey, which FERC named the “Load Group.”
“The Load Group’s requests for various additional provisions go beyond what the commission required in, and constitute requests for rehearing of, the February 15 order,” the commission said. “We therefore find these requests to be outside the scope of the compliance proceeding, and were we to consider them as requests for rehearing, would deny them.”
FERC on Tuesday approved MISO’s plan to replace its retirement notification process with a more general three-year generation suspension period.
MISO’s proposal places all generation owners submitting an Attachment Y retirement notice into a catch-all three-year suspension period, with suspended units maintaining interconnection rights for the full three years unless they formally decide to retire (ER18-1636). Units that do not return to service after three years are presumed retired and their interconnection rights dissolved. The changes became effective July 16, 2018.
| MISO
After FERC issued a July deficiency letter on the proposal, MISO said the new suspension process would still allow it to designate resources seeking suspension as system support resources needed to keep operating for reliability reasons. (See FERC Seeks Details on Proposed MISO Retirement Rules.) The RTO also explained its old suspension process wasn’t working as intended, saying that out of 77 suspensions over the last five years, only eight generators returned to service at the end of the originally designated suspension period.
For modeling purposes, MISO will treat approved suspensions as unavailable resources with no specified date of return service. MISO also said its proposal requires no notice from a generation owner should it want to change its suspension status into a permanent retirement anytime during the three years.
FERC said MISO’s proposal that modeling not anticipate suspended units will return to service “better reflects the inherent uncertainty of planning.”
” … We agree with MISO that its current requirement to provide a return-to-service date in Attachment Y Notices to suspend may at times create an illusion of certainty that does not actually exist,” the commission said.
The 2nd U.S. Circuit Court of Appeals on Thursday upheld New York’s zero-emission credits (ZEC) for nuclear generation, rejecting claims they intrude on FERC jurisdiction (17‐2654‐cv).
“We conclude that the ZEC program is not field preempted, because plaintiffs have failed to identify an impermissible ‘tether’ under Hughes v. Talen Energy Marketing between the ZEC program and wholesale market participation; that the ZEC program is not conflict preempted, because plaintiffs have failed to identify any clear damage to federal goals; and that plaintiffs lack Article III standing as to the dormant Commerce Clause claim.”
In upholding a district court’s dismissal of the complaint by the Electric Power Supply Association and others, the appellate court said its finding was “consistent” with the 7th Circuit’s Sept. 13 ruling upholding Illinois’ own ZEC program. (See 7th Circuit Upholds Ill. ZEC Program.)
EPSA on Thursday asked the 7th Circuit to rehear its ruling, alleging the court had made legal and factual errors. “The panel overlooked or misapprehended three key legal arguments under which appellants would prevail,” EPSA said.
Threading the Needle
The New York Public Service Commission created the ZEC program in August 2016 as part of its Clean Energy Standard (CES), which set a goal of reducing greenhouse gas emissions by 40% by 2030. The PSC said it crafted the program to avoid the issues behind the Supreme Court’s April 2016 ruling in Hughes v. Talen, which voided Maryland regulators’ contract with a natural gas plant as an intrusion into federal jurisdiction over wholesale power markets. (See NY Attempts to Thread Legal Needle with Clean Energy Standard, Nuke Incentives.)
The court said that ZECs, like renewable energy credits (RECs), are certifications of an energy attribute separate from the purchase or sale of wholesale energy. Although the ZEC program “exerts downward pressure on wholesale electricity rates, that incidental effect is insufficient to state a claim for field preemption under the FPA [Federal Power Act],” the court said.
The court said the PSC avoided the defects of the Maryland contract for differences, which required the generator to participate in PJM’s capacity market.
“Plaintiffs point to nothing in the CES Order that requires the ZEC plants to participate in the wholesale market,” the court said. “ … As the district court concluded, a generator’s decision to sell power into the wholesale markets is a business decision that does not give rise to preemption concerns.”
“Until 2019, the ZEC price cannot vary from the social cost of carbon, as determined by a federal interagency workgroup. After 2019, the ZEC price is fixed for two‐year periods, and does not fluctuate during those periods to match the wholesale clearing price,” the court said.
The court also said the ZEC program was permissible under the dual federal/state regulatory system over electricity because it “does not cause clear damage to federal goals.”
The PSC approved the program to prevent the premature retirements of three New York nuclear power plants, Exelon’s FitzPatrick, Ginna and Nine Mile Point.
Nine Mile Point Nuclear Plant | Constellation Energy Nuclear Group
EPSA and the other plaintiffs — the Coalition for Competitive Electricity, Dynegy, Eastern Generation, NRG Energy, Roseton Generating and Selkirk Cogen Partners — claimed they were harmed because the ZEC program allows “favored New York power plants to prevail in interstate competition against” their generation by underbidding them in the wholesale electricity markets.
“If the PSC awarded ZECs in a non‐discriminatory manner to out‐of‐state nuclear plants (as it may do in the future under the terms of the CES order), there would be no abatement in the injury plaintiffs claim to suffer from the general market‐distorting effects of the ZEC program. In short, plaintiffs’ injuries ‘would continue to exist even if the [legislation] were cured’ of the alleged discrimination,” the court said. “Because plaintiffs’ asserted injuries are not traceable to the alleged discrimination against out‐of‐state entities, but (rather) arise from their production of energy using fuels that New York disfavors, they lack Article III standing to challenge the ZEC program.”
Win for RECs?
“The decision is a win for both ongoing state efforts to preserve existing nuclear plants — New Jersey regulators expect to finalize a ZEC program by the end of the year — and long-standing renewable energy policies,” said Ari Peskoe, director of the Electricity Law Initiative at Harvard Law School. “The panel held that renewable energy credits (RECs), instruments that are used for compliance with renewable portfolio standards, are legally indistinguishable from ZECs. Today’s decision thus implicitly concludes that RECs are not preempted under the FPA, an issue which no court has ever squarely addressed.”
CAISO is seeking to extend measures for another year that deal with the continuing threat to electrical reliability posed by limited operations at the Aliso Canyon natural gas storage facility, where a massive release of methane occurred in October 2015.
CAISO is seeking to extend for another year interim market measures designed to deal with gas supply restrictions at the damaged Aliso Canyon facility. | California Governor’s Office of Emergency Services
“Our hope is to be able to keep these measures in place for another 12 months,” Anna McKenna, an assistant general counsel for the ISO, said in a conference call with stakeholders Tuesday.
The provisions include a measure allowing the ISO to enforce constraints on the maximum amount of natural gas that can be burned by gas-fired plants in the areas served by the Southern California Gas and San Diego Gas & Electric. The constraints would be based on limited supply anticipated by CAISO during specific hours.
The provisions also allow CAISO to suspend or limit the ability of scheduling coordinators to submit virtual bids if it’s determined virtual bidding could undermine reliability or grid operations.
Similar provisions have been in place for the past two years to prevent blackouts or grid disruptions caused by the natural gas supply in Southern California being over-taxed.
The current proposal, called Phase 4, would extend the temporary provisions now in place for another year beyond Nov. 30 and Dec. 16, when they are set to expire.
CAISO planned to file its proposal with FERC by Thursday and ask for a 60-day turnaround so the new restrictions are in place when the first set of rules expires at the end of November.
Before the 2015 blowout, Aliso Canyon was the state’s largest natural gas reservoir, and its damaged status poses challenges to generators and regulators alike.
Despite objections from local residents and Los Angeles County officials, SoCalGas resumed injections into the facility in July 2017 to comply with a state directive to maintain sufficient gas inventories to support reliability on the region’s gas and electric systems. (See CPUC OKs Temporary Increase in Aliso Canyon Injections.)
Illinois regulators last week suggested PJM consider ending its capacity market if it continues supporting policies that the state believes discount its generation preferences. [Editor’s Note: An earlier version of this story incorrectly stated that regulators had threatened to leave the RTO.]
The Illinois Commerce Commission convened a Sept. 20 hearing on PJM’s capacity market three weeks before a deadline to respond to a FERC order that rejected both of the RTO’s proposals for revising its capacity market, which sparked a rush to develop alternatives. (See FERC Orders PJM Capacity Market Revamp.)
While several proposals emerged, including one supported by the Illinois Citizens Utility Board, PJM has maintained support for its own plan, which would pair an expanded minimum offer price rule (MOPR) with a two-stage auction that removes subsidized resources and reprices the results.
Already well aware of Illinois’ grievances, PJM staff attending the hearing attempted to explain the RTO’s position.
“We are really trying to make this work,” PJM’s Darlene Phillips said. “We recognize that Illinois and other states have the right to make decisions. We are not trying to fight against those decisions. We are trying to make sure that, at the end of the day, our markets work for the entire region. There are other states that aren’t making those decisions … [and their generators] don’t have the luxury of getting an out-of-market payment.”
Another Way?
PJM’s assurances didn’t sway either the ICC commissioners or the other panelists, largely made up of either environmental advocates or representatives of Exelon, which has two nuclear facilities in Illinois benefiting from a 2016 state law that subsidizes the units with state-funded zero-emission credits. The 7th U.S. Circuit Court of Appeals recently upheld the state’s right to provide the funding.
“What if we throw this capacity market out?” ICC Commissioner John Rosales asked, noting that FERC had already ruled the market unjust. “There’s some rationale we can do it another way.”
He pointed to ERCOT, which doesn’t have a capacity market.
“Is that an option? … Is there something else that we can do? Because the amount of money is uneconomical,” he said. “That’s a lot of money that’s invested in a reserve market that doesn’t seem to be needed most of the periods throughout the year,” Rosales continued. “Understand, there’s times that we’re going to need some help, but you get that [help] from others.”
Jen Tribulski, a PJM attorney, suggested that FERC didn’t intend to do away with PJM’s “capacity market as a whole,” but sought to improve how the market deals with out-of-market payments.
The disagreement came over what is considered a subsidy. Phillips said that “we have to draw a line somewhere. This is not easy.”
However, opponents argued PJM has larger market distortions to address.
“Regulated utilities have the ability to subsidize all of their generation with ratepayer funding, so if you’re going to talk about a market without subsidies, you’ve got to really relook at the whole market. It’s the single biggest market distortion that there is,” said Rob Kelter of the Environmental Law & Policy Center. “When you consider the cost of energy and you don’t consider the cost of environmental externalities, you are creating the biggest distortion you could possibly create. Coal and natural gas pollute.”
“Right now, the proposal on the table is to artificially raise the prices that consumers would be paying to preserve the supremacy of the capacity market,” said Andrew Barbeau of The Accelerate Group. “There’s a certain fealty to the capacity market that we’ve seen in recent years … to use the capacity market to start serving other purposes. It’s always been there to serve as this insurance product. Consumers are paying more and we’re getting less for it, and it’s kind of violating what residents of the state have been pretty consistently demanding, which is that the power be cheaper and cleaner.”
‘Fundamental Disconnect’
Phillips said the market “is doing what it was meant to do when it was put in place” to produce “reliability at the least cost,” but that it didn’t contemplate environmental concerns. She added that she was “not saying there’s not room for improvement.”
“That’s something that states can get together and have a discussion about” in creating a market-based proposal, she said. “You’re getting reliability. You’re getting assurances, not insurance, [but] assurances that three years from our market, three years forward, that we have enough capacity online to make sure the energy needs during that period are met.”
ICC Chairman Brien Sheahan said there is a “fundamental disconnect in PJM’s conception of what ‘accommodate’ is and what ‘mitigate’ is.”
PJM says its proposal accommodates states’ policy decisions, but states argue it instead mitigates their efforts to sponsor preferred technologies.
“You can’t just start doing this kind of line drawing,” he said. “And the end result, I predict, will be if they don’t accommodate, then the states are going to find alternatives. … Legislatures and governors in states that care about climate change and care about environmental policy are not going to bow to how [PJM thinks] they should work.”
ICC Manager Randy Rismiller suggested moving away from capacity markets altogether.
“Energy and ancillary services markets historically have worked quite well. They haven’t been as contentious as capacity markets. This sort of gradual gravitation away from capacity might be a way out of these constant conundrums,” he said.
CUB’s Kristin Munsch urged PJM to “stop trying to separate us, but integrate our preferences into the market.”
“I think PJM in recent years has begun to adjust the construct, a market that we thought was working well, to one that’s no longer reflecting what I think consumers are looking for,” she said.
CAISO moved closer this week to updating its transmission access charge (TAC) structure to include new rules about how to measure transmission usage.
Stakeholders discussed the final draft proposal Monday at CAISO headquarters in Folsom, Calif., with participants also joining by telephone.
The proposed rules are intended to more accurately allocate transmission costs based on current grid conditions to achieve greater efficiency and cost-effectiveness, the ISO contends.
Power lines in Contra Costa County, California | USDA
In particular, the rules would change the current volumetric TAC to a hybrid one that uses historic peak demand data instead of forecasted data.
“It’s kind of a balance we’re trying to strike here,” Chris Devon, CAISO market and infrastructure policy developer, told stakeholders.
The volumetric-only approach is no longer appropriate because of a changing grid, most notably the rise of distributed generation and other distributed energy resources, the ISO and many stakeholders contend. The hybrid approach would help adjust for this new reality so that transmission owners can better recover the costs of building, maintaining and operating transmission facilities, proponents said.
“The proposed hybrid approach is an improvement over the current TAC structure,” the ISO said in its presentation Monday. “[It] captures both volumetric and peak demand functions and reliability benefits provided by the system.”
Planning for the revisions started in April 2017 and has included several stakeholder meetings. The initial straw proposal went through two revisions, with some of the more controversial proposals modified or rejected.
CAISO recently backed off a proposed provision that would have moved the point of measurement for transmission usage away from the end-use customer’s meter to the interface between the transmission and distribution systems to better reflect increased customer reliance on resources directly connected to the distribution network, such as rooftop solar.
“The ISO is willing to revisit the point-of-measurement issue — for purposes of prospectively allocating the costs of future transmission facilities — if state policymakers and regulatory authorities, after careful consideration of the merits and implementation issues, support retail rate changes that provide a transmission cost credit (i.e., relief from retail rate charges for certain new transmission facilities) to load-serving entities that have procured distributed generation resources,” the ISO wrote in the proposal.
The TAC plan still has a way to go before it could be implemented.
A final proposal will likely be submitted to the ISO Board of Governors in the first half of 2019, with board approval coming later next year.
It would then have to be submitted to FERC, with implementation occurring no sooner than 2021 or 2022, according to CAISO planners.
The grid operator previously developed a proposal to allocate transmission costs over an expanded balancing area if the ISO integrates new members from other areas of the West. (See CAISO Floats Latest Cost Allocation Plan for Expanded Balancing Area.) That proposal has been shelved until CAISO expands into other regions.
U.S. Sens. Sheldon Whitehouse (D-R.I.), Jack Reed (D-R.I.), Ed Markey (D-Mass.), Elizabeth Warren (D-Mass.) and Jeanne Shaheen (D-N.H.) joined Sen. Richard Blumenthal (D-Conn.) in a letter urging FERC to reject NEPOOL’s proposal to codify its longstanding closed door policy (ER18-2208).
Richard Blumenthal | Richard Blumenthal
“Residents of New England pay some of the highest electricity rates across the country,” the senators said. “Consumers deserve to be aware of the important decisions that are made that affect their household energy bills and the environment. Such decisions should be transparent and subject to public scrutiny.”
The senators dismissed NEPOOL’s argument that allowing press access would hurt the ability of NEPOOL members to talk candidly, calling it “a claim that is neither supported nor justified. In New England and around the country, it is essential that the deliberation process be kept open to all who are affected by these decisions.”
New England is the only one of the seven U.S. regions served by RTOs or ISOs where the press and public are prohibited from attending stakeholder meetings.
“Although NEPOOL does publicly release documents, including meeting minutes and official records, both in advance and after meetings take place, this cannot be considered a substitute for membership,” the senators said.
They warned that approval of NEPOOL’s proposal “could have significant impact on and set precedent for stakeholder participation in electricity market entities, and not only in New England. Formal exclusion of stakeholders from decision-making in NEPOOL would be in stark contrast to FERC Order 719, which sought to increase and not hinder responsiveness to stakeholders across all RTOs.”
On Sept. 18, a dozen members of the House of Representatives also called on the commission to open the meetings.
Their letter was signed by Rep. Frank Pallone (D-N.J.), the ranking member of the House Energy and Commerce Committee; Rep. Fred Upton (R-Mich.), the chairman of the committee’s Subcommittee on Energy; Rep. Bobby Rush (D-Ill.), the ranking member on the subcommittee; seven of nine members from Massachusetts’ delegation; and one representative each from Rhode Island and Vermont.
Last week, NEPOOL filed a motion to dismissRTO Insider’s protest seeking to open the meetings, saying FERC lacks jurisdiction to force changes (EL18-196). Other intervenors supported RTO Insider’s request that FERC either force a NEPOOL rule change or strip it of its role as ISO-NE’s stakeholder body. (See NEPOOL: FERC Can’t Change Press, Public Ban.)
ERCOT said an “exceptional” response by generators and a lack of extreme temperatures helped it meet record demand this summer without issuing alerts or calling for conservation measures.
ERCOT’s summer performance review said the wholesale market “performed as expected,” with generators responding to higher price signals and making their units available during peak demand periods. It noted the market “is designed to provide financial incentives to encourage market participants to respond appropriately” under tight operating conditions.
The ISO, which manages 90% of the state’s grid, set a new system demand peak of 73.3 GW on July 19, more than 2 GW higher than the previous record set in August 2016. The record high was one of 14 set during the lone period of extreme heat this summer (July 18-23).
Hourly Average Demand, Capacity, and Reserves on 7/19/2018 | Ercot
ERCOT also set a new weekend peak demand of 71.4 GW on July 22.
The summer — which ends Sept. 30 for ERCOT — was the fifth hottest on record across Texas. However, high temperatures were “not as significant or as sustained” as they were during the 2011 record-setter, the ISO said. Temperatures averaged 86.7 degrees F during the summer, with Austin recording 90 days over 100 and Dallas 71 (including 40 consecutive).
Summer Peak Demands Records | Ercot
Real-time system-wide wholesale prices ranged from $33/MWh to $47/MWh between June and August, with a high of $3,125/MWh on June 5. The highest system-wide price for a single settlement interval during July’s extreme weather came on July 18, when prices hit $2,169/MWh.
The highest system-wide day-ahead price was $2,062/MWh on July 23.
The ISO had fewer reliability unit commitments in 2018 compared to last year because market participants made their units available during tight system conditions, according to the review.
Generation outages were also half of what was projected in ERCOT’s final seasonal assessment in April, the grid operator said. (See ERCOT Gains Additional Capacity to Meet Summer Demand.) Outages and de-rates totaled a little over 2 GW during the July 19 peak.
ERCOT entered the summer with a planning reserve margin of 11%, almost half of that in previous years. The tightest operating conditions came on Aug. 18, when two large generators tripped, one just before the day’s peak. The ISO relied on operating reserves to meet demand “with no reliability concerns.”
ERCOT filed the report and accompanying data on Monday afternoon with the Texas Public Utility Commission, which has opened a docket on the summer’s market performance (Project 48511).
The ISO’s staff will also share their findings with stakeholders during the Technical Advisory Committee on Wednesday and the Board of Directors on Oct. 9.
Cheap energy from natural gas plants and renewables claimed another coal victim in Texas last week when American Electric Power announced it will close the Oklaunion Power Station near the Oklahoma border.
AEP, the plant’s operator and majority owner, said it plans to shut down Oklaunion by October 2020, citing concerns that the plant’s production costs are no longer competitive in ERCOT, company spokesman Stan Whiteford said.
Oklaunion Power Station | AEP
The 32-year-old, 650-MW plant is split among four owners in both the ERCOT and SPP grids. AEP Texas owns a 54.69% interest in the plant. The other owners are the Brownsville Public Utilities Board (17.97%) in South Texas, AEP’s Public Service Company of Oklahoma subsidiary (15.62%) and the Oklahoma Municipal Power Authority (11.72%).
The plant accounts for 4.4% of ERCOT’s summer coal capacity. Its retirement will leave the grid operator with 24 operational coal units.
Two of those units, at CPS Energy’s J.T. Deely Power Plant, are currently mothballed and not included in ERCOT’s capacity calculations. The units date back to the late 1970s and have a combined capacity of 871 MW.
CPS Energy’s J.T. Deely | CPS Energy
The San Antonio municipality notified ERCOT in 2013 it was closing Deely permanently by the end of 2018, partly to avoid spending as much as $550 million in environmental retrofits. CPS has said it remains committed to closing the plant, despite the Trump administration’s proposal the roll back the Clean Power Plan.
ERCOT spokeswoman Leslie Sopko said the grid operator has yet to receive an official notification of suspension of operations (NSO) regarding Oklaunion, and has not received an NSO for Deely’s permanent closure.
“AEP has advised us of their plans to close the plant,” Sopko said, noting the retirement will be reflected in ERCOT’s Capacity, Demand and Reserves report when it receives the NSO.
The grid operator still has more than 81 GW of capacity, though its reserve margin slipped to below 11% this year, following last year’s retirements. ERCOT survived record heat during July without any generation shortfalls or resorting to emergency measures.
Imagine a casino where you could produce $548 million in paper profits — or $100 million in losses — with only $600,000 of collateral. That’s essentially what Andrew Kittell and John Bartholomew saw when they began trading financial transmission rights in PJM in 2014, the beginning of a saga that has now spiraled into the largest default in the history of the RTO’s financial markets.
After the default of Tower Research Capital’s Power Edge hedge fund in 2007, FERC ordered an end to collateral-free trading in Order 741. PJM and other RTOs tightened their credit rules as a result.
But the changes weren’t enough to protect PJM against Kittell and Bartholomew’s GreenHat Energy, which purchased a staggering 890 million MWh of FTRs — the largest FTR portfolio in PJM — before the company defaulted in June.
GreenHat listed its address as 826 Orange Avenue, Suite 565 Coronado, Calif. — a UPS store between a nail salon and a RiteAid. | Google
In hindsight, RTO officials should have been wary of Kittell and Bartholomew, who came to FERC’s attention for their roles in J.P. Morgan Ventures Energy Corp.’s (JPMVEC) scheme to manipulate the CAISO and MISO markets between 2010 and 2012.
The GreenHat debacle has led to proposals for additional changes to PJM’s credit policy and questions about the competence and vigilance of RTO staff involved. PJM’s failure to respond promptly to warnings from other FTR traders allowed GreenHat’s $10 million loss in 2017 to grow — leaving other market participants on the hook for as much as $145 million. [Editor’s Note: FERC issued rulings in two FTR dockets on Sept. 25. See update at bottom.]
Here, based on interviews, PJM records and FERC filings, is how it happened, a cautionary tale of inadequate safeguards, opportunistic traders, foot dragging to patch loopholes and, finally, a botched effort to obtain more collateral that may have netted the RTO nothing. GreenHat’s principals did not respond to requests for comments sent to their attorneys, David Gerger of Houston and John N. Estes III of D.C.
Aggressive Purchases
After becoming a PJM member in 2014, GreenHat began amassing its FTR portfolio in the 2015 long-term FTR auction. The company focused most of its activity on positions in the 2018/2019 planning year, securing the rights to 54 million MWh each month. That accounted for 73% of its portfolio. It held another 18 million MWh (24%) for the 2019/20 planning year and 2 million MWh (3%) for the 2020/21 planning year.
Screenshot from Cambridge Energy Solutions’ Day-Ahead Locational Market Clearing Prices Analyzer (DAYZER). PJM has approved about 1,900 sources and sinks for FTR trading, which produce about 6,800 potential FTR paths. | Cambridge Energy Solutions
The company stuck mostly to long-term auctions — which are held three times a year and offer positions for the following year and two more beyond that — buying many of the same paths year over year. Between 2015 and December 2017, GreenHat participated in at least five long-term auctions. The positions seemed like good bets at one time: PJM calculates that in the 2015/2016 planning year, GreenHat’s portfolio would have netted $548 million in profits.
How much did GreenHat pay to amass such a large position? Nothing at the time. It bought on credit, having to post only its initial $600,000 in collateral. Yet there were indications that GreenHat was not well capitalized: On one document, it listed its address as 826 Orange Avenue, Suite 565 Coronado, Calif. — a UPS store between a nail salon and a RiteAid.
GreenHat’s positions, had the company held them, would have remained profitable, though less so, in the 2016/17 and 2017/18 planning years.
But the profitability of GreenHat’s positions was falling as transmission upgrades approved in PJM’s Regional Transmission Expansion Plan to alleviate congestion were added to the FTR model. The implied profits of GreenHat’s portfolio, based on the auction clearing price, were $0 from the December 2015 long-term auction, and they generally decreased with each subsequent auction. By the December 2017 auction, the portfolio appeared to be a $45 million loser.
PJM analysis shows the continuing downward trajectory of GreenHat’s FTR portfolio. | PJM
During those years, GreenHat posted no more collateral than the $600,000 it originally provided as a requirement to trade in PJM’s market. FTR auction participants do not pay the purchase price of FTRs until settlement, when the price is combined with or netted against any congestion revenue credit owed to or by the FTR holder. PJM calculates collateral based on a comparison of the purchase price to the “adjusted FTR historical value,” a three-year, weighted average of the day-ahead congestion previously experienced on the FTR’s path.
The comparison calculations are cumulative, so a negative number for one position can help offset a positive number for another. In that way, GreenHat was able to consistently balance out its portfolio so it could continue acquiring positions without owing collateral.
Screenshot of PJM’s FTR Center shows credit analysis. | PJM
Doubling Down
In April, PJM implemented FERC-approved revisions to its credit policy that factored future transmission upgrades into credit calculations, essentially reducing the expected clearing price on affected paths (ER18-425). The changes would have created a $60 million collateral call for GreenHat’s portfolio, according to PJM, but the rule included a 13-month transition period, which GreenHat would exploit to increase its holdings.
During the transition, GreenHat participated in its only annual FTR auction, for the 2018/2019 planning year, acquiring enough new seemingly winning positions to negate a collateral call. The additional purchases would ultimately add nearly $35 million more in anticipated losses to the company’s portfolio.
“The buying activity in PJM’s PY18/19 auction by [GreenHat] did not appear to be designed to reverse or offset [GreenHat’s losing] positions. Instead, the buying activity was focused on entirely different parts of the PJM network, with a particular focus on buying FTRs with high adjusted FTR historical values (even after accounting for transmission upgrades) relative to their auction clearing prices, which as a result reduced [GreenHat’s] collateral requirements,” DC Energy noted in a FERC complaint seeking immediate changes to PJM’s credit requirements (EL18-170).
FTR obligation as a benefit | PJM
FTR obligation as a liability | PJM
Going to Settlement
GreenHat’s positions started going to settlement with the beginning of planning year 2018/19 on June 1, and PJM issued GreenHat a $1.2 million bill for its initial losses on June 5. By the time PJM declared GreenHat in default on June 21 — after a waiting period required by the Tariff — the anticipated losses had ballooned to $110 million.
At a stakeholder meeting in August, Vitol’s Joe Wadsworth said he used recent market results to determine that it could be upward of $145 million and “is getting worse.”
If accurate, the result would be almost triple the $52 million credit default by Power Edge in 2007, which also triggered credit policy revisions following FERC Order 741.
The order noted that FTRs “have unique risks that distinguish them from other wholesale electric markets” with obligations that can run from a month to a year or more, leaving them dependent “on unforeseeable events, including unplanned outages and unanticipated weather conditions.” An outage can switch a profitable prevailing flow FTR to counterflow, resulting in losses. And “because FTR obligations cannot be terminated prior to [their expiration], losses can mount to the point that the FTR holder goes bankrupt,” FERC said.
PJM’s revisions following Power Edge addressed FTR counterflow risks, while GreenHat’s portfolio is predominantly prevailing-flow positions that will be affected by transmission upgrades.
According to DC Energy, all other RTOs/ISOs — CAISO, ISO-NE, MISO, NYISO, SPP and ERCOT — consider the distribution of historical values monthly, daily or hourly and incorporate the low-valued tail of the distribution (e.g., 75th or 95th percentile). CAISO, NYISO and ERCOT also require upfront payments to prevent market participants from defaulting on prevailing-flow portfolios.
Efforts to Intervene
GreenHat’s riskiness didn’t materialize out of nowhere. DC Energy said it approached PJM in April 2016, months after GreenHat had secured its first positions, about tightening up its credit policies. Specifically, DC Energy pushed for a 5-cent/MWh collateral requirement and worked with PJM to shepherd a proposal through the stakeholder process. PJM argues the proposal wasn’t viable because it would have reversed safeguards put in place after the Power Edge default.
Staff removed the collateral requirement from the proposal in September 2016, and the measure failed to receive stakeholder endorsement at the December meeting of the RTO’s Markets and Reliability Committee — around the time GreenHat was securing positions in its second long-term auction that appeared to be a $2 million loss. (See PJM Credit Adder Fails upon Heightened Review.)
DC Energy met with PJM again in February 2017 and made presentations at stakeholder meetings in March, June and November, and again in January 2018. The campaign eventually bore fruit, with FERC approving the change in FTR credit rules effective April 1 that increased credit requirements on paths on which transmission upgrades are expected (ER18-425).
Annual and long-term auction FTRs | PJM
In July, after winning stakeholders’ endorsement, PJM asked for FERC approval of another revision to the credit rules: imposing a 10-cent/MWh minimum monthly requirement (ER18-2090).
But DC Energy saw that GreenHat’s first bills were coming and attempted to beat the likely default by filing a complaint at FERC on June 4 and requesting it be fast-tracked (EL18-170). DC acknowledged the per-megawatt-hour monthly requirement PJM was likely to file soon, but it said the situation required more expediency and asked FERC to approve its own proposal on credit minimums.
PJM responded on June 25, four days after it declared GreenHat in default, to oppose the proposal and warn that “overly rigid credit requirements can limit market access and constrain competition.” Staff argued that PJM’s new proposals would have imposed a $90 million credit requirement on GreenHat’s portfolio, that GreenHat had always followed PJM’s credit rules and that its purchases seemed like good decisions.
“FTR auction clearing prices when GreenHat acquired the majority of the FTR portfolio on which it has defaulted indicated that GreenHat’s portfolio would be profitable,” staff wrote.
PJM’s Stan Williams said in an affidavit included in the response that staff only became “concerned about” GreenHat’s risk exposure in “early 2017” — despite DC Energy’s claim that it had met with staff to discuss the developing situation roughly a year before.
Vitol, another FTR trader, supported DC Energy’s complaint and blamed PJM staff, saying the RTO “does not appear to have acted in good faith or with any real sense of urgency to address the risk to the market, and may indeed have willfully ignored the mounting risk posed by GreenHat’s market activity or positions.”
Apogee Energy Trading accused RTO staff of being too “focused on trying to prevent ‘another GreenHat’ without addressing the [immediate] GreenHat portfolio problem.”
FTR trader Appian Way criticized PJM in a FERC filing for failing to use “margining” to reflect changes in the market values of FTR portfolios. “Without margining, the moral hazard is that participants double down on losing positions as has been the case with GreenHat Energy.”
Worthless Collateral?
PJM rejected the criticism, citing its efforts to secure additional collateral from GreenHat and the April 2018 rule change shoring up its credit policies. Prior to that, in April 2017, PJM had approached GreenHat to increase its collateral. DC Energy was still promoting its per-megawatt-hour minimum requirements, even though it had failed once to win stakeholder endorsement, and GreenHat had just completed its second long-term auction, where it had appeared successful even though its overall portfolio was running a $2 million loss.
GreenHat offered to sign over the rights to what company representatives said they believed to be $62 million in revenue from selling some of its FTR positions to an undisclosed company in bilateral contracts. PJM agreed to the deal, but it was later told by GreenHat’s counterparty that it had already paid its debts before the company signed the rights over to the RTO.
PJM later admitted that it had not confirmed the amount due prior to accepting the deal. “To avoid a claim of interference with GreenHat’s contractual counterparty and to allow GreenHat the ability to sell down its portfolio, PJM had no choice but to comply with this request,” the RTO said.
GreenHat said it “offered additional collateral when it had no obligation to do so” only because it had no FERC quorum to complain to. The deal was that GreenHat wouldn’t challenge the call, and PJM would make its own evaluation of what the collateral was worth.
However, PJM hasn’t collected anything from the pledge agreement and the RTO now acknowledges “there is now some question whether the pledge agreement will result in monies to PJM.”
DC Energy noted in its complaint that PJM’s Tariff gives staff the “right to ‘require additional collateral as may be deemed reasonably necessary to support current market activity’” and that “such extraordinary measures should be done in unique one-off situations.” PJM staff had referenced that Tariff provision in an email to GreenHat during the collateral call negotiations. But the company said the reforms it proposed were necessary because one-off collateral calls “should not be used to address Tariff deficiencies on a long-term basis.”
But PJM said in a “lessons learned” document presented at the Sept. 17 meeting of its Credit Subcommittee that “there are limited provisions for a discretionary collateral call, and those provisions … are not necessarily applicable in all circumstances.”
Screenshot of PJM’s FTR Center shows market results by participant. | PJM
It recommended a rule change to allow itself “to issue collateral calls that can clearly be applied broadly to a wider range of potential circumstances and all types of market activity.”
Traders with a Past
Andrew Kittell | Andrew Kittel
This isn’t the first time the people behind GreenHat have exploited market flaws at the expense of other participants. Two of the principals at GreenHat, Kittel and Bartholomew, were identified as lieutenants in the 2013 JPMVEC market-manipulation investigation that resulted in a $235 million fine, which remains FERC’s single-highest penalty paid since its records began in 2007 (IN11-8, IN13-5).
FERC said JPMVEC used 12 different bidding strategies to manipulate the energy markets in MISO and CAISO to ensure dispatch and uplift payments for plants that otherwise were often uneconomic. The company had obtained the tolling rights to most of the gas-fired plants from Bear Stearns, which had fallen apart in the 2008 financial collapse.
Kittell also came from Bear Stearns in the deal. Bartholomew was hired from Southern California Edison after submitting a resume that boasted he had “identified a flaw” in CAISO’s markets that he could exploit for “millions of dollars.”
FERC’s Office of Enforcement said that the company violated the commission’s anti-manipulation rule by “intentionally submitting bids … that falsely appeared economic to … market [operation] software but that were intended to, and in almost all cases did, lead CAISO and MISO to pay JPMVEC at rates far above market prices.”
During JP Morgan’s manipulation of CAISO’s Bid Cost Recovery make-whole payments, one trader sent a colleague an email with this photo of a child from Oliver Twist and the subject line, “Please sir, [more] BCR.”
FERC’s enforcement order came on July 30, 2013, but it noted that by June of that year, JPMVEC had effectively sold its interest in the plants by retolling, or subleasing, them to third parties. As of the enforcement action in 2013, Kittell and Bartholomew were still at JPMVEC but working on “transactional activities.” Though named in FERC’s enforcement order, neither was personally fined, as FERC has sometimes done.
FERC spokesperson Craig Cano said the commission doesn’t comment on investigations and would neither confirm nor deny whether GreenHat is being investigated.
PJM refused to divulge when it learned of the connection between GreenHat and JPMVEC. However, staff acknowledged in the “lessons learned” document that “the current credit application may not include all inquiries that may be relevant for PJM to assess the application.”
The document says “additional information should be required … such as whether an applicant or its owners have been the subject of regulatory investigations in the past, whether an applicant has ever had its market-based rate authority suspended or terminated, whether an applicant has ever had its retail supplier license suspended or terminated, etc.”
Sharing the Pain
Per its Tariff, PJM allocates the losses from defaulted portfolios to every entity that is a member as of the default date. The RTO had 992 members on June 21, and 10% of the final bill will be allocated to them on a per capita basis. Those assessments are capped at $10,000 per incident. The remaining losses will be allocated proportionally according to each member’s gross PJM activity over the three months preceding the default.
PJM has sent bills for $42.5 million for GreenHat’s losses in June through August, representing about 18% of the company’s portfolio, with 33 more months of settlements to go. The losses include both settled positions and money the RTO paid market participants to take on the positions before settlement.
In fact, the bids PJM received to take on GreenHat’s prompt-month positions in August were so far above what they’ve actually settled at that the RTO petitioned FERC for emergency waivers of its Tariff requirements so it can plan a better strategy. The first waiver would allow PJM to only offer the prompt month of GreenHat’s positions — the ones that will settle the following month — into its monthly auctions rather than offering all of the defaulted positions. PJM said it would “maximize the likelihood of liquidation of those positions,” as the Tariff requires (ER18-2068).
The liquidations were costing $775,000 per day, PJM calculated, or $12.4 million for the first 16 days of August.
“By contrast, if PJM had allowed GreenHat’s positions to proceed to settlement, actual losses for those same 16 days in the month of August 2018 would have been approximately $2.3 million, consistently less than $500,000 per day, with some days resulting in $0 in losses or even modest profits when they settled,” PJM’s Tim Horger said in an affidavit filed in the docket.
PJM also argues that markets for the prompt month are far more liquid than those for months and years further out.
After receiving stakeholder approval in August, PJM filed a second waiver request to allow all GreenHat positions to go to settlement through Nov. 30 (ER18-2289). Both requests were intended to buy time for PJM stakeholders and staff to find a resolution.
Some PJM members have also touted the potential for using the FTR market to hedge against the GreenHat losses by taking positions to offset the company’s holdings.
Not all members are pleased with the delay, however. Apogee has opposed both waiver requests, arguing that prompt liquidation is better for the market than attempting to mitigate “undesirable consequences … for certain members over others.” As a financial trader, Apogee’s allocation would be relatively limited compared to members who buy, sell and trade in multiple PJM markets daily.
Apogee argues that waiting could allow traders to “front run” the sale of GreenHat’s portfolio by selling any identical positions they have and then buying them back at a discount when the large volume of the FTRs are sold in the subsequent monthly auctions.
“The additional selling pressure from front-runners also is likely to increase and not mitigate the total loss,” Apogee argued.
In July, PJM filed a third waiver request seeking to hold onto $550,000 in collateral posted by Orange Avenue, another FTR trader also managed by Kittell (ER18-1972). Orange joined PJM in February and posted its collateral but never traded. It sought to withdraw and recover its collateral in June, but PJM asked FERC to allow it to hold the money for a year until it can determine the legitimacy of the $62 million Kittell signed over to PJM on behalf of GreenHat.
Solutions
PJM has held several special sessions of the MRC to discuss the situation with stakeholders and analyze 23 proposals for dealing with GreenHat’s portfolio. The suggestions range from letting all the positions go to settlement to the Monitor’s proposal to cancel them so they don’t settle. Apogee proposed allowing market participants to assume their share of the FTRs from the portfolio instead of paying the allocation. Vitol has suggested a separate sealed-bid auction of the portfolio.
“Our recommendations are so this does not spiral into chaos,” DC Energy’s Bruce Bleiweis said at the Sept. 18 session. Liquidation, he said, is “small bites over a period of time to make it manageable.”
Most financial FTR traders are pushing for liquidation, including Apogee’s Kevin Kelley. “I think there’s a lot of scare in the room based on the August results,” he said at the same meeting.
Staff plan to seek stakeholder endorsement at the Sept. 27 MRC meeting for any of six proposals preferred by stakeholders. If a path forward is approved at the subsequent Members Committee meeting, PJM plans to file it for FERC approval to be effective on Dec. 1. That filing would include a request that, if FERC doesn’t approve the endorsed proposal, it extend the current waiver requests until March 1 to avoid reverting back to the status quo of being required to immediately liquidate the positions. If no proposal is approved, PJM expects stakeholders to direct staff to file the extension request by itself.
PJM also announced it plans to introduce problem statements and issue charges in October for both the Credit Subcommittee and the Market Implementation Committee to implement its “lessons learned.” And a proposal to implement a “mark-to-auction” component into the FTR credit requirement is targeted for endorsement by the MRC and MC at their Dec. 6 meetings.
Staff also met with “experts in energy markets and risk management” during a closed-door FTR Risk Management Workshop on Aug. 14. The session identified at least 18 factors contributing to FTR portfolio volatility and determined that the “highest priority recommendation” is to establish FTR credit requirements based on the highest monthly calculation of three components: (1) path-specific congestion incorporating the projected impacts of transmission system changes (approved by FERC and implemented April 1); (2) a minimum volumetric requirement (implemented Sept. 3 subject to refund); (3) or mark-to-auction determinations (currently before the Credit Subcommittee).
The workshop also identified 11 other potential improvements.
UPDATE
On Sept. 25, the commission approved PJM’s proposal to add a 10-cent/MWh collateral requirement on FTR trades, effective Sept. 3 (ER18-2090), and set DC Energy’s complaint for additional rule changes for a paper hearing (EL18-170).
“We agree that the $0.10/MWh minimum credit requirement for FTRs helps address the specific risks to market participants due to large FTR portfolios that may be under-collateralized,” the commission said in the first order. “As PJM will now apply the higher of the credit requirements based on the FTR historic value or the volumetric credit requirement, this proposal helps address risks associated with large FTR portfolios that may continue to be under-collateralized as a result of prior FTR credit policies in PJM. We agree that the price threshold established in the volumetric credit requirement more reasonably balances the need to remedy credit shortfalls for large FTR portfolios while limiting the impact to market participants in its FTR market.”
The commission noted that no one opposed the proposal, although DC Energy contends it doesn’t go far enough.
“We seek to supplement the record in this proceeding,” FERC said in the DC Energy order, “in order to determine whether the Tariff is unjust and unreasonable even with PJM’s new Tariff revision in place.” It set a refund effective date of June 4.
“We cannot determine whether PJM should be required to implement DC Energy’s proposed mark-to-auction collateral requirement and minimum capitalization proposals or whether other changes to the Tariff may be needed. Therefore, we set the complaint for paper hearing procedures.”
The commission asked for briefing on whether large portfolios create a greater financial risk than smaller portfolios; whether the 10-cent/MWh requirement sufficiently mitigates the risk; whether valuing FTRs based on historical performance fails to reflect their volatility; and whether loopholes continue to exist in PJM’s credit policy.
