The Federal Energy Regulatory Commission on Friday ordered Richard and Kevin Gates and their associates to pay $34.5 million in penalties and disgorged profits in their high-profile market manipulation case. But the brothers say they will force FERC to collect in federal court, where a statute of limitations defense could reduce penalties.
“We’re going to fight, and we look forward to meeting them in court,” Kevin Gates said Saturday.
No Loophole
The commission’s order accepts the Office of Enforcement’s findings that the brothers’ Powhatan Energy Fund and trader Houlihan “Alan” Chen violated anti-manipulation rules by making riskless back-to-back up-to-congestion trades to profit on line-loss rebates (IN15-3). FERC Chairman Norman Bay, who oversaw the investigation in his previous role as Enforcement director, did not participate in the order.
“The fact that the PJM tariff does not explicitly prohibit round-trip UTC trades does not create a loophole or otherwise render respondents’ transactions lawful,” the commission wrote. “Respondents’ round-trip UTC transactions were deceptive and manipulative.”
The order seeks $29.8 million in civil penalties and $4.7 million in disgorgement of profits.
If the Gates brothers don’t pay up within 60 days, as they insist they won’t, FERC will have to file a complaint in U.S. District Court to force payment.
The brothers also could benefit from the U.S. Supreme Court’s 2013 ruling in Gabelli v. Securities and Exchange Commission, which held that a five-year statute of limitations for the SEC to bring a civil suit seeking penalties for securities fraud begins when the alleged fraudulent activity occurs, not when it is discovered.
The court found that the “discovery rule,” which starts the statute of limitations when a victim learns he has been defrauded, did not apply when the government brings an enforcement action for civil penalties.
“The discovery rule exists in part to preserve the claims of victims who do not know they are injured,” the court ruled. “The SEC … is not like an individual victim who relies on apparent injury to learn of a wrong. Rather, a central ‘mission’ of the commission is to ‘investigat[e] potential violations of the federal securities laws.’”
Under the 60-day clock, the earliest FERC could file would be about July 29. If the Gabelli ruling were applied in the Powhatan case, that could mean that FERC could seek penalties and disgorgement for only the last few days of the months of questionable trades.
That would be an embarrassment for FERC, which seemingly left the investigation in limbo for almost two years.
Evolving Strategy
Chen, who conducted the trades in question, began trading UTCs in 2007, after leaving Merrill Lynch, where FERC said he studied UTCs as a tool for physical and financial transactions.
Initially, his trades were based on market fundamentals and models he developed using a “careful, low risk approach of what he called `directional bets,’” FERC said. Most bids were under 100 MW, and his profitability depended on favorable price spreads.
In October 2009, after discovering he was receiving line-loss rebates, Chen switched to a strategy designed to capture increased volumes of rebates, FERC said.
His strategy changed again after suffering a $176,000 loss on May 30, 2010, when one leg of a trade saw an unexpected price spike.
Following the loss, Chen switched to a round-trip trading strategy between the same two points (A-to-B, B-to-A) that FERC said made the underlying trades effectively riskless.
FERC is seeking penalties only for what it calls the “Manipulation Period,” from June 1, 2010 through August 3, 2010, when Chen stopped the trading after receiving a warning from PJM Market Monitor Joe Bowring.
Four-Year Investigation
FERC began investigating Chen and his partners the same month. Over the next three years, Chen and the Gates brothers responded to FERC data requests and sat for depositions while their lawyers sparred with FERC’s attorneys and provided affidavits from an economist and an attorney supporting their defense. Kevin Gates said he rejected FERC’s offer to enter settlement discussions.
In October 2011, FERC said a charging decision was “imminent,” according to William M. McSwain, attorney for the Gates brothers.
The commission took no further action, however, until almost two years later, in August 2013, when FERC staff delivered a 28-page “preliminary findings” letter summarizing why they thought Chen’s trades were improper. Attorneys for Chen and Gates rejected the arguments and reiterated their demand that FERC end the investigation.
FERC refused.
Frustrated, Kevin Gates began planning a publicity campaign to make the case that he and his partners had been unfairly hounded by FERC. On Jan. 30, 2014, President Obama nominated Bay to fill the seat of former FERC Chairman Jon Wellinghoff.
A month later, Gates went public, launching a website that included much of the correspondence between FERC and the investors’ attorneys and statements from academics, consultants and former FERC officials backing their defense. (See PJM Trader Calls FERC on Manipulation Probe.)
It wasn’t until last August that FERC staff issued a Notice of Alleged Violations against Gates and his partners, the commission’s first public acknowledgement of the investigation. The notice was filed the day after Bay was sworn in as a commissioner.
Facing opposition in Arkansas, a transmission developer is using an unusual tactic in order to garner public support for a proposed project: online petitioning.
Clean Line Energy Partners is asking signers of its Change.org petition to send a pre-written letter to the Department of Energy, telling “Secretary [Ernest] Moniz to support the delivery of low-cost clean energy to consumers” and approve the Plains & Eastern Clean Line, a $2 billion 600-kV high voltage, direct current transmission line. Clean Line posted the petition three weeks ago and, as of press time, has collected more than 2,400 signatures.
Online petitioning is usually utilized by activists and grassroots organizations for populist causes. In fact, those in opposition to the Plains & Eastern project started their own Change.org petition in January. It has gathered more than 1,400 signatures since then.
The line would stretch 720 miles, beginning in the Oklahoma panhandle, through Arkansas and end in Tennessee, southeast of Memphis. Clean Line is touting the project as a way to deliver up to 3.5 GW generated from wind farms in Oklahoma to customers in the Southeast.
The Plains & Eastern is the first transmission project being developed with the U.S. Department of Energy under the Energy Policy Act of 2005’s Section 1222. The department issued a request for proposal under the section in 2010 and selected Clean Line for the project in 2012.
The section allows for the department’s Western Area Power Administration or Southwestern Power Administration to partner with private companies in developing new transmission facilities if the department determines that they are necessary to reduce congestion or meet demand. The facilities must be located in states in which the power administrations operate. SWPA owns transmission lines and facilities in Texas, Oklahoma, Missouri, Louisiana and Arkansas.
The Energy Department is currently evaluating public comments on its draft environmental impact statement for the project. Meanwhile, the department requested updates to Clean Line’s application in December 2014. The public comment period for this “Part 2” application ends June 12.
Battle for Public Support
The pre-written letter in the petition tells Moniz “I am writing to express support for the Plains & Eastern Clean Line and to urge the Department of Energy and Southwestern Power Administration to participate in the proposed project.”
Clean Line’s petition is just one of the tools it’s using to help supporters submit comments during the public comment period, said Sarah Bray, the company’s director of communications.
“We’ve been engaging with supporters in all kinds of ways,” Bray said. “We have a tremendous amount of support for this project. You wouldn’t think people would mobilize for a transmission line … it’s been really exciting to see.”
Many in Arkansas, however, oppose the project. According to the Times Record, multiple cities have passed resolutions opposing the project. Last week in Van Buren, multiple residents spoke in opposition to the line, even after the city’s mayor and council received a presentation from a Clean Line representative who highlighted the boon in jobs and tax revenue the area would see as a result of the project.
In February, Arkansas’ two senators, Republicans John Boozman and Tom Cotton, introduced the Assuring Private Property Rights Over Vast Access to Lands (APPROVAL) Act. The legislation would require the Energy Department to receive approval from the governor and public service commission of a state in which the department wanted to exercise eminent domain for Section 1222 projects.
While eminent domain is often unavoidable, “this difficult decision should not be in the hands of Washington bureaucrats,” Boozman said. “If a project is not good for Arkansas, our governor or public service commission should have the power to say ‘no.’”
In January 2011, the Arkansas Public Service Commission denied Clean Line status as a public utility. The commission said that while it supports building transmission infrastructure in the state and that Clean Line’s efforts were “laudable and its work to be commended,” the line would not deliver power to Arkansas customers, a key part of the definition of “public utility.”
The Oklahoma Corporation Commission and the Tennessee Regulatory Authority granted Clean Line public utility status in 2011 and January 2015, respectively.
MISO and PJM have again narrowed a list of “quick hit” flowgate projects with the potential to relieve market-to-market congestion.
Resagging of the NIPSCO section of the Michigan City-LaPorte 138-kV line is expected to cost $2.3 million. Had it been in place in 2013-14, it would have provided congestion relief of $2.7 million.
After reducing their list of potential projects from 39 in March to four in April, RTO officials told the MISO-PJM Joint and Common Market Initiative meeting on Wednesday that the list had now been reduced to two.
In March, MISO officials said they and their counterparts in PJM were considering projects to address 39 flowgates responsible for about $408 million in historical congestion.
In April, the PJM-MISO Interregional Planning Stakeholder Advisory Committee whittled the list of potential projects to four. The committee said most of the potential projects were unneeded because about $279 million of the congestion would be addressed by upgrades already planned or in service and that other flowgates in the initial selection had not experienced congestion recently.
At Wednesday’s MISO-PJM JCM meeting, RTO staff said two of those remained on the recommended list, after determining that the other two were already being addressed. An additional five will be monitored for recommendations in the future.
Had the two projects been in place for 2013 and 2014 — the period studied — they would have reduced congestion by $9.6 million.
One is a SCADA equipment upgrade for the 161-kV Beaver Channel-Sub 49 line, providing congestion relief of $6.9 million.
The other is the 138-kV Michigan City-LaPorte line, which is resagging in the Northern Indiana Public Service Co. section, with congestion relief of $2.7 million.
Costs for the proposed Beaver Channel project are “minimal,” while Michigan City-LaPorte is estimated at $2.3 million, according to RTO officials.
Talks are underway with transmission owners and entities that would benefit from the upgrades. The projects are to be evaluated for inclusion in MISO’s 2015 Transmission Expansion Plan (MTEP15) for recommended approval in December.
MISO identified about $99 million in remaining congestion that hasn’t been addressed for service upgrades. About $80 million of that congestion is along the Michigan interface that will be subject to further study in the second half of this year.
Deliverability Improvements
Meanwhile, MISO has introduced a proposal to remove hurdles preventing it from importing more capacity from PJM. MISO said that while the MISO-to-PJM direction is “almost fully subscribed,” the transmission capability in the PJM-to-MISO direction is “minimally utilized.” One idea contemplated is expanding an external network resource interconnection service that allows an external resource to serve network load as would an internal network resource. The external resource would require transmission service to the MISO border.
Another is a modified external network integration transmission service (NITS) concept. MISO would offer NITS to generators and allow the MISO network load to be identified in the Planning Resource Auction.
“Right now, if you’re an external generator without existing load, your only option is point-to-point service,” said Jesse Moser, manager of infrastructure studies at MISO. The RTO is seeking stakeholder feedback by June 26.
The ideas emerged as part of broader talks between the RTOs to comply with the Federal Energy Regulatory Commission’s Order 1000 compliance filing, which is due June 16.
Stakeholders at the JCM meeting were told the RTOs have agreed to most of FERC’s directives and non-substantive revisions to eliminate differences between the two RTOs’ filings. Cost allocation remains under discussion.
Central Hudson Gas & Electric’s decision to include distributed energy resource projects in its rate case before New York regulators is providing an early look into a utility’s and stakeholders’ approach to the state’s energy industry overhaul.
New York’s Reforming the Energy Vision, as spelled out in a February 2015 order by the Public Service Commission, requires utilities to propose demonstration projects by July 1.
Central Hudson included its proposal as part of its pending rate case (14-E-0318, 14-G-0319).
“We find there are opportunities to make our system smarter, better and stronger under REV and proposed projects that we feel will help achieve these goals,” said John Maserjian, a company spokesman.
Shaping the Rules
The demonstration projects and rate case are on separate regulatory tracks before the NYPSC. But by being first out of the gate, Central Hudson could help shape the rules.
Comments filed in response to the company’s May 1 list of proposed projects highlight the dispute over the extent to which utility ownership of DER will be allowed, even at the demonstration stage. (See New York PSC Bars Utility Ownership of Distributed Energy Resources.)
The Independent Power Producers of New York objected to the Central Hudson-owned community solar project, saying it violates REV’s prohibition of utility ownership, even under criteria for the demonstration phase. “As a private investor has proposed a community solar project, there is no reason, and it would violate the commission’s objectives, for Central Hudson to go forward with its competing proposal.”
Consolidated Edison Solutions has proposed its own community solar project and also objects to Central Hudson project ownership.
Need for Transparency
A coalition of intervenors representing commercial and industrial customers said “targeted demand response” identified as a solution to transmission congestion in the Central Hudson region is a worthy goal, but it called for more transparency. “The information necessary for other parties to evaluate this specific project, beyond the general concept, simply has not been made available … inasmuch as customers are being asked to fund the project, the relevant information as to the estimated costs and benefits of the project need to be disclosed, with ample opportunity for parties to comment thereon, prior to it being approved.”
The projects proposed by Central Hudson were the result of a collaborative process among competitive suppliers, environmentalists and consumer groups in the utility’s territory.
Project List
The demonstration projects are:
Central Hudson’s Community Solar: The project, expected to cost up to $10 million, would be owned by the utility and would sell energy to customers in 100-kWh blocks under a 25-year power purchase agreement.
SolarCity’s community solar: Similar to Central Hudson’s project, this 2.5-MW array would be located on Central Hudson property but owned by SolarCity.
Central Hudson’s demand response: The project will promote residential and commercial customer aggregation in three areas of Central Hudson’s service territory.
Central Hudson’s microgrid: Central Hudson would install generating capacity designed to meet critical power needs during an outage for customers that join. The project could integrate storage, local renewable and distributed energy resources and local demand response resources. A letter of intent has been executed with several customers and NRG Energy, which has prior microgrid experience in New Jersey and the Caribbean.
Central Hudson’s behind-the-meter services: The company proposes to demonstrate the viability of behind-the-meter services for 1,000 customers for six months at no cost to explore product and services made possible by smart devices; and
Citizens for Local Power’s community choice aggregation: Over 30 months, municipalities within Ulster County will engage in detailed energy planning, setting of goals and priorities, and other actions to create the first CCA “2.0” in New York. The project, which was not in Central Hudson’s original proposal, does not meet REV criteria of having competitive suppliers and third parties pay most of the demonstration costs. Central Hudson said it is willing to help, but as proposed, the nearly $800,000 in start-up funds would come from ratepayers.
PSC staff will review projects for compliance with the order. “If any are selected to move forward, they will fall under further review for REV compliance by state regulators,” Maserjian said.
Even if a project is not deemed to be a demonstration project, those deemed to have value will proceed in a different setting, according to the PSC.
WILMINGTON, Del. — A first-read proposal to disband a deadlocked Financial Transmission Rights/Auction Revenue Rights (FTR/ARR) Senior Task Force drew a strong reaction from stakeholders, with some expressing fears the dissolution might lead to a unilateral filing by the PJM board and others who said it was time to move on to other issues.
“We did reach consensus on one thing,” task force facilitator Dave Anders told the Markets and Reliability Committee on Thursday. “The group felt that it was not likely that there was anything more fruitful we could do with the FTRSTF.”
However, he said there was a chance one package that had garnered nearly 50% approval at the task force might win broader support with modifications.
“Members can make a motion at the MRC or [Members Committee] to propose something they feel might be able to reach a supermajority sector-weighted vote,” he said. “It did seem in the task force discussions that there’s a possibility out there — we just hadn’t latched on to it yet.”
The task force, formed last spring, was charged with evaluating causes for FTR underfunding and determining stakeholders’ expectations of ARR and FTR.
Stu Bresler, vice president of market operations, agreed with Anders. “We’ve been at this for a while and we’ve been unable to receive stakeholder consensus on a package of proposals. … We’ve seen an increasing percentage of stakeholders who say they want to see a change from the status quo. What is the expectation on the part of the stakeholders of how that might happen?”
Steve Lieberman of Old Dominion Electric Cooperative took Anders up on his offer and asked for a chance to draft a proposal for consideration at the next MRC meeting.
But others, including Bruce Bleiweis of DC Energy, who served on the task force, said it was time to move on.
“This is not the first task force that’s discussed this issue,” Bleiweis said. “This has gone on for years. There’s a large percentage of people who have been at the task force who have not offered alternatives, but they vote that they want change. The skeptical part of me asks, why do people want to keep having these discussions? Is it if we keep talking about these issues, [the Federal Energy Regulatory Commission] won’t act, PJM won’t act?
“I think the task force has been done for a while. We haven’t seen anything come out of the task force that would have a meaningful impact.”
Susan Bruce of the Industrial Customers Coalition said that while a majority of stakeholders might want change, the change they want varies widely.
“I want to make sure it’s clear from an industrial customer perspective that we have voted that we’re looking for change, but the definition of change that my clients are looking for and the definition of change that others are looking for may be different.
“The change that we’re looking for is incremental, if you will, and it is not fundamental,” Bruce said.
WILMINGTON, Del. — PJM likely will recommend reducing a proposed $30,000 fee for studying transmission projects of $20 million or more.
PJM has deferred filing the plan with FERC pending further review, Paul McGlynn, general manager of system planning, told the Markets and Reliability Committee on Thursday.
McGlynn said that as planners were preparing the filing, data indicated that the fee might be more than necessary to cover the costs of internal labor and external consulting associated with the competitive windows during the approximately two-year trial period.
The fee proposal was approved Feb. 26 by the MRC and Members Committee after the Federal Energy Regulatory Commission rejected as discriminatory a previous plan to apply the fee to all greenfield projects but not upgrades of less than $20 million. (See FERC Rejects Fee on Greenfield Transmission Projects.)
McGlynn said the decision was based on the increased number of projects being considered under this new approach along with the most recent data drawn from the limited 2014 proposal windows.
“We just wanted to give you a heads-up that we will delay filing it and will update the proposal to some amount other than $30,000,” he said.
PJM had planned to ask FERC for approval that would affect the window that ended in February. Now, McGlynn said, “It likely will not be in effect for any proposal windows this year.”
A revised proposal is expected to be presented at the Planning Committee next month.
PJM: Mistaken LOC Credits Total $7M to $15M
PJM this week expects to finalize the amount of money it will seek from generators that mistakenly received lost opportunity costs when they were on forced outages and ineligible, Chief Financial Officer Suzanne Daugherty told the MRC.
Daugherty said staff had narrowed the total overpayments over two years to between $7 million and $15 million. The next step is to break down the cost by generator.
“It’s taking time to do this,” she said. “We are having to look at reporting data systems that have not been designed to interact with each other.”
While Daugherty said it’s likely the erroneous payments extend before April 2013, the Tariff allows the RTO to recover only 24 months’ worth.
Affected generators will begin being contacted this week, she said. Following these conversations, billing adjustments will be appearing in the June month-end statements, she said, and might roll into July’s bills.
The compensation applies to combustion turbines that are scheduled in the day-ahead energy market but are not committed in real time. However, if they are not able to operate in real time, they are not eligible for the credit. (See PJM to Recoup up to $15 Million in Mistaken Lost Opportunity Costs.)
Members OK Gas-Electric Initiative
The committee approved a problem statement and issue charge to review options for moving the day-ahead energy market and reliability unit commitment timelines in response to FERC’s final rule on coordinating gas and electric schedules.
The initial proposed solution involves shrinking the amount of time, from four hours to three and a half, that PJM has to resolve offers.
In a related discussion later in the meeting, stakeholders expressed concern that the earlier the offer deadline is moved, the less accurate a load forecast will be due to lack of good information about impending weather and gas trades.
Joe Wadsworth, who made a presentation on behalf of Vitol, raised several concerns, including that robust natural gas trading does not occur before 9:30 a.m. and often is later, especially in the winter. And, he said, trading is unlikely to shift earlier regardless of whether PJM moves up its day-ahead bidding. In addition, he said in his presentation, “Sequencing of NYISO’s DA market clearing well in advance of PJM’s DA bidding deadline is critical.”
The next educational session on the issue will be held following the June 10 Market Implementation Committee meeting.
Interim Fee for Virtual Transactions Fails
Two proposals from Inertia Power to impose a temporary $0.07/MWh uplift charge on virtual transactions failed — not surprising given the reception on their introduction in April. (See Cool Response to Proposed 7-Cent Fee on Virtual Transactions.)
One proposal would have imposed the fee on up-to-congestion bids (UTCs), increment offers (INCs) and decrement bids (DECs); the other would have applied to UTCs only. The first proposal failed with only 26% support; the alternative motion fell short at 31%.
The proposals would have expired in six months or upon FERC approval of an alternative. Transactions placed between September 2014 and the effective date of the filing would not have been affected.
“We haven’t been able to reach consensus. We need something to protect the market in the interim,” said Noha Sidhom in making the case for the proposal.
The fee, she said, would provide transactional cost certainty as well as a new revenue stream for uplift as the system heads into volatile summer months. It also would give insight into what a permanent fee could look like.
The proposal was in response to a Section 206 proceeding ordered by FERC to determine whether PJM is improperly treating UTCs differently from INCs and DECs.
While INCs and DECs are charged uplift and subject to the financial-transmission-rights forfeiture rule, UTCs are exempt from both. UTC trading volumes crashed after Sept. 8, the refund-effective date set by FERC for any uplift assessments.
Those who supported the fee pointed to the fact that at least it would constitute something rather than nothing.
“We’re not sure FERC is going to order retroactive refunds,” said Dave Pratzon of GT Power Group. “If they don’t, you might have a period of six to nine months where you’re collecting revenue where you don’t have that now.”
Some also worried that a large refund could potentially bankrupt some financial participants.
The Independent Market Monitor, represented by Howard Haas, led the opposition to the measure.
“We think this is an end-run around the EMU process,” he said in an interview after the vote, using a shorthand reference for the Energy Market Uplift Senior Task Force (EMUSTF).
If implemented, the proposed fee would replace an allocation of uplift charges in any retroactive collection ordered by FERC, he said. By relieving such pressure, it would remove the incentive for financial participants to reach a solution at the task force, he said.
And he said, “The jury is still out on the benefits of virtuals, particularly UTCs.”
Manual Changes Unanimously Endorsed
Members endorsed the following manual changes:
Manual 36: System Restoration — Annual review. Adds detail about when PJM assumes control and when it returns to normal operation. Also adds guidance on completion of interconnection checklist. Effective: June 15.
Manual 03: Transmission Operations — Updates index and operating procedures for PJM RTO operation (nuclear station voltage limits, operation procedures with neighboring systems and operation procedures for AEP, ComEd, Dominion, PPL, UGI, PSEG and PECO.) A change to section 2.1.1 adding a requirement that load dump rating be at least 3% higher than emergency rating was removed due to differing ideas over what it meant. The issue will return to the committee later. Effective: June 1.
Manual 38: Operations Planning — Makes minor changes due to system upgrades and specifies periodic review of IROL facilities. Updates the study process for transmission reliability analysis procedure. Effective: June 1.
The Independent Market Monitor for the Regional Greenhouse Gas Initiative found no evidence of anti-competitive conduct in the CO2 allowance secondary market, according to its report.
Potomac Economics found that the average transfer price of CO2 allowances during the first quarter of 2015 was $5.46, approximately 5% higher than in the prior quarter and 41% higher than the first quarter of 2014. The clearing price in Auction 27, held on March 11, was $5.41, which was consistent with secondary market prices leading up to the auction.
RGGI Reorganizes Executive Board
A Connecticut regulator has assumed the chair of the Regional Greenhouse Gas Initiative.
Katie Dykes, deputy commissioner for energy at the Connecticut Department of Energy and Environmental Protection, became the new chairwoman on Friday, replacing Kelly Speakes-Backman. The executive committee includes Joseph Martens, commissioner of the New York Department of Environmental Conservation, vice chair; Thomas Burack, commissioner of the New Hampshire Department of Environmental Services, secretary; James Volz, chairman of the Vermont Public Service Board, treasurer; and David Small, secretary of the Delaware Department of Natural Resources and Environmental Control, member-at-large.
Biographies of executive committee members and of the entire RGGI board are available here.
State lawmakers have overwhelmingly approved a bill that would ban power companies from signing up residents for variable-rate electricity contracts. The measure, which would take effect Oct. 1, now goes to Gov. Dannel P. Malloy, who is expected to sign it into law.
The legislation attempts to quell a source of consumer complaints against third-party suppliers who seek to switch residents from the state’s two utility-managed standard-generation offers.
Although the bill would prohibit suppliers from signing up customers for variable-rate plans, it does not ban variable rates outright. The majority of residents with variable electric plans do not sign up for such plans; they are rolled over into a variable plan by their suppliers at the termination of their fixed-rate plans. The legislation requires regulators to address this issue.
Proposed Gas Rate Changes Would Increase Larger Users’ Cost
The state’s chemical industry is fighting a proposed Delmarva Power & Light natural gas rate plan that would lower costs for residential customers while increasing charges by 6 to 30% to larger users. The utility proposed the changes after a consultant for the Public Service Commission said last year that some gas customers appear to be subsidizing larger, bulk purchasers. “A potential 25% natural gas cost increase to Delaware businesses is not the message that the state should be sending,” Josh Young, executive director of the 14-member Chemical Industry Council of Delaware, said in a letter to the PSC. For residential customers, the changes would mean a 1.4%, or $1.75, decrease in bills for an average winter month.
A public workshop is scheduled for Wednesday in Wilmington. The PSC said a decision could come by the end of the year.
Exelon’s Nukes in Limbo as Legislature Ignores Bill
Three clean power bills — including one backed by Exelon to support three of its struggling nuclear plants — have stalled in the General Assembly. Part of the legislature’s delay relates to the surprise results of MISO’s Planning Resource Auction, which is expected to result in higher rates next month. (See related story, Public Citizen to FERC: Investigate Dynegy Role in MISO Capacity Price Jump.) “There are an awful lot of questions, some of which arose after the auction,” said Steve Brown, spokesman for House Speaker Michael Madigan.
On Monday, in an 8-K filing with the Securities and Exchange Commission, Exelon said that it doesn’t expect the legislature to pass its proposed Low Carbon Portfolio Standard during the current session. The company has said that without the revenue the legislation would bring in, it might have to close the plants in Byron, Quad Cities and Clinton. (See Exelon-Backed Bill Proposes Surcharge to Fund Illinois Nukes.)
In April, Exelon Executive Vice President Joseph Dominguez had said the company wouldn’t wait until the fall veto session for an answer. Last week, however, the company appeared to be more flexible. “We remain open to participating in any and all discussions designed to enact a legislative package,” the company said.
Northern Indiana Public Service Co. will reimburse customers nearly $1 million and reapply for any rate increases under a settlement reached with the Utility Regulatory Commission. The settlement, a response to a state Court of Appeals ruling that overturned the IURC’s previous approval of NIPSCO’s seven-year infrastructure modernization plan, will result in refunds averaging about $6 per customer.
The settlement covers only NIPSCO’s electric customers. A separate plan covers the company’s gas customers.
The Office of Utility Consumer Counselor and some of NIPSCO’s industrial customers appealed the company’s seven-year plan, saying they were concerned about double recovery and the accuracy of the company’s rate-based investments.
The Legislature’s Energy, Utilities and Technology Committee on Thursday scuttled Republican Gov. Paul LePage’s energy proposals in a 7-6 party line vote.
LePage’s proposals would have made sweeping changes in longstanding state energy policies designed to encourage renewable energy development and to fund efficiency programs. They included a repeal of the state’s renewable portfolio standard and a measure that would require utilities to provide a credit “backstop” to help large businesses expand natural gas pipeline capacity. One bill would cut conservation programs by returning a larger share of revenue from a regional carbon credit auction.
LePage’s energy director, Patrick Woodcock, said that he hoped some elements of the governor’s proposals could be resurrected this year.
Two-Year Fracking Ban Enacted as Hogan Declines Action
Hogan
Gov. Larry Hogan last week allowed a state-wide fracking ban to take effect without his signature.
When the ban passed in both houses of the General Assembly with a veto-proof majority, Hogan said he would neither sign the law nor veto it. The deadline for action passed Friday night, and the ban will go into effect on Oct. 1.
Sponsors of the bill said the ban would allow scientists the chance to study the potential environmental impacts of fracking. Hogan had called fracking an “an economic gold mine” during his 2014 election campaign. But since taking office in January, he had been quiet on the issue.
Protesters Interrupt Snyder; Call for Action on Enbridge Pipeline
Environmental activists opposed to an aging Enbridge oil pipeline interrupted a speech by Gov. Rick Snyder at the 2015 Mackinac Policy Conference, before being escorted out of the conference.
The protesters are calling for the closure of the 61-year-old Enbridge Pipeline No. 5, which carries crude oil from northern Wisconsin to southern Ontario beneath the Straits of Mackinac. They cited studies from an environmental nonprofit that question the pipeline’s structural integrity.
Pipeline safety is a looming issue, especially in Michigan. Just last week Enbridge reached a $75 million settlement with state environmental regulators related to a 2010 spill into the Kalamazoo River. Cleanup for that spill, which is ongoing, has already cost the company $1.21 billion.
PUC Approves $250 Million Geronimo Energy Solar Project
The Public Utilities Commission has approved a $250 million solar project comprised of 21 facilities throughout the state.
The sites for the Aurora Solar Project are mostly in rural Minnesota near established transmission lines. The power will be sold to Xcel Energy. It will be the largest solar installation in the state and increase the state’s solar output by a factor of seven. Surprisingly the project beat several natural gas projects in the bidding process.
“This signals that something big is happening in solar energy in Minnesota,” said Michael Noble of Fresh Energy, a non-profit solar advocacy group. The PUC rejected three other sites because of local zoning rules.
Literal Power Struggle Keeps Revel Casino from Opening
A legal standoff between the developer that bought Atlantic City’s Revel complex out of bankruptcy and ACR Energy Partners, its sole power supplier, will keep the shuttered casino at the complex from reopening this summer.
Glenn Straub, the developer who bought the casino, agreed to a tentative deal with ACR to keep the building minimally powered while he looks for a way to either connect into the Atlantic City Electric grid or tap into the defunct Showboat casino next door, which is now owned by Stockton University. Straub’s company, Polo North Country Club, is battling ACR over fees. The state’s second tallest building was without power for three weeks after ACR pulled the plug April 9 following the bankruptcy sale. State officials have ordered the two companies to keep the building’s fire-suppression powered. The parties also are dueling over who owns $40 million in electric equipment that connects ACR to the complex.
NYISO is changing its Consumer Impact Analysis, a process that evaluates the impact of market administration projects and rule changes, to improve transparency and provide more opportunities for stakeholder input.
The Consumer Impact Analysis evaluates the potential impact of changes based on reliability, environment, cost and transparency. The revised process will give stakeholders notice at the outset of a market design initiative if a project is expected to have a major consumer impact. Stakeholders will receive a description of the methodology to be used in the impact analysis, the results of which will be presented at least 30 days prior to stakeholder votes.
The changes incorporate feedback received from end-use consumer representatives, other market participants and policymakers.
Some residents in Walnut Grove, a town of about 1,500 located on top of potential shale gas reserves, are objecting to a state plan to conduct core sampling on publically owned land to explore for natural gas.
“The community we love is in the middle of a David-and-Goliath battle with big industries that seem to care very little about the people in the area we call home,” town resident Tracy Brown Edwards said. Walnut Grove already hosts the third-largest coal ash dump in the state.
The legislature approved fracking last year but almost immediately issued a moratorium while legal challenges are prepared.
PUCO Delays Decision on AEP’s Coal Rider Until PJM Capacity Auction, FERC Ruling
The Public Utilities Commission said it would wait until after the PJM capacity auction to rule on American Electric Power’s request to guarantee rates from its aging coal plants in return for a vow to keep them operating.
The commission in February approved most of AEP’s three-year security plan but rejected the company’s guaranteed-income request. Two other utilities — FirstEnergy and Duke Energy — have similar requests pending before the commission.
The commission said it wants to see the results of the PJM Base Residual Auction, and the final outcome of the state’s plan to meet the Environmental Protection Agency’s Clean Power Plan, before ruling. The auction for 2018-19 should have taken place in May, but it was delayed to give the Federal Energy Regulatory Commission time to approve PJM’s Capacity Performance proposal. That reform is expected to benefit coal plants in PJM, including those in AEP’s fleet.
Gov. Mulls Ban on Fracking Bans After Texas Passes Similar Law
A law prohibiting local government bans on fracking is awaiting the governor’s signature.
The Senate voted 33-13 on the bill — which also prohibits local bans on wastewater disposal wells — at the urging of the oil and gas industry. The industry has faced increased pressure from communities where fossil fuel opponents have made headway after Denton, Texas, last year voted to ban fracking within town limits. Denton is located in the heart of the Barnett Shale region.
The industry argues that regulation of oil and gas development comes under the aegis of state or federal regulators, not local officials.
Coal Alliance: Benefits of Clean Power Plan Overestimated
Pennsylvania Coal Alliance CEO John Pippy says the federal government has underestimated the cost of imposing regulations related to the Environmental Protection Agency’s Clean Power Plan and overestimated its benefits.
Washington needs to consider the effect of forcing coal plants into retirement, Pippy told the Pittsburgh Business Times. “There’s no place to sell the coal right now,” he said.
Last week, Murray Energy and Alpha Natural Resources announced layoffs of more than 2,000 people. Alpha plans to close its Emerald mine in Greene County by the end of the year. Consol Energy has said it will reduce its state mines to a 32-hour workweek.
Wolf Nominates Environmental Professional to Seat on Public Utility Commission
Gov. Tom Wolf nominated a gas industry executive and climate change researcher to the Public Utility Commission. Andrew Place, EQT ’s corporate director for energy and environmental policy, would take the place of outgoing Commissioner James H. Cawley.
“Andrew Place brings the knowledge and expertise to help advance my vision for the PUC, and I am pleased to nominate him,” Wolf said. “We must ensure there is a balance between consumers and utilities. We also have to develop Pennsylvania’s abundance of energy resources to make sure we have the infrastructure to support the natural gas and other energy industries.”
Place has degrees in economics and public policy and worked as a research fellow at Carnegie Mellon University’s Department of Engineering and Public Policy, becoming an expert in carbon capture and sequestration.
Qualifying electric vehicles bought or leased and registered in the state will be eligible for rebates of up to $2,500 beginning June 15.
The total pot of money available for consumers is $682,500, and it will be doled out on a first-come, first-served basis. Drivers of zero-emission battery electric vehicles will get $2,500. Those that lease or buy plug-in hybrid electric vehicles will receive $1,500.
Dealerships will be responsible for filing a claim and then will give the money to their customers.
Xcel Energy is asking state regulators to raise its fixed monthly fee for electricity and natural gas customers, rather than seeking an increase in usage rates.
Xcel wants to increase the fixed monthly customer charge from $8 to $18. The company said it would decrease its usage rate by about 0.7 cents/kWh. The increases would boost electricity revenue 3.9% and gas revenue 5%.
Regulators in neighboring Minnesota this year rejected a similar request by Xcel to increase the customer charge. Customer advocates said fixed-fee increases penalize smaller users and reduce the incentive to conserve. The company argues that bigger fees provide for a more equitable recovery of costs to maintain distribution networks. “The nature of the electric grid is going to change,” an Xcel executive said. “The grid is there and costs something regardless.”
Manitoba Hydro has asked the Public Utilities Board for a 3.95% increase in its electricity rate to cover increased borrowing costs, especially for projects like the Keeyask plant. The request comes after the utility received a 3.5% increase in 2013 and a 2.75 % interim increase in 2014.The Consumers’ Association of Canada and the Manitoba Metis Federation have told the PUC they oppose the rate increases, which they say will hurt lower-income customers. Consumer advocates also noted that Manitoba Hydro has said it will seek a similar increase next year.
Keeyask is a 695-MW hydro station being built on the Nelson River. When completed it will be the company’s fourth largest hydro station.
INDIANAPOLIS — MISO will release the results of its latest resource adequacy survey later this month, after a survey last year caused alarm, with forecasts of capacity shortages in three zones in MISO North and Central.
How bad will the new numbers be? And how can MISO increase its reserve margins in the future? Those were among the topics that dominated discussion at Infocast’s MISO Market Summit last week.
“We do not have a capacity shortage,” Lin Franks, Indianapolis Power & Light’s senior strategist for RTO, FERC and compliance initiatives, said flatly. “The message has been ridiculously presented to the world as if the sky is falling. The sky is not falling. It’s been very difficult with [the Environmental Protection Agency] disrupting all our planning processes, but we are rallying. We are solving it. We have an obligation to serve load and damn it, we’re going to.”
Franks
Franks found some support from Kathleen Spees, a principal of The Brattle Group. “There’s more [capacity] that gets offered than comes out in these surveys. So I’m not particularly worried that we’re really going to have a shortage.”
Snapshot in Time
Franks said the survey data, which is collected by the Organization of MISO States, makes the situation look worse than it is.
Utilities are asked, for example, about the certainty of their plans for new generation. “[You] are never certain at all until you get your certificate of public convenience and need. So it’s not a graduated certainty. It is or it isn’t, period,” she said. “What you’re seeing is a snapshot in time. It doesn’t mean that there won’t be a solution [when the capacity is needed].”
Gardner
Joseph Gardner, MISO’s vice president for forward markets and operations services, said the RTO will change how it presents the survey data in the new report. “So hopefully it will address some of those things,” he said.
There is no question, however, that MISO, which has enjoyed reserve margins exceeding 20% in the past, is facing a much tighter future.
Calls on Interruptible Loads to Increase
Gardner noted that it’s been nine years since MISO last deployed its load-modifying resources — currently about 6 GW of behind-the-meter generation and 4 GW of interruptible loads.
David Sapper, of Customized Energy Solutions, speaks as Jim Carson of RisQuant Energy (left) and Chris Plante of Wisconsin Public Service listen.
“We’re going to start having to use that quite often. I don’t expect we’ll have to use it very often this year, but we do expect to use it very often starting next year,” he said. “How often is hard to tell. It depends on what kind of a summer we have. If we have a summer like we did three years ago: not much. If we have a summer like we did two years ago: a lot — upwards of two dozen times of more.”
That could result in departures from the program, Gardner and others said.
“Essentially those interruptible customers start to look like a peaking generator,” said Chris Plante, director of resource planning and policy for Wisconsin Public Service. “Those customers … are not accustomed to regular interruptions. Our thought is that as they start to experience those interruptions, they may actually decide to leave the interruptible program and become firm load, which of course makes the situation even more tight.”
David Sapper, director of midcontinent regulatory affairs for Customized Energy Solutions, said MISO officials’ recent suggestion that they are considering testing the response of interruptible loads may also contribute to defections.
Challenges to Adding Generation
Losses of interruptible loads would make the construction of new generation even more crucial. But that won’t be easy, Plante said, because of “friction” in MISO’s interconnection process.
Plante
“You have to get into the MISO interconnection queue early enough so that you get your study results done and you get the transmission issues identified. Usually that time frame is so long that I don’t even have a good idea yet on whether I’m going to build a one-on-one combined-cycle or a two-on-one. If it’s a one-on-one, is it 400 MW or is it 450 MW? That might not seem like a big deal, but to MISO’s interconnection process it’s a big deal. You can’t go in with 400 and later say, ‘Well it’s really 450.’ You have to get out of the queue and get back in with 450.”
Plante also criticized MISO’s modeling of wind power at 100% of nameplate capacity during off-peak hours. “When my combined-cycle is modeled at 100% and the wind’s modeled at 100%, there’s all kinds of constraints. And those constraints show up in my interconnection agreement as issues that I need to resolve before I can count that generator as capacity. Depending on the lead time of those constraints, I might have to wait for 10 years [for a major transmission project] before I can get the capacity value out of that combined-cycle when in reality … we believe that off-peak wind probably won’t be at 100% and the constraints that MISO identifies might not ever show up.”
No Rescue from IPPs
Don’t expect to see independent power producers riding in like the cavalry to build new generation.
Kruse
Brett Kruse, vice president of market design at Calpine, said his company won’t build in MISO without a contract because all but two of its states are dominated by vertically integrated utilities and its voluntary capacity market provides too little revenue.
“The contract has to be 10 or 20 years depending on how much you can frontload it … where you basically have to stick all the value of your plant into that contract, because once you get out and you’re a merchant plant in a construct like [MISO], you have very little value other than what you’re seeing the IPPs in Michigan do: Either you build a line to get into PJM like [Tenaska Capital Management’s Covert, Mich., plant] did or you sell to the utilities.”
As the biggest natural gas buyer in the U.S. and one of the biggest operators and builders of gas-fired generation, “I can build … a gas-fired plant cheaper than anybody else in America. … We’re very confident we can run circles around any utility self-build in America.”
But he added, “If I went to my board and said I wanted to invest $500 million into building a [merchant] plant in MISO, they’d laugh me out of the room — and then fire me.”
Until recently, MISO’s ample reserve margins have meant there hasn’t been much need for merchant entry, said Brattle’s Spees.
Capacity Prices Too Low?
But, she said, “That’s not going to last forever. The only way it can last forever is if the regulated states overbuild into perpetuity by a sufficient margin that they can meet the resource adequacy needs of their neighbors” in Illinois and Michigan, the two MISO states with retail competition.
Spees said she sees promise in the concept of setting up a PJM-like forward capacity market for the states with retail choice.
Marka Shaw, a director of wholesale market development for Exelon, also criticized MISO’s structure, saying it is not only unable to attract new entry but also provides insufficient revenue to cover expenses for existing baseload generation, such as Exelon’s Illinois nuclear fleet.
Kruse and others agreed that MISO’s capacity prices are too low, with some noting that the $150/MW-day price seen in Illinois Zone 4 in the most recent auction — which sparked complaint to the Federal Energy Regulatory Commission last week — is less than two-thirds of the $247/MW-day cost of new entry in the zone. (See Public Citizen to FERC: Investigate Dynegy Role in MISO Capacity Price Jump.)
Gas vs. Nuclear
But Kruse’s Calpine colleague, Joe Kerecman, jumped into the discussion from the audience to criticize what he called Exelon’s request for “out-of-market subsidies.” Exelon has been lobbying for the Illinois legislature for a bill that would charge Illinois electricity users a fee to ensure continued operation of three nuclear generators that the company says are unprofitable. On Monday, Exelon acknowledged that the legislation would not pass during the current legislative session.
“These plants are also getting old,” Kerecman said, accusing Exelon of abandoning its support for competitive markets. “There’s a fallacy that they won’t get replaced.”
“Clinton [one of the generators Exelon says is losing money] is one of our newest plants,” Shaw shot back.
Shaw found support in Spees, who said the relief nuclear operators are seeking is to address the unpriced cost of carbon emitted by coal and natural gas plants. “That’s a market failure,” she said.
Maggie Henry, a 61-year-old organic farmer from Western Pennsylvania, never expected to become a protester.
“I was happy working like a mule to produce food for my community,” she said.
Henry collects eggs on her organic farm in Pennsylvania. (Source: “Gas Rush Stories” documentary by Kirsi Jansa)
Her 100-acre farm in Bessemer, near the Ohio border, produced eggs, meat and vegetables for top restaurants in Pittsburgh, including the Fairmont Hotel, the Enrico Biscotti cafe and Crested Duck Charcuterie. Over four years it grew from six to 400 chickens. “I had a thriving business going! It was all I could handle,” she said.
But after a shale gas operation began drilling in a neighboring farm in 2010, she says, her life changed.
Her farm, which has been in her family for almost a century, is located above an historic oil field. Plugged wells can serve as pathways for methane and other pollutants, allowing them to seep to the surface and into aquifers.
She has a monitor that measures particulate matter that is “off the charts all the time.”
“The toxicity of the air and the contamination of the water is absolutely unbelievable,” she said. “People are covered with rashes and blisters. They experienced all sorts of neurotoxic symptoms. Their children suffer nose bleeds and asthmatic reactions.”
She blames drilling in the Utica shale for a series of earthquakes in March 2014 that she says cracked her basement foundation, drywall and chimney pipe. “When it rains, water pours through my basement wall,” she said. “That never happened before.”
In February, two pigs and a cow unexpectedly died within two and a half weeks of each other.
A year ago, she told her story in a documentary. And on May 14, she traveled to D.C. to attend the Federal Energy Regulatory Commission’s open meeting, becoming one of three protesters to evade a security dragnet and enter the meeting room. (See Another Meeting Day, Another Drama at FERC.)
She stood up at the end of the session, shouting “In the shale plays of Pennsylvania, you are killing people!”
She mentioned Terry Greenwood, a farmer who she said “made a chilling prediction years ago. He said, ‘First it is the animals, then it will be the people.’ We buried him in June of last year, the victim of a rare form of brain cancer,” she said.
After the FERC meeting, Chairman Norman Bay called the protesters’ repeated interruptions of the commission’s meetings “disrespectful” and noted that it is the states — not FERC — that regulates fracking.
Henry insists FERC shares responsibility because it has approved liquefied natural gas export terminals. “They are poisoning us so they can make more money selling this fracked gas overseas,” she said. “No way am I going to permit this. I intend to give voice to the struggle every chance I get.”
She stopped farming her land after the 2013 harvest, no longer able to guarantee that her products were pure.
“I don’t care about anything [else] anymore,” she said Tuesday morning, shortly before marching to FERC headquarters again with other protesters. “I have been radicalized.”
ATLANTIC CITY, N.J. — PJM’s Annual Meeting last week marked a number of milestones: It was the largest yet, with 525 attendees, and it heralded the end of CEO Terry Boston’s eight-year tenure as well as the retirement of PJM employee No. 13, Jim Kirby, after half a century.
In remarks at the Members Committee meeting that ended the three-day event, Boston employed his trademark humor. During Superstorm Sandy, Boston said, “We got caught with our plants down.”
He noted the flat demand for electricity, saying, “The load forecast is the lowest in my entire career.”
He followed that with discussions of extreme weather; the world’s largest fuel switch to low-carbon sources; the integration of demand response; and the need for more high-voltage direct current transmission.
“If we’re smart, over this next century we’ll focus on the electrification of automobiles,” Boston said, noting the rise in EV sales in the PJM footprint from nearly nothing in 2010 to about 28,000 in 2014.
He juxtaposed industry predictions from 15 years ago with the state of the market today to underscore the need to keep a balanced generation portfolio.
Fifteen years ago, he noted, gas-fired plants were to be avoided, with their high, volatile fuel prices. Wind and solar were absent from long-range plans. “The resiliency of the future is what we’re here to protect,” said Boston, who closed to a standing ovation.
“Thank you for your great and unique style of leadership,” Board of Managers Chairman Howard Schneider said, calling Boston’s tenure, “an incredible career that has improved the lives of millions of Americans.”
“Andy has led or has been intimately involved in every facet of PJM’s mission during his 18-year career at PJM, and prior to that at [General Public Utilities Corp.],” Schneider said.
Ott praised Boston for building a culture of openness and consensus-building at PJM. “You set a standard when you came on board,” Ott said. “You set an example for us all.”
Ott promised to continue Boston’s tradition, saying “I value diversity of opinion, diversity of thought.”
He added that he would work to help PJM “be more nimble, more innovative as we go forward.”
