The Michigan Public Service Commission wants federal regulators to force MISO to turn over a study used to identify areas that require the operation of system support resources (SSR) in the state’s Upper Peninsula.
The load-shed study is “essential” to determining whether MISO’s analysis accurately identifies the local balancing authorities (LBA) that require the SSR units and — if not — how it should be modified to do so, the Michigan PSC said in a filing to the Federal Energy Regulatory Commission (ER14-2952).
In 2014, the Wisconsin Public Service Commission complained to FERC that Wisconsin ratepayers would pay a disproportionate share of SSR costs (ER14-2860, ER14-2862). FERC agreed, and MISO responded in September with revised rate schedules that shifted the costs of the Presque Isle, White Pine and Escanaba SSR units more heavily to Michigan.
Michigan regulators are protesting MISO’s allocation of SSR costs on the basis of the reduced LBA boundaries created by Wisconsin Electric Power Co. (WEPCo) as a result of Wisconsin’s challenge.
Michigan has argued that WEPCo’s LBA boundary changes “produce an unduly discriminatory and disproportionate allocation” of SSR costs.
As examples it cited Cloverland Electric Cooperative, whose SSR costs are estimated to rise by 800%, from $2.6 million to $21.9 million, and WEPCo’s load in the Michigan U.P., which the PSC says will increase by 1,000%, from $7 million to $70 million.
The Michigan PSC said it wants FERC to reject the use of WEPCo’s modified LBA boundaries to assign cost responsibility.
With the study data in hand, the PSC said, it could not only demonstrate the inaccuracy of MISO’s “optimal” load-shed study in identifying the load-serving entities that require SSR units, but also demonstrate the larger area of LSE loads that benefit from operation of the units at issue.
MISO’s Dec. 17 response to a FERC deficiency notice described the load-shed study as based on “optimal contingents” designed to “minimize” the volume of load identified as needing the SSR unit. “MISO admits that the impact area identified in the load-shed study ‘is not an all-inclusive identification of load that can reasonably be expected to benefit under every circumstance,’” the Michigan PSC wrote.
After reviewing the response, the PSC said it asked MISO for a copy of the unredacted load-shed study. MISO refused, the PSC said, saying it was only available to MISO staff and transmission owners.
“The Michigan PSC has reason to believe that the ‘optimal’ load-shed study does not accurately identify load that requires operation of the SSR units,” the PSC said. “For this reason, the Michigan PSC desires to conduct alternate studies that are designed to identify loads that require operation of the SSR units under more realistic conditions.”
Presque Isle Deal
Regardless of how the PSC’s request plays out at FERC, Michigan ratepayers may get some relief as a result of Upper Peninsula Power Co.’s agreement to purchase Wisconsin Energy’s Presque Isle generator. UPPCO said last month it would “step into” the existing rates but eliminate the SSR agreement, relieving U.P. ratepayers of its $97 million annual cost. (See Sale Would End SSR, Clear Way for WE-Integrys Deal.)
ISO-NE opened its ninth Forward Capacity Auction yesterday amid expectations of high prices as the region deals with plant retirements and tight natural gas supplies due to inadequate infrastructure. Results from the auction are expected this week or next.
Last year, for the first time, the auction failed to clear as much capacity as ISO-NE sought, falling 143 MW short of the 33,855-MW requirement. ISO-NE is seeking more than 34,000 MW for delivery year 2018/19, 334 MW more than last year’s requirement.
Revenues from FCA 8 totaled $3.05 billion, a 72% jump from 2009’s previous high of $1.77 billion and nearly triple 2013’s $1.06 billion.
FCA 9 the Peak for Prices?
Analysts for UBS Securities released a report yesterday predicting prices will rise higher in this week’s auction, perhaps reaching $11 to $15/kW-month in southeastern Massachusetts and Rhode Island.
The analysts said prices could be limited by new entrants within the RTO or a rebound in transmission imports following a reduction last year.
In either event, they predict new plant construction and possible expansions at existing sites in the constrained Massachusetts market could send prices crashing in FCA 10 next year. “We suspect this is the top of the market for this region, with prices reaching their highs — pushing down prices for future years,” they wrote.
Christopher Tumure, an analyst at JP Morgan, said yesterday the he expects “a bit of an uptick” in prices.
“On the supply side, much of the new generation has already been bid into recent auctions, so we don’t see much change there. On the demand side, there’s about a 300-MW increase year-over-year.”
Two new developments may partially offset each other, he said.
“One of the changes this year is the Pay-for-Performance [program], which may increase prices as it affects the bidding behavior. Another change is the switch to the sloped demand curve instead of a vertical, and that’s not necessarily a good thing for prices.”
NRG Sees Gains
Last month, NRG executives told the company’s annual investors meeting that they expect $1.445 billion in 2018/19 capacity revenue from ISO-NE and PJM, a $565 million increase over 2017/18.
Since FCA 8, the region has lost the Salem Harbor Generating Station in Massachusetts and the Vermont Yankee nuclear plant to retirement. Also unavailable in FCA 9 will be the Brayton Point Generating Station in Massachusetts, which is set to close in 2017. In a recent media briefing, ISO-NE CEO Gordon van Welie said New England will lose about 3,500 MW of generating resources over the next few years.
ISO-NE’s informational filing for 2018/19, which the Federal Energy Regulatory Commission accepted Jan. 16, shows an installed capacity requirement of 35,142 MW (ER15-328). After accounting for 953 MW of Hydro Quebec Interconnection Capability Credits, the RTO seeks to procure 34,189 MW.
Qualified to compete in the auction are 41,102 MW — 8,547 MW of new resources and 32,555 MW of existing resources.
ISO-NE will model four capacity zones in FCA 9:
Southeastern Massachusetts/Rhode Island (SEMA/RI);
Connecticut;
Northeastern Massachusetts/Boston (NEMA/Boston); and
Rest of Pool (Maine, Western/Central Massachusetts, New Hampshire and Vermont).
ISO-NE determined that SEMA/RI will be modeled as import-constrained in this year’s auction, in addition to Connecticut and NEMA/Boston, which were both modeled as import-constrained last year.
SEMA/RI wasn’t modeled last year, when the four zones were Maine (export-constrained), NEMA/Boston (import-constrained), Connecticut (import-constrained), and Rest-of-Pool.
This year will be the first auction in which ISO-NE will adopt a sloped demand curve, as is used in PJM. FERC ordered the change, which is intended to reduce price volatility, following the shortfall in FCA 8.
Demand Response is In
The New England Power Generators Association had asked FERC to disqualify demand response from participation, citing the D.C. Circuit Court of Appeals ruling voiding FERC’s jurisdiction over DR pricing in the energy markets (Electric Power Supply Association v. Federal Energy Regulatory Commission).
[EDITOR’S NOTE: An earlier version of this story incorrectly said that SEMA/RI was modeled as an import-constrained zone in FCA 8. SEMA/RI was not modeled in last year’s auction.]
CARMEL, IND. — Planning Advisory Committee members had plenty of questions last week as MISO officials presented their proposed scenarios for the 2016 Transmission Expansion Plan.
Stakeholders questioned fuel and generation price forecasts and assumptions about future penetration of renewable resources and the role of energy efficiency.
A stakeholder for EDF Renewable Energy questioned the assumptions on the costs of installing new wind capacity, challenging data from Lazard and the Energy Information Administration’s Annual Energy Outlook that estimated current capital costs at $1,800 to about $2,000/kW.
“These costs seem extremely high,” he said. The real cost “is probably close to half these values.”
Jason Schmidt of Xcel Energy questioned why MISO planned to eliminate a future scenario that assumes an increase in state renewable portfolio standards. The proposed base case assumes only enough wind, solar and energy efficiency to meet state standards. “We just submitted a resource plan in which we doubled our wind [capacity] and achieve 10% solar by 2030,” Schmidt said.
Sean Brady, of wind trade group Wind on the Wires, said he shares Xcel’s concern about modeling of renewables. “It’s a departure from what we’ve done in the past,” he said.
MISO’s David Van Beek said “there wasn’t a lot of support” among stakeholders for significantly higher targets, particularly in MISO South, where Louisiana, Mississippi and Arkansas have no RPS.
MISO officials agreed to seek additional information from Bentek about the assumptions in its gas price forecasts.
Members also debated how to model age-related coal retirements.
The baseline assumes 12 GW of coal retirements by 2016 due to the Environmental Protection Agency’s Mercury and Air Toxics Standards (MATS), with another 14 to 20 GW resulting from the Clean Power Plan, depending on regional or sub-regional compliance.
Including the projected 3 to 12 GW of age-related coal retirements leaves all non-business-as-usual futures with high retirements. If age-related retirements are excluded “more balanced retirements can be studied,” MISO said.
Feedback on MISO’s proposed assumptions is due Feb. 11. The RTO will present its final proposals for assumptions and scenarios at the Feb. 18 PAC. The committee will take an advisory vote on the proposal via email or on a conference call after the 18th.
Order 1000 Interregional Compliance Filing
MISO said it expects to make a joint compliance filing with PJM in response to the Federal Energy Regulatory Commission’s December order finding that they only partially complied with the requirements of Order 1000.
The commission ordered the RTOs to modify their cost allocation method for cross-border transmission projects and develop identical language in their Tariffs to describe their interregional transmission coordination procedures (ER13-1944). (See FERC Begins ‘Next Step’ on Order 1000: Interregional Filings.)
At the Regional Expansion Criteria and Benefits Task Force meeting Jan. 29, there was agreement that MISO will have joint stakeholder meetings with PJM to discuss the filing, MISO’s Jesse Moser said.
First Interconnection Request for Battery Storage
Xcel Energy’s Randall Oye, chair of the Interconnection Process Task Force, told PAC members that MISO has received its first interconnection request for battery storage and will work with stakeholders to develop a process for analyzing such requests.
In a meeting of the task force last month, Oye gave a briefing on how California is processing storage interconnections. CAISO received more than 2,000 MW of storage applications in its April 2014 study cycle in response to California law requiring 1,325 MW of storage in service by 2024, according to Oye’s presentation.
Change to Transmission Developer Prequalification Deadline
MISO has changed the deadline for transmission developers to provide the RTO audited financial statements as part of the prequalification process for Order 1000 competitions. The date was changed to May 31 from March 31 after some companies said the March date was too early based on their annual accounting schedules.
Two of Astoria Generating Station’s five units were placed in mothball status in 2012, reducing its capacity from 1,335 MW to 957 MW.
The Federal Energy Regulatory Commission said it has more questions for NYISO before considering proposed revisions to its rules for retired and mothballed generators.
FERC last week sent NYISO a deficiency letter (ER14-2518) listing questions about the ISO’s July 2014 proposal, which would allow it to terminate a generator’s eligibility to participate in the Installed Capacity (ICAP) market after six months in a forced outage if repairs have not been started.
The proposal also would add Tariff definitions of the terms “mothball outage” and “retired.”
The Independent Power Producers of New York supported the six-month rule for participating in the ICAP market. However, it said FERC should reject a requirement that generators on outage respond to reliability needs by returning to service or making their interconnection points available. The association said the requirement would deny generators rights they earned in interconnection agreements with transmission owners.
Responding to the objections, NYISO said in September that “Any modification to, or termination of, an existing interconnection agreement … will continue to be subject to the terms and conditions of the underlying agreements.”
On Jan. 29, FERC’s Office of Energy Market Regulation gave the ISO 14 days to reply to additional questions, including whether it intends to apply its definition of “retired” generators to those with existing interconnection agreements. FERC also asked whether the ISO could unilaterally terminate the interconnection agreements of units in retired status.
Scorecard of frequency response performance for generators in the MISO footprint. Scores of five and above are “problematic,” MISO says. (Click to zoom.)
CARMEL, IND. — MISO has begun collecting data from local balancing authorities in preparation for the North American Electric Reliability Corp.’s new frequency response standard (BAL-003-1).
NERC’s rule is intended to ensure sufficient frequency response from balancing authorities to control interconnection frequency. It also sets consistent methods for measuring frequency response and determining frequency bias settings.
The “generator scorecards” that LBAs are completing cover the period Dec. 1, 2013, through Oct. 31, 2014. MISO’s Terry Bilke presented the results to date to the Reliability Subcommittee, including a histogram showing generator results on a scale of zero to seven. (See chart.) “Anything five and above is problematic,” he said.
Bilke said MISO will work with LBAs and generators to boost governor response where necessary.
The frequency bias setting requirement takes effect April 1. By April 1, 2016, balancing authorities will be required to achieve an annual frequency response measure (FRM) “equal to or more negative” than its frequency response obligation.
Operations Working Group Charter, Management Plan OK’d
Members endorsed the 2015 charter and management plan for the Operations Working Group. There were no substantive changes from 2014, according to chair Ray McCausland of Ameren.
MISO Readies for GMD Rule
Alliant’s Will Behnke, chair of the Emergency Preparedness / Power System Restoration Working Group, briefed members on MISO’s preparation for NERC’s Geomagnetic Disturbance Operations Standard (EOP-010-1), which takes effect April 1.
“We’re ready,” Behnke said.
The standard requires Reliability Coordinators to review the geomagnetic disturbance (GMD) operating procedures or processes of transmission operators (TOPs) within their areas to mitigate the effect of GMDs on the grid.
TOPs must submit a worksheet to MISO 30 days before their GMD operating procedure becomes effective or is revised.
Performance on Real-Time Operations Drills Improving
Local balancing authorities and market participants have improved their performance on monthly drills of real-time operations processes, with more than 80% successfully completing them, MISO’s Danielle Logsdon told members.
Logsdon said that is a marked improvement from the prior success rate of 60%. Performance on the XML drill is “close to 100%,” Logsdon said.
Distributed ICCP Project Extended
MISO said it doesn’t expect to complete its distributed ICCP project until the first quarter of 2016.
MISO’s Arijit Bhowmik told members the RTO expects to complete migration of 70% of the internal links to the new systems by the end of this year. The project, announced last year, was originally scheduled to be complete this August.
MISO’s 2015 Summer Coordinated Seasonal Transmission Assessment will add voltage stability analyses of the Amite South HV Interface and imports in Southwest Michigan in addition to those previously done on the Minnesota Wisconsin Export Interface (MWEX), DSG HV Interface and MISO South’s Western Critical Interface.
ICCP (Inter-Control Center Communications Protocol) is MISO’s real-time data source, providing visibility into the grid and allowing four-second dispatch of generation. The project will spread members across multiple ICCP nodes, reducing the impact of a single failure.
Summer Seasonal Assessment Takes a Closer Look at Louisiana
The 2015 Summer Coordinated Seasonal Transmission Assessment will include a reactive reserves analysis of the Baton Rouge area for the first time, MISO’s Scott Goodwin told members.
Also new will be a voltage stability analysis for the Amite South HV Interface and Southwest Michigan imports.
The CSA is intended to inform operators of potential marginal system conditions expected during the upcoming summer peak and evaluate various stressed conditions, including second contingencies.
The analysis will begin this month, with a draft report posted for review April 24 and the final report expected May 29.
CARMEL, IND. — MISO transmission developers cried foul last week over Entergy’s proposed $187 million transmission upgrade near Lake Charles, La., saying the company’s request for expedited approval is denying them a chance to compete for the project.
Entergy Gulf States Louisiana filed the request with MISO on Dec. 15, saying it was in response to a system need identified on Dec. 1.
The company asked that the request be treated as an out-of-cycle project and not as part of the normal MISO Transmission Expansion Planning (MTEP) process. “Due to major industrial expansion projects ongoing in the Lake Charles area and the aggressive timeline to complete the project by summer of 2018, this project needs to be started in the first half of 2015,” it said.
The project, which the company described in a Jan. 8 press release as “one of the largest single transmission projects in Entergy’s history,” includes two new substations, expansion of a third and 25 miles of 500-kV and 230-kV transmission.
“It’s not the largest [out-of-cycle project] we’ve ever received, but it’s substantial,” said Jeff Webb, MISO director of planning, in presenting the project to the Planning Advisory Committee on Wednesday.
Under the Transmission Planning Business Practice Manual, out-of-cycle projects are limited to reliability projects that address a need identified after the project submittal cutoff date of the prior annual MTEP cycle, with a required need date within three years of the request date and expected in-service date within four years.
Webb said the cost of the project would be allocated to the Entergy pricing zone and built by Entergy — not opened to the competitive selection process ordered by the Federal Energy Regulatory Commission in Order 1000.
“If you wait long enough, everything becomes a reliability project,” said George Dawe, vice president of Duke American Transmission. “In my mind it doesn’t meet at least one, and maybe two, of those criteria. … They’re saying that sometime after September this load materialized.”
“We think it meets the requirements,” responded Webb, noting the requested June 2018 in-service date. “It seems rational. We have no knowledge of when Entergy may or may not have known.”
Webb’s defense did not end the debate. Dawe was joined by others also expressing skepticism. Discussion of the project — scheduled for 10 minutes on the agenda — stretched on for about 45 minutes.
Sharon Segner of LS Power requested MISO evaluate the project to see “whether there are benefits to this line outside of Entergy’s footprint and whether it goes to the competitive bid process.” Those are the questions, she said, that would be the subject of a potential challenge before FERC.
Webb said such an evaluation would take too much time to meet Entergy’s schedule.
Entergy’s press release indicated the project would have benefits beyond reliability: “In addition to enhancing reliability, operational flexibility and helping meet the increased demand in the region, the project will also improve access to lower cost generation in the [MISO] market, potentially reducing costs for all customers in the area.”
Kipp Fox of AEP Transource questioned how the load “mysteriously appeared between Module E submissions” — interim resource adequacy plans each load-serving entity is required to provide MISO annually.
“You should have some governance rules,” he added.
Webb insisted Entergy’s claim was “believable.”
“It’s kind of like generator interconnections. Lots of people talk about generator interconnections. [Utilities] don’t start planning and building until you have a commitment.”
Tia Elliott, director of regulatory affairs at NRG Energy, noted that Entergy had won approval of an out-of-cycle project in Lake Charles a year ago. “Here we are a year later and we see another request for load growth in the Lake Charles area,” she said, noting that the total cost of the two projects exceeds $200 million.
Entergy submitted the earlier request Dec. 19, 2013, saying it was needed to respond to a signed contract it received about two weeks earlier for new block load additions in the Lake Charles area. The request proposed construction of a substation and a transformer upgrade. The company said the facilities, estimated to cost $37.7 million, were needed by summer 2015.
Webb said there is a tension between emergent reliability needs and the competitive developer selection process under Order 1000, which can take 12 months or longer.
Subjected to the competitive process “this project wouldn’t have a developer for a year and a half from now and it has to be in service in June 2018,” he said. “There’s not enough time.”
Webb also said MISO is “sensitive … to the possibility of gaming that [our-of-cycle] process.” He invited stakeholders to provide “specific suggestions on how we can meet those two competing issues” through rule changes.
No one from Entergy spoke during the discussion. In a statement today, Entergy said the project meets all four of MISO’s criteria for out-of-cycle projects. The filing “is the appropriate process for this project given the unprecedented growth occurring and the limited time to install the facilities needed,” it said.
“We look forward to participating in the stakeholder process and we fully expect MISO to approve the [project] as a baseline reliability project needed to support the unprecedented economic development occurring in this region.”
Tom Mielnik, manager of electric system planning at MidAmerican Energy, said the out-of-cycle process is necessary.
“Customers like to make the decision at the last minute and then they want the utility to act expeditiously,” he said. “This is a real issue and a need for out-of-cycle projects.” He added that customers “typically” insist that utilities keep their potential interest confidential as they weigh several different sites for potential expansions.
The project will be discussed in detail at a Feb. 11 meeting of the South Technical Study Task Force in New Orleans. The project will also be considered by the System Planning Committee of the Board of Directors, which Webb said could recommend it to the full board as soon as April.
Powhatan Energy Fund’s trading to capitalize on line-loss rebates cost more than 20 market participants at least $100,000 each, according to a PJM analysis, with Exelon, American Electric Power and Dominion Resources each losing more than $1 million.
The results of the analysis were included among more than 300 pages of documents released by the Federal Energy Regulatory Commission’s Office of Enforcement last week as it argued against Powhatan’s request for more time to respond to market manipulation allegations.
Joe Bowring, Monitoring Analytics; PJM’s Independent Market Monitor
FERC on Friday rejected Powhatan’s request to delay the filing, which was due today. But it said Powhatan could make a supplemental submission by Feb. 9 addressing the materials provided with OE’s response.
Powhatan filed a blunt-spoken response late Monday, in which they criticize the OE staff report on the case as “a pile of nonsense” (IN15-3).
The information released by FERC included a July 2010 audio recording of PJM Market Monitor Joe Bowring that Powhatan had sought in a Jan. 27 filing.
Powhatan argued that the recording that could prove that Bowring didn’t think its trading strategy — which collected line-loss rebates on what FERC contends were riskless up-to-congestion trades — was illegal. (See Gates, Powhatan Say FERC Enforcers Didn’t Share Crucial Info.)
FERC issued an Order to Show Cause in December seeking $29.8 million in fines from twins Rich and Kevin Gates and Houlian “Alan” Chen, who traded on behalf of their Powhatan hedge fund.
Losses Suffered
Enforcement recently asked PJM to run simulations to calculate how other market participants were affected by the trades by Powhatan and two other funds controlled by Chen and the Gates brothers.
In its response last Thursday, Enforcement said PJM’s analysis showed that the harm from the trading “was both widely distributed throughout PJM and significantly concentrated on certain load-serving entities” with more than 20 market participants losing more than $100,000 each.
The biggest losers were Appalachian Power (an AEP subsidiary), which lost $1.45 million, Dominion Virginia Power ($1.15 million) and Exelon’s PECO Energy and Commonwealth Edison ($1.2 million combined).
Powhatan Response Filed
Late Monday, Powhatan’s filed a 49-page response to the Order to Show Cause.
It disputes Enforcement’s characterization of its strategy as “wash-like” trades and claims the FERC proceeding is unconstitutional because the defendants never received prior notice that the trades at issue were unlawful.
“There is nothing inherently fraudulent about taking advantage of a market inefficiency or ‘loophole,’” they said, asking the commission to absolve them.
“The commission has an opportunity here to demonstrate true leadership. An opportunity to make a decision based on the right reasons — like fidelity to the law and fundamental fairness — instead of the wrong ones, like deference to OE staff just because the staff has consumed over four years on its up-to-congestion (UTC) investigation.
“This investigation has been so poorly conceived and poorly executed that it does a disservice to the commission,” they continued. “If this case proceeds any further, it will be a train wreck for FERC.”
PJM Comments
PJM issued a statement saying that Powhatan’s filing “illustrates only its failure to appreciate the unique legal and regulatory framework governing organized wholesale electricity markets. The electricity business, at its core, is still a public service in which Congress has mandated that consumers pay just and reasonable prices.”
It added, “FERC’s regulatory mission differ significantly from the regulation of traditional financial markets and the role played by the Securities and Exchange Commission. The exploitation of loopholes — although of questionable benefit to society — might be lawful behavior in financial and other commodity markets. In electricity markets, however, the Federal Power Act imposes a higher standard to protect consumers and other market participants from activities that increase prices without providing any accompanying benefits.”
Transparency
Kevin and Rich Gates
Kevin Gates said Saturday that the release of the information was a vindication of Powhatan’s decision to launch a public relations campaign against FERC, which included a website containing documents and testimonials from attorneys and economists supporting their defense.
“Going public with ferclitigation.com … put pressure on them to get us the materials, as they knew there’d be transparency on their behavior,” he said. “Still, though, they haven’t been fair. For instance, [Friday night] at 7:12 p.m., they sent us additional materials that they previously had not produced.”
Powhatan said the July 2010 recording captures a phone conversation between Bowring and another trader discussing trades like those at the heart of the Powhatan investigation.
On the tape, according to the Gates’ Jan. 27 filing, “Dr. Bowring says that the trades did not violate the rules, that he understands why the traders engaged in them, and that the rules need to be changed to remove the incentives that drove the trading. He also says that he would not refer the trading conduct to Enforcement if the traders stopped the trading in question.
“That last point is key because the PJM Tariff requires Dr. Bowring to refer trading that he thinks might be market manipulations,” according to the filing.
Under the so-called Brady rule, prosecutors are required to provide targets exculpatory evidence in the government’s possession. Gates’ attorneys said they asked for possible Brady material in August, and although materials were provided, the tape recording in question was not.
OE: Bowring Tape not Exculpatory
Transcript of July 2010 conversation among PJM Market Monitor Joe Bowring, Bowring associate John Dadourian and an unnamed trader. (Click to zoom)
Enforcement said it was providing the tape even though it was not exculpatory, and therefore didn’t fall under Brady. “This conversation relates to the behavior of another market participant and is not remotely exculpatory of [Powhatan’s] conduct,” it said.
According to a transcript of the recording, Bowring tells the unnamed trader that trades designed solely to collect line-loss rebates are not “legitimate.” Bowring says that while the trader was “not violating the rules” — an apparent reference to PJM’s Tariff — his actions were “not consistent with the spirit of the rules.”
Bowring says if the trader does not stop the questionable trading, the Monitor would refer the matter to FERC. The trader assures Bowring he has stopped the trading in question.
Bowring concludes the conversation by saying “we’re not going to take any further action on this” but adds he would be approaching PJM and perhaps FERC to discuss changing the market rules.
Enforcement said that Bowring informed FERC of his concerns the day after the conversation.
“The IMM, PJM and the commission all expressed concern about this behavior being harmful and potentially manipulative and all worked with alacrity to address it — and none of them ever alleged that it was a Tariff violation,” Enforcement said.
It noted that the recording appears to have been made in Pennsylvania, which requires mutual consent for recording phone calls. It said there is “no indication” that Bowring consented to these recordings. Enforcement said it did not name the trader on the tape because he has not been accused of market manipulation.
FERC spokeswoman Mary O’Driscoll said last week she would not comment on a pending matter. Bowring could not be reached for comment.
Attorneys for hedge fund twins Rich and Kevin Gates and their associate Houlian “Alan” Chen asked the Federal Energy Regulatory Commission on Tuesday for more time to respond to market manipulation allegations that could carry fines totaling nearly $30 million.
The reason? They argue that FERC’s Office of Enforcement has unfairly withheld evidence that could prove that PJM’s Independent Market Monitor didn’t think their trading strategy — which collected line-loss rebates on what FERC contends were riskless up-to-congestion trades — was illegal.
Their motion (IN15-3), which was filed after the Office of Enforcement denied their request for the information on Monday, asks the commission to compel its release and grant them a two-week extension on the Feb. 2 deadline for responding to the allegations.
FERC issued an Order to Show Cause in December seeking $29.8 million in fines in an unusually high-profile case that figured in a debate over FERC enforcement policy during Commissioner Norman Bay’s confirmation process earlier this year. (See FERC Staff Seeks $30 Million Fine in Powhatan Case.)
At his Senate confirmation hearing, Norman Bay defends his handling of FERC enforcement cases as Rich Gates (R) looks on.
The Gates brothers and Chen, who traded on behalf of their Powhatan Energy Fund, have denied wrongdoing.
In their filing, they say that they’ve learned that the Office of Enforcement has a tape in which PJM’s Independent Market Monitor Joe Bowring is talking to another trader discussing trades like those at the heart of the Powhatan investigation.
According to the filing, on the tape, “Dr. Bowring says that the trades did not violate the rules, that he understands why the traders engaged in them and that the rules need to be changed to remove the incentives that drove the trading. He also says that he would not refer the trading conduct to Enforcement if the traders stopped the trading in question.
“That last point is key because the PJM Tariff requires Dr. Bowring to refer trading that he thinks might be market manipulations,” according to the filing.
Under the so-called Brady rule, prosecutors are required to provide targets exculpatory evidence in the government’s possession.
The Gates’ attorneys said they asked for possible Brady material in August, and although materials were provided, the tape recording in question was not. On Monday, Enforcement refused to agree to an extension of the Feb. 2 deadline, and on Tuesday the attorneys filed the request with the full commission to grant the extension.
The filing notes that Enforcement recently asked PJM to run simulations that could have relevance to their case. The Gates’ attorneys asked for those as well.
“It appears that Enforcement has asked for PJM to perform these simulations for purposes of addressing alleged market harm related to the trades at issue,” the filing said. “That request could have been made years ago. Instead it was made after the Show Cause Order issued, while we were preparing our response.”
In an interview yesterday, Kevin Gates declined to say how he learned of the recording. He said he was surprised to learn that the Enforcement apparently had it and didn’t share it with his attorneys.
“If this doesn’t count as something under Brady,” he said, “why even have a Brady policy? What is the purpose?”
In his Senate confirmation hearing in May, Bay — then the director of the Office of Enforcement — said the office adopted the Brady doctrine at his suggestion.
Bay was responding to criticism by former FERC General Counsel William Scherman and other members of the energy bar that the commission has engaged in heavy-handed enforcement tactics. Scherman alleges that FERC officials have failed to abide by the doctrine. (See LaFleur Cruises, Bay Bruises in Confirmation Hearing.)
Bay’s replacement, acting Enforcement Director Larry Gasteiger, responded to similar allegations at an Energy Bar Association forum in April. (See FERC, CFTC Reject Due Process Complaints.)
FERC spokeswoman Mary O’Driscoll declined comment yesterday on the Gates’ filing. Bowring could not be reached for comment.
Interface Pricing Flaw: Today, the full effect of transactions on the MISO M2M constraint is modeled by both RTOs.(Source: Potomac Economics)
WASHINGTON — MISO’s Independent Market Monitor urged the Federal Energy Regulatory Commission last week to resolve a standoff between MISO and PJM over interface pricing that he said is costing consumers millions.
“We’re seeing tens of millions of dollars in uplift. We see transactions being scheduled that are not efficient. And the only way to really solve this is to get prices right,” MISO Market Monitor David Patton told commissioners during a panel discussion with RTO representatives and state regulators at FERC’s Jan. 22 meeting.
But PJM Market Monitor Joe Bowring and Stu Bresler, PJM vice president of market operations, said pressure for an immediate resolution could be short-sighted. “We have to be careful an arbitrary deadline does not force a bad answer rather than getting to the right answer,” Bowring said.
“I think a deadline that required a solution in a very near timeframe would be very difficult and potentially damaging if it resulted in an inferior approach,” agreed Bresler.
Whether the commissioners will set a deadline to help spur a resolution is unclear.
“I think we want to distill what we have heard today and get the sense of where the commissioners are,” Chairman Cheryl LaFleur said at a press conference following the meeting.
Two Years
MISO and PJM have been working for two years to resolve differences in the way they price transactions at interface buses.
The RTOs agree that the current methods undermine efficient scheduling of power because they cause both RTOs to model the same constraint, resulting in double-counting.
Patton says transactions are overcompensated when they are expected to relieve a constraint, and overcharged when they are expected to contribute to congestion. Interface pricing flaws “cost MISO some money. It costs PJM a huge amount,” he said.
Patton contends that PJM’s method exaggerates the effects of imports and exports on transmission constraints near the seam. As a result, he said, scheduling incentives have been inflated by as much as 600% at the Cook-Palisades interface in Michigan, the most active M2M constraint last winter.
“We massively overpriced congestion last winter and it resulted in an average of something like 3 GW being exported from PJM to MISO. This was during the timeframe when we were just coming out of the polar vortex and PJM had just incurred half a billion dollars in uplift, committing tons of generation under conservative operations, and they’re exporting gigawatts to MISO, where it’s demonstrably less valuable,” Patton added.
Bresler said he didn’t see the correlation. “PJM has made changes to its interface definitions in direct response to concern from MISO. Given the change we made, I’m not sure I understand the reference … to the polar vortex and the uplift,” he said.
Patton recommends removing the congestion component of the LMP for the non-monitoring RTO.
PJM offered an alternative in which each RTO would set its interface bus price relative to a common set of interfaces.
FERC to Set Deadline?
Patton said FERC should set a deadline for an agreement because there have only been two solutions under consideration for more than a year.
“We’ve had an incredible amount of analysis on those two solutions. Obviously, I think there’s one clearly correct answer, but not everyone agrees with me,” he said to laughter. “I think if we did have a deadline to file, it would be useful just to file and say ‘We’re agreeing to disagree, and here are the pros and cons of these two solutions that we have an enormous amount of research on, and then allow the commission to maybe weigh in and give some guidance and push the needle in one direction or the other.”
“We really need FERC’s involvement in this issue. We need a deadline to file a solution to this,” Patton told commissioners.
Bowring said he didn’t think a hard deadline made sense, although he suggested the RTOs could report back to the commission in June. “If we knew the answer, we would have told you already. We don’t.”
Bresler said Patton’s proposed solution to interface pricing could have negative impacts elsewhere.
“PJM has always defined our interface prices so that we reflect the impact of interchange transactions on the transmission system and more specifically on the transmission constraints which we are actually operating,” Bresler said. “And part of the solution that Dr. Patton has proposed is essentially eliminating the impact of some transmission constraints in the interface price.
“That may end up being the right solution,” Bresler added. “But I think the difficulty … is making sure that doing so doesn’t have detrimental effects elsewhere.”
LaFleur expressed frustration with the inability of the two RTOs to resolve the impasse.
“I am at least actively contemplating, should we do something more active than ask for another schedule, which is what we decided to do [in 2013] after a lot of tough talk,” she said. She acknowledged work done by the RTOs to address seams issues but added, “I’ve been a little disappointed with the level of progress on some of the thorniest issues, many of which have come before us today.”
Commissioner Philip Moeller said the problems are “partly our fault.”
“We kind of took our foot off the gas and stopped requiring the quarterly reports and basically lost focus on the fact that these issues were not going away,” he said.
Michigan Public Service Commissioner Greg White, another panelist, agreed a deadline could increase the parties’ “sense of urgency” but said he didn’t want to “end up with a product that is inferior because of a lack of time.”
Joint and Common Market Progress
The bus interface pricing issue has proven to be perhaps the most intractable issue facing PJM and MISO’s Joint and Common Market initiative, a joint stakeholder process to address seams issues.
Patton said the JCM process has borne fruit. He said MISO’s ability to export capacity into PJM has increased, although the two parties haven’t solved the underlying problems. “So while I don’t think we structurally have solved the problem and I don’t see a filing coming any time soon that will structurally solve this, I think the priority has diminished.”
Bowring was unapologetic. “There will continue to be issues as long as there are very substantial differences between the design for procuring capacity in MISO and the design for procuring capacity in PJM,” he said. “The … notion that there should be transfers no matter what I think is excessively simple-minded.”
Elizabeth Jacobs, chair of the Iowa Utilities Board, who represented the Organization of MISO States on the panel, said she was encouraged by MISO and PJM’s plans to introduce Coordinated Transaction Scheduling to improve interchange optimization. (See “PJM Posts MISO Price Predictions Before CTS Vote” in Market Implementation Committee Briefs, Jan. 12, 2015.) Jacobs noted that while the panel discussion focused on the PJM-MISO seam, many MISO members are facing new seams issues with an expanded SPP.
The Federal Energy Regulatory Commission said last week that it intends to tighten the rules on the use of “hold harmless” commitments in support of merger applications and will prohibit commitments that are limited in duration, which could leave ratepayers vulnerable.
In a proposed policy statement (PL15-3), the commission said it was better defining the costs subject to such commitments and the accounting methods used to track them. The commission will accept comments on the proposal, which it called a reaffirmation of its 1996 Merger Policy Statement (Order 592), for 60 days.
FERC noted that hold harmless commitments — agreements not to seek recovery of transaction-related costs in rates unless they are offset by transaction-related savings — have become a common feature of merger applications under section 203 of the Federal Power Act (FPA) over the last decade.
The commission said, however, that “it has never defined those costs with much specificity, leading to inconsistency with respect to this issue.”
The policy statement’s definition includes the costs of consummating a transaction (e.g., legal, investment advisory, accounting and financing costs) and the capital and operating costs incurred to achieve merger synergies (e.g., severance payments, accounting and operating systems integration costs).
The commission said requiring applicants to explain how they track the costs will help ensure that they are not recovered in rates without commission approval.
Time Limits
The Merger Policy Statement requires that hold harmless commitments must protect customers “for a significant period of time following the merger,” a period that the commission has typically defined as five years.
FERC said it now realizes that such a limit “raises the risk that transaction-related costs could be included in future formula rate billings without applicants making the showing of offsetting savings.”
The commission said its concern arose from its experience auditing utilities with hold harmless commitments, the concerns of protestors in previous merger applications and the proposed treatment of certain categories of costs.
“For example, an applicant could try to include transaction-related costs in formula rates without making a showing of offsetting savings if the costs, though incurred during the hold harmless period, do not enter the ratemaking process until after the hold harmless period expires … Similarly, limiting the applicability of hold harmless commitments to specific time periods may incentivize applicants to delay incurring some types of transaction-related costs until after the hold harmless period expires.”
The new policy, FERC said, ensures “that the focus of a hold harmless commitment [is] on whether a cost is transaction-related, and not on when the cost is incurred.”
FERC also said removing the time limit will ensure proper treatment of costs that should be capitalized as an asset during the hold harmless period, but whose cost recovery would occur as the asset is depreciated over future periods that extend beyond the hold harmless period.
Changes are Prospective
The commission also reiterated its opposition to including acquisition premiums as transaction-related costs. It said it would continue to require a showing of “specific, measurable and substantial benefits to ratepayers” for recovery in a subsequent FPA section 205 proceeding.
FERC said the policy changes would apply prospectively and would not affect existing commitments or pending merger applications.
