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.
The RTO’s Nominating Committee has settled on incumbents Phyllis Currie and Mark Johnson along with Minnesota Public Utilities Commission Chair Nancy Lange. If Lange earns enough of the vote, she will replace outgoing Chairman Michael Curran, who has reached the three-term limit.
Madison Gas and Electric’s Megan Wisersky, who holds one of two stakeholder seats on the Nominating Committee, said the committee narrowed a pool of about 30 candidates to two candidates for each of the three open seats, including those held by Currie and Johnson. MISO turned to management firm Russell Reynolds for help assembling a candidate pool.
“The quality of the candidates was exceptional,” Nominating Committee member and Director Baljit Dail said.
“We look forward to another newbie,” Curran added.
MISO Senior Vice President and Secretary Stephen Kozey said polls will be open Sept. 27 to Nov. 2, with a quorum representing 25% of MISO voting members (at least 35 members). Candidates must receive a majority of member support after quorum to be placed on the board. For each candidate listed on the ballot, MISO members can vote “for,” “against” or “withhold.”
“Should a member fail to collect a majority of the voting, the Nominating Committee process would begin all over again,” Kozey said.
MISO membership will also vote during that time on whether to increase the board’s compensation beginning in 2019. The board, after consulting with Russell Reynolds, voted to give itself a $7,000 raise for all directors, raising the current base retainer from $89,000 to $96,000 per year. Currently, directors are paid $116,000, committee chairs get $124,000 and the board chair gets $131,000. The last director pay increase took place in 2016. (See Board OKs Pay Hike, Change to Independence Rules.) The board also voted to increase the chairman’s stipend from $15,000 to $20,000 in 2019.
Curran said increases to director compensation would be frozen for two years should the increase take effect.
Kozey said under MISO’s Transmission Owners Agreement and bylaws, it would take at least two-thirds of the quorum of voting RTO members to reject the compensation increase.
Board election and compensation results will be announced at the Dec. 6 board meeting in Carmel, Ind.
After earlier forecasts of a small year-end overage, MISO is now on track to be $1.2 million under its $265 million expected budget in December.
MISO Chief Financial Officer Melissa Brown said the savings are primarily attributed to delays in planned investments.
The RTO is likewise expected to come in under its capital expense budget, likely spending $28.8 million of the allotted $29.6 million. The decrease comes from deferring some vendor work on its market platform replacement and reclassifying other capital expenses as operating expenses.
MISO staff are proposing a $269.6 million operating budget for 2019, a $4.7 million increase over last year. The RTO, however, is planning for a smaller capital budget, at $27.2 million.
The 2019 budgets include $81.2 million in both operating and capital spending on technology.
The total 2019 budget includes $20.5 million of spending on MISO’s market platform replacement project, broken down into $10.7 million in capital expenses, $4.2 million in operating expenses and $5.6 million dedicated to the salaries and benefits of staff working on the project.
MISO leadership said it will reveal in late 2019 its chosen vendor to construct the new platform. In June, the RTO said preliminary vendor General Electric was months behind schedule on developing the platform, especially on the complex software needed to clear the day-ahead market. (See MISO Platform Replacement Risks Delay, Budget Overrun.)
Curran asked that MISO provide the board updates on its preferred vendor and reasoning before releasing the information next year.
MISO Reviewing FTR Process
After PJM experienced a major default in its financial transmission rights market, MISO is ramping up an ongoing review of its own FTR market.
Officials said they began the review in 2017 and will continue to look for any weaknesses in its process. The evaluation is expected to extend into next year, and MISO said it plans to bring results of the evaluation to stakeholders.
Brown said staff are looking at other RTOs’ practices to identify the best combination of procedures.
FERC filings indicate PJM’s financial fallout from the incident that began with GreenHat Energy’s $1.2 million FTR default might become as high as $110 million. (See PJM Reeling from Major FTR Default.)
But MISO last week said its FTR market differs from PJM’s in one key way that may protect it against a significant default: MISO does not net auction bid prices with estimated congestion credit value. MISO said the netting difference results in a conservative credit calculation and higher collateral, preventing “thinly capitalized” parties from buying large portfolios.
“We believe this is a key component for minimizing the magnitude of a default,” MISO said.
Brown said bid prices in MISO are required to be collateralized.
“So you’ve got to bring the cash to play the game,” she told the board.
MISO also said it limits FTR terms to one year, while PJM allows rights for up to four years. It additionally pointed out that it estimates the value of transmission congestion more frequently than PJM, updating congestion estimates monthly rather than once per year.
In response to a question from Director Barbara Krumsiek about whether GreenHat could resurface to apply to operate in MISO, Brown said the screening process for credit worthiness would most likely exclude it early in the process.
Directors asked if there was a downside to being more conservative in its FTR market requirements.
Brown said MISO’s collateral requirment protects the membership class, not MISO, because the costs of a default would be passed on to members.
“I’m on the conservative side, just so we’re clear,” Director Currie said.
Director Thomas Rainwater said it appeared that MISO’s credit policy hasn’t diminished “robust” FTR market activity.
ISO-NE on Thursday asked FERC to terminate the capacity supply obligation of Invenergy’s delayed 485-MW Clear River Energy Center Unit 1 combined cycle plant in Burrillville, R.I. (ER18-2457).
The RTO said it was exercising its right to terminate the CSO because the plant will not be operating in time for the beginning of the capacity commitment year beginning June 1, 2019.
Clear River Energy Center Rendering | Invenergy
Unit 1 obtained the CSO in Forward Capacity Auction 10, held in February 2016, but its commercial operation date is now scheduled later than June 1, 2021. Invenergy has covered the plant’s CSO for the capacity commitment periods beginning in 2019 and 2020.
Chicago-based Invenergy has been attempting since 2015 to get a construction permit for the plant from the Rhode Island Energy Facilities Siting Board (Docket No. SB-2015-06), a process delayed by opposition to the plant itself, the environmental sensitivity of the proposed site and the developer’s plans to secure extra water for operations.
On Sept. 21, the town of Burrillville asked the siting board to reject the advisory opinion submitted by the state’s Public Utilities Commission in favor of the project. Town Manager Michael C. Wood posted news of the RTO’s termination filing on the town’s website: “No doubt this is a big setback for Invenergy. Burrillville will thoroughly evaluate this action by ISO-NE, but we are not underestimating Invenergy.”
Location of Clear River Energy Center | Invenergy
Last November, ISO-NE barred Unit 2 from offering into February 2018’s FCA 12 because of the permitting delays. (See ISO-NE Bars Invenergy Plant from FCA 12.)
If the commission accepts ISO-NE’s filing, the RTO said it “will terminate the CSO, draw down the financial assurance that Invenergy provided for Clear River Unit 1’s CSO and will remove the resource’s qualified capacity, which will render it ineligible to participate in the upcoming FCA 13 to be held in February 2019.”
The RTO asked the commission to issue an order within 60 days of its filing, arguing that the grid operator and market participants “need certainty on the status of this resource” prior to FCA 13.
WINDSOR LOCKS, Conn. — Climate change and the key role of heating and cooling improvements for energy efficiency were the hot topics of discussion among consumer advocates, state regulators and industry professionals attending a meeting of ISO-NE’s Consumer Liaison Group on Thursday.
Combined residential, commercial and industrial building heating accounts for about 40% of CO2 emissions in New England, followed by transportation at about 35% and the electric sector at 23%.
“Those are the big three wedges when you want to actually achieve the economy-wide greenhouse gas goals that we now have in statute,” said Commissioner Robert Klee of Connecticut’s Department of Energy and Environmental Protection.
The state’s Global Warming Solutions Act calls for reducing GHG emissions to 10% below 1990 levels by January 2020 and 80% below 2001 levels by 2050, and it was recently amended to reduce emissions to 45% below 2001 levels by 2030.
The state’s renewable portfolio standard and the Regional Greenhouse Gas Initiative have driven down emissions, “and Connecticut has just doubled down on that with legislation to make our RPS 40% Class I renewables by 2030,” Klee said.
The “new normal” of stronger and more frequent storms is also a challenge for planners and predictors, Klee said. “Those storms would normally happen years or decades apart, but Eversource [Energy] reported in a period of 16 months having four of the company’s 10 most devastating storms ever … [which] translates into [affecting] our rates and how much we’re all going to be paying for this.”
Joseph Rosenthal, principal attorney for Connecticut’s Office of Consumer Counsel, moderated a panel on electrification of heating.
From 2013 to 2015, the state was promoting the use of natural gas “to find the right parameters to give consumers choice about whether to stay with oil or switch to natural gas and what kind of subsidization we would offer for that,” Rosenthal said.
Now Connecticut is moving into a new phase, talking about electrifying of the heating sector, he said.
DEEP Deputy Commissioner for Energy Mary Sotos said climate change drives the move to electrify heating to reduce GHG emissions, but the use of lower carbon content biofuels also provides opportunities to improve energy efficiency.
“One limitation on reaching the state’s GHG emissions target is how we measure biofuel,” Sotos said, noting that the advantages of biofuel lie in reduced emissions over the lifecycle, while the EPA tools her state uses only reduce emissions at the point of combustion.
“In the near term, unless we change those methodologies significantly, we wouldn’t necessarily get to claim credit for any changes made there,” she said.
Sotos’ remarks set the table for Chris Herb, president of the Connecticut Energy Marketers Association, a statewide group of fuel oil dealers, who said, “Forget everything you think you know about heating oil.”
On July 1, all New England states mandated the use of ultra-low sulfur heating oil, with a maximum sulfur content of 15 ppm, a 97% reduction from the previous standard, he said. The new fuels, mixed with 7% biodiesel on average, mean particulate emissions are reduced by 80%, nitrous oxide by 10% and CO2 by 2%.
With biodiesel added, heating oil is no longer the fuel that people are used to, Herb said.
ULSHO/bioblend CO2e reduction versus natural gas over a 20-Year atmospheric lifetime. | National Oilheat Research Alliance
“It’s cleaner than natural gas,” Herb said, showing a slide comparing the 20-year atmospheric lifecycles of natural gas versus ultra-low sulfur heating oil, which his trade group is trying to rebrand as “Bioheat.”
Ronald Araujo, energy efficiency manager for Eversource, said heat pumps provide excellent benefits, given the right situation.
“Ground source heat pumps are very efficient,” Araujo said. “It doesn’t generate heat — it moves heat from place to place — but one disadvantage is it needs some external source to work with.”
Ground source heat pumps are more efficient than air source heat pumps because the temperature of the ground is relatively stable (about 50 degrees Fahrenheit), while the air temperature in New England can range from below zero to 100 with high humidity, either of which compromise efficiency.
“The reason heat pumps are so important is that they reduce emissions. They reduce emissions today, and they will also do it as the electricity sector continues to get cleaner,” said Emily Lewis O’Brien, Acadia Center senior policy analyst. “This is an important part of the equation … but you can’t do it with heat pumps alone.”
O’Brien emphasized that in order to meet renewable energy goals, it would be relatively “simple” to bring all six states in New England, plus New York, into matching best practices in every area, from electric vehicle promotion, to solar development, to heating electrification and energy efficiency.
Anne George, ISO-NE vice president for external affairs, highlighted recent developments at the RTO, particularly regarding fuel security and the issue of the difficulty of obtaining natural gas supplies during the region’s winter peak.
FERC in July tentatively accepted a cost-of-service agreement between ISO-NE and Exelon for Mystic Generating Station Units 8 and 9, ordering an expedited hearing process on unresolved issues related to cost justification (ER18-1639). The agreement would allow the gas-fired units in Massachusetts an annual fixed revenue requirement of almost $219 million for capacity commitment period 2022/23 and nearly $187 million for 2023/24. (See FERC Advances Mystic Cost-of-Service Agreement.)
“They did agree with how we were approaching the fuel security risk analysis, but they did not go along with us doing this outside of our typical Tariff language,” George said.
Elizabeth Mahony, of the Massachusetts attorney general’s office, spoke for her boss, Deputy Chief of the Energy and Environment Bureau — and CLG Coordinating Committee Chair — Rebecca Tepper, who was busy dealing with issues related to the multiple gas line explosions in the Merrimack Valley near Boston the previous week.
Mahony highlighted the election of a new Coordinating Committee at the next CLG meeting, to be held in Boston on Dec. 6. “Any CLG member who is an electricity end user, or directly represents ratepayers, or is a member of a consumer organization, or is a government consumer or ratepayer advocate is eligible to serve on the Coordinating Committee,” she said.
FERC on Thursday rejected a request by developers of a proposed $2 billion pumped storage project for a declaratory order entitling it to cost-based rate recovery as a transmission asset in CAISO.
The commission sided with CAISO and the California Public Utilities Commission, which had argued that Nevada Hydro’s petition for its Lake Elsinore Advanced Pumped Storage (LEAPS) project was an end run around the ISO’s transmission planning process (TPP) (EL18-131).
Lake Elsinore | City of Lake Elsinore
“We dismiss Nevada Hydro’s petition and find that a request to designate LEAPS as a transmission facility is premature at this time,” FERC wrote. “LEAPS has not been studied in the CAISO TPP to determine whether it addresses a transmission need identified through that process, and, if such a need were met, how the facility would be operated. Absent such information, the commission cannot make a reasoned decision on whether LEAPS is a transmission project and thus eligible for cost recovery under the [transmission access charge].”
CAISO said FERC should not accept Nevada Hydro’s analysis that LEAPS is a cost-effective solution to transmission planning needs, noting that the company’s benefits study relied heavily on revenues from market-based services such as energy market sales, regulation, load following, capacity, spinning and ramping. The CPUC said it is unlikely that pumped storage will be the most cost-efficient means of meeting reliability, grid integration or greenhouse gas reduction targets between now and 2030.
The $2 billion LEAPS project, which entered CAISO’s interconnection queue in 2005, has had a long and controversial history, with local governments and many residents opposed to its construction on the natural 3,000-acre Lake Elsinore, adjacent to the Cleveland National Forest in Southern California’s Riverside County.
This is the second time Nevada Hydro has failed to obtain FERC approval to advance the project. In the 2008 Nevada Hydro case, the commission rejected a request that CAISO assume operational control over the facility and found that the developers failed to show why it should be treated differently from other pumped hydro facilities that had not been granted rolled-in transmission pricing.
In seeking the declaratory order, Nevada Hydro said it, not CAISO, would maintain operational responsibility for LEAPS.
But the commission said that change did not entitle the project to circumvent the ISO’s planning process.
“Requiring LEAPS to be reviewed through the CAISO TPP is consistent with the commission’s policy that regional transmission planning processes should identify transmission needs and solutions in a coordinated, nondiscriminatory process that is open to all interested stakeholders,” the commission said. “We note that CAISO has committed to studying LEAPS as a transmission proposal, both as a means to address reliability needs (if it is submitted in an appropriate request window of CAISO’s TPP and if the proposal specifies the CAISO-identified reliability constraints the project could mitigate), and as an economic planning study request.”
The project would include 500-MW of pumped storage, the Talega-Escondido/Valley-Serrano 500-kV Interconnect and a 30-mile line to transmission systems owned by Southern California Edison and San Diego Gas & Electric. Its hydroelectric license application is pending before FERC (P-14227-003).
FERC on Thursday affirmed an administrative law judge’s decision to assign a Minnesota city’s portion of the 345-kV Hampton-North Rochester line (H-NR) to Northern States Power’s pricing zone, rejecting arguments by NSP parent Xcel Energy (ER14-2154-006, ER15-277-005).
The H-NR line was completed in September 2016 as part of the Hampton-Rochester-La Crosse (HRL) transmission project into Wisconsin. The city of Rochester, Minn., through its Rochester Public Utilities (RPU) municipal utility, owns 14.7% of the line; NSP, Southern Minnesota Municipal Power Agency (SMMPA) and Dairyland Power Cooperative are co-owners, at 49.5%, 23.4% and 12.4%, respectively.
The line was included in MISO’s 2008 Transmission Expansion Plan, and the RTO asked FERC in 2014 to add RPU as a transmission owner in NSP’s zone, where the line is located, enabling the city to receive its annual transmission revenue requirement (ATRR) for the line from the zone.
MISO’s Tariff specifies that within each zone, transmission rates are based on the sum of the revenue requirements for facilities “located within that pricing zone.” Xcel argued that the language did not refer to the facilities’ physical locations, but rather the zones the facilities’ ATRRs are “allocated” to for ratemaking purposes. The company pointed out that the word “physically” does not precede the word “located” in the language. Thus, Xcel argued, the Tariff does not mandate that H-NR should allocated to NSP’s zone.
In his initial decision in May 2017, ALJ David H. Coffman found this unpersuasive, pointing to the dictionary definition of “located.”
“The plain meanings of the terms ‘located’ and ‘allocated’ are not remotely similar,” he wrote.
Xcel took exception to the ALJ using dictionary definitions to support his conclusions. But the commission said Coffman was merely using them as evidence of common sense interpretation of the words.
“We are unpersuaded by arguments seeking to differentiate the use of the word ‘located’ in different contexts with respect to the interpretation of” the Tariff, FERC said. “Such arguments stray from the ordinary meaning of the word and also introduce additional problems, notably different interpretations of the word ‘zones’ with respect to the location of load and the location of transmission facilities. …
“Transmission facilities are not ethereal concepts but fixtures that cannot be moved from zone to zone,” FERC added. “Accordingly, given this context, interpreting the word ‘located’ as ‘existing in a particular place’ is logical.”
Xcel also argued that because Dairyland was allowed to allocate its ATRR for both H-NR and HRL to its own zone, where its load is located, RPU’s ATRR need not be allocated to NSP’s zone. Rather, it could have been allocated to SMMPA’s zone, where RPU’s transmission facilities and load are located.
The ALJ, however, noted that the MISO Tariff allows an exception if the TOs agree upon a different allocation and FERC approves the agreement, as occurred in February 2017 for HRL. (See FERC OKs Settlement, Opens Docket in Dispute over Minn.-Wis. Tx. Project.) That agreement excluded the ATRR allocation for H-NR, which could not be resolved at the time.
JPZ Agreement Dispute
In a related order, FERC ended its examination of the joint pricing zone (JPZ) agreement among TOs in NSP’s zone, after NSP added RPU as a party to the agreement pending the resolution of the ATRR dispute (EL17-44). NSP had balked at adding RPU even after FERC approved it as a MISO TO. The commission had warned in February 2017, when it began its investigation, that revisions to the MISO Tariff or Transmission Owners Agreement (TOA) could be necessary to prevent such exclusions in the future.
Under the TOA, MISO distributes revenue to each JPZ’s host TO, which then distributes it among each TO in its zone. The RTO had been distributing revenue to NSP based on RPU’s approval as a TO in the zone, but because NSP had not added RPU to the agreement, the company was withholding the city’s revenue.
While RPU acknowledged that its situation had been resolved, it told FERC that the TOA gives host TOs “the opportunity to leverage the need for a JPZ agreement against a new, typically smaller, transmission owner seeking to recover some or all of its transmission revenue requirement from that zone.”
“This leverage is often coupled with claims of undue cost shifts and various allegations of unjust and unreasonable rate impacts or cost allocations to make it difficult for a smaller transmission owner such as RPU to integrate into MISO,” RPU said.
FERC disagreed. “There is neither evidence that such denial, or use of that threat to affect the terms of cost allocation, is widespread, nor evidence that the host transmission owner responsibilities have either precluded new transmission owners from receiving their respective ATRRs that have been accepted by the commission or would have a chilling effect on new transmission owners’ interest in joining MISO, as RPU suggests.”
The commission, however, reiterated that “a JPZ agreement should reflect commission-accepted transmission rates. … Therefore, any dispute associated with a new transmission owner’s ATRR should not delay the filing of a JPZ agreement to include a new transmission owner to the zone.”
Chairman Kevin McIntyre recused himself from both orders.
