ISO-NE Opens FCA 9 amid Expectations of High Prices

By William Opalka

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).

FERC, which has asked the Supreme Court to reconsider the ruling, rejected the generators’ challenge last month (ER15-257). (See FERC Approves New England Demand Response Integration.)

[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.]

February 3, 2015

MISO Planning Advisory Committee Briefs

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.

February 3, 2015June 15, 2023

FERC Questions NYISO Plan to Terminate Generators’ Interconnection Rights

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.

February 3, 2015June 15, 2023

MISO Reliability Subcommittee Briefs

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 standard was approved by the Federal Energy Regulatory Commission in January 2014. (See FERC OKs Rules on Geomagnetic Disturbances, Frequency Response.)

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.

FERC approved the standard, the first phase of rules to protect the grid from GMDs, in June. (See FERC OKs GMD, Training Standards; Proposes Modeling Rule Change.)

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.

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.

February 3, 2015June 15, 2023

Entergy Out-of-Cycle Transmission Request Draws Competitors’ Ire

By Rich Heidorn Jr.

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.

February 2, 2015June 15, 2023

PJM: Gates’ Trades Cost Exelon, AEP, Dominion $1M Each — UPDATED

By Ted Caddell and Rich Heidorn Jr.

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.

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 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

powhatan energy fund — 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.

January 27, 2015June 15, 2023

Gates, Powhatan Say FERC Enforcers Didn’t Share Crucial Info

By Ted Caddell

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.)

utc — 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.

January 27, 2015

CRUTHIRDS AT LARGE: La. PSC Questions Tx Spending

By David L. Cruthirds

Members of the Louisiana Public Service Commission last week expressed concern with the adequacy of the transmission construction MISO has planned for their state, which is seeing a surge in industrial development thanks to low natural gas prices.

MISO officials briefed the commissioners on the RTO’s 2014 Transmission Expansion Plan (MTEP) — the first transmission planning cycle to include the full participation of the MISO South Region — at the commission’s monthly Business & Executive (B&E) meeting in Baton Rouge last week.

The presentation by MISO’s outside counsel David Guerry and Patrick Brown, executive director of transmission asset management for MISO South, also included discussion of MTEP 2015.

MTEP 2014, approved by MISO’s board last month, included 369 projects totaling $2.5 billion.

MISO South (Arkansas, Louisiana, Mississippi and Texas) received $359 million, including 29 projects in Louisiana at an estimated $182 million. Distribution ($64 million), economic ($56 million) and baseline reliability ($41 million) projects dominate the work in Louisiana, with other reliability projects adding $17 million and “relaying” projects at $2 million.

MISO didn’t perform any calculations on projected rate impacts because the projects are deemed local and thus not eligible for regional cost allocation, Brown said.

Assurances Sought — and Obtained

Several commissioners asked for assurances that MISO will build enough transmission to serve Louisiana’s industrial growth. A state economic development report released last month found Louisiana ranked second in the South and fifth in the nation in private-sector job growth rate since 2008.

Commissioner — and gubernatorial candidate — Scott Angelle said he expected the transmission investment in Louisiana to be higher in light of the industrial expansion.

Commissioner Eric Skrmetta expressed concern about the WOTAB (West of the Atchafalaya Basin) and Amite South load pockets, saying that the Louisiana Energy Users Group (LEUG), which represents industrial customers, is “hyper-interested” in reliability issues in Amite South.

Entergy attorney Karen Freese responded by noting that MTEP 2014 includes $56 million in projects to improve reliability and increase imports into the Amite South/New Orleans area. The projects should enhance generation deliverability in Amite South, especially for one large industrial cogenerator that is a member of LEUG, she said.

The Amite South projects showed a 6-1 benefit-cost ratio, Brown said. Guerry said such economic-based projects are exactly the kind of projects LEUG is seeking.

Freese, referring to evaluations by both SPP and Entergy, said that the proposed “Houma loop” project in southern Louisiana wasn’t economically justifiable.

Skrmetta wasn’t entirely satisfied, saying the commission wants the ability to order transmission construction if MISO isn’t doing what needs to be done. He also asked Entergy and LEUG to meet with him to discuss the issues in more detail.

Guerry noted the commission has a key role in the transmission construction process because it must approve siting and cost recovery. He also noted the MTEP 2014 projects are expected to be in service in 2018, which is before the industrial expansion projects are expected to be in operation.

MTEP 15

Guerry said that while there wasn’t much involvement by MISO South stakeholders in MTEP 2014, the RTO is seeing more robust participation in MTEP 2015.

MISO plans to continue promoting increased participation and wider acceptance of the MTEP process across the MISO South footprint. MISO will hold planning forums as well as workshops to promote stakeholder education and increased involvement in MISO’s planning processes.

As part of MTEP 2015, MISO is evaluating four projects proposed by Cleco Power and 35 submitted by Entergy Louisiana.

Lake Charles Project

The briefing included a description of $187 million in transmission improvements planned by Entergy Gulf States Louisiana for the Lake Charles area.

Entergy says the project, which includes two new substations, expansion of a third and 25 miles of 500-kV and 230-kV transmission, will support industrial expansion, improve reliability and provide Southwest Louisiana access to cheaper generation elsewhere in MISO. Pending LPSC approval, construction is scheduled to begin in 2016 with a projected in-service date in 2018.

“Nearly 500 MW of new load have already signed up for facilities in the Lake Charles area and the potential exists for another 500 MW that are in various stages of exploration by new or existing customers in that part of the state,” Gulf States CEO Phillip May said in a statement announcing the project Jan. 8.

The project is an “out-of-cycle” proposal and will receive expedited review outside of the usual MTEP process. MISO is sensitive to the need to serve economic growth, so it is assigning a higher priority and streamlining the process as much as possible, Brown said.

Lake Charles is expected to be the state’s fastest-growing region, with $81.7 billion in industrial project announcements projected to add 12,000 jobs over the next two years, a 12% increase, according to an October 2014 report by Louisiana State University economists.

[Editor’s Note: Author David Cruthirds provides general regulatory and government relations consulting services to Sempra LNG, whose Cameron liquefied natural gas terminal may receive benefits from the Lake Charles project.]

Load Growth in MISO North

Skrmetta asked about generation trends in MISO North. Brown said MISO is projecting resource shortages in certain MISO North zones due to the Environmental Protection Agency’s proposed carbon regulations. Skrmetta noted MISO North is benefitting from generation located in MISO South, so that needs to be considered in the transmission cost allocation process. Guerry assured him it was.

Holloway Named LSPC Chair, Angelle Vice Chair for 2015

The commission unanimously elected Commissioner Clyde Holloway as chairman and Angelle as vice chairman for 2015 on the motion of outgoing Chairman Skrmetta.

The vote came at last week’s B&E meeting, which Skrmetta chaired at Holloway’s request. Holloway made a brief statement, thanking his colleagues for their support and saying he wants to keep Louisiana’s rates “the lowest in the nation.” According to the Energy Information Administration, the state had the second lowest residential rates in the U.S. in October 2014, the latest data available, second only to Washington state. Louisiana ranked eighth for all sectors.

Skrmetta was unanimously elected as the commission’s representative to the Entergy Regional State Committee and the Organization of MISO States.

Commissioner Foster Campbell, reported to be ailing with the flu, did not attend the meeting.

January 27, 2015June 15, 2023

Company Briefs

The Federal Energy Regulatory Commission gave PPL a 10-day extension, until Friday, to prepare its mitigation plan for the proposed spinoff of its generating assets into a merchant power producer.

FERC had set a Jan. 20 deadline for PPL to respond to conditions the agency set for the new generating company, Talen Energy, which will be created from a combination of assets from PPL and Riverstone Holdings. PPL spokesman George Lewis said last week that PPL received the filing extension.

More: The Morning Call

Cape Wind Contracts Terminated, Company Suspended from ISO-NE

Troubled wind developer Cape Wind ended contracts to buy land and buildings in Massachusetts and Rhode Island and was suspended from participating in ISO-NE.

The announcements are the latest gloomy news for Cape Wind, whose power purchase agreements with utilities National Grid and NSTAR were terminated earlier this month. The utilities said they backed out because Cape Wind failed to meet financing and construction deadlines. Its 468-MW project has been in the planning and permitting stage for more than a decade.

ISO-NE notified the Federal Energy Regulatory Commission that it had suspended Cape Wind from its wholesale power market. Dennis J. Duffy, vice president of governmental and regulatory affairs for Cape Wind, said the suspension was a “nonissue” and that it would be reversed “well in advance” of the project beginning operations.

More: The Boston Globe

Amazon Commits to Indiana Wind Project to Power Data Centers

Amazon Web Services is teaming up with Pattern Energy Group to build a 150-MW wind farm in Indiana to provide electricity for a planned data center.

Pattern will construct and operate the 150-MW wind farm in Benton County, Ind. The facility will be called the Amazon Web Services Wind Farm, and it is scheduled to go into operation in a year. Amazon is catching up to Google and Facebook in a quest to power cloud-based web services with clean energy.

More: Gigaom

NRG Installs 24 Vehicle Chargers in Greater DC Area, More Coming

NRG Energy has installed 24 fast electric vehicle (EV) charging stations in the D.C. area, and another one is due to become operational later this month.

NRG’s eVgo subsidiary installs and operates the chargers. They allow for fast charging of vehicles, in some cases providing an 80% charge in 30 minutes.

More: pv magazine

Duke Energy Building 13-MW Solar Facility at Marines’ Camp Lejeune

Duke Energy is teaming with the U.S. Navy and Marines to construct and operate a 13-MW solar facility at Marine Corps Base Camp Lejeune near the North Carolina coast.

“Secretary of the Navy Ray Mabus set an aggressive but critical goal for the [Department of the Navy] to produce or procure 1 GW of renewable energy by the end of 2015,” said Robert Griffin, executive director of the Navy’s Renewable Energy Program Office.

The estimated $25 million to $30 million project, which would be built on about 80 acres, needs regulatory approval from the North Carolina Utilities Commission.

More: Charlotte Business Journal

End of Duke Power Contract Spells End for Carolina Plant

A North Carolina biomass energy plant has closed following the expiration of a power contract with Duke Energy.

Coastal Carolina Clean Power of Kenansville, which burned wood chips and scrap lumber to produce electricity, shut down after Duke declined to renew its contract because the electricity cost up to 200% of the price on the open market. The closing has left 17 people out of work.

More: WITN

Dominion Virginia Power Files to Build 20-MW Solar Plant

Dominion Virginia Power will build a 20-MW solar facility in Fauquier County, in Northern Virginia, its first commercial solar venture in the state.

The company, in a filing with the Virginia State Corporation Commission, said the $47 million plant is to be built on about 125 acres near its Remington Power Station. The plant would be financed by a surcharge of about 4 cents per month for a typical residential consumer during construction, and then drop to about 2 cents a month after the plant goes into service. The commission needs to approve the surcharge.

Dominion has about 344 MW of solar capacity in six states, but it was under pressure from environmentalists to build a project in Virginia, where it operates 18,366 MW of conventional power generation.

More: The News & Advance

Businessmen Sign Contract for Exelon’s Delaware Station

A developer and caterer are teaming up to buy the old Delaware Station generating plant on the Delaware River in Philadelphia, with an eye to develop two boutique hotels on the site.

Developer Bart Blatstein and caterer Joseph Volpe say they’ve signed a contract to buy the retired, Revival-style building on 1,000 feet of riverfront. They declined to comment on the price.

Exelon Generation spokesman Robert Judge confirmed a sales agreement had been signed but wouldn’t identify the buyers.

More: The Philadelphia Inquirer

Environmentalists, Property Owners Join Protest Against Atlantic Coast Pipeline

Dozens of environmentalists and property owners rallied at the Virginia State Capitol in Richmond against plans by Dominion Resources and other utilities to build a $5 billion, 550-mile natural gas pipeline across the state and into North Carolina.

The protesters, organized by the Sierra Club and Friends of Nelson, asked the General Assembly to block the Atlantic Coast Pipeline, which would carry 1.5 billion cubic feet of gas a day from Appalachian shale gas fields.

One bill before the legislature would repeal a 2004 law giving interstate gas companies the right to survey and test pipeline routes without property owners’ consent.

More: News Leader

NextEra to Develop Wind Energy on Hawaiian Parker Ranch Land

NextEra, which is acquiring Hawaiian Electric, has signed an agreement with the Parker Ranch Foundation Trust to develop wind farms on land the trust oversees on Hawaii Island.

The foundation began an effort in 2013 to look for a partner to help develop renewable energy on its holdings. “We have been aggressively seeking ways to reduce the cost of electricity for our community and our island by using the potential renewable energy resources available on PRFT’s Hawaii Island lands,” said Neil “Dutch” Kuyper, president and CEO of Parker Ranch.

Financial terms were not disclosed.

More: FierceEnergy; Parker Ranch

January 27, 2015June 15, 2023

FERC Rejects Challenge on PJM Capacity Import Limit

By Suzanne Herel

The Federal Energy Regulatory Commission last week denied a challenge to PJM’s capacity import limit, rejecting rehearing requests by American Municipal Power, the Northern Illinois Municipal Power Agency and the Illinois Municipal Energy Agency (IMEA) (ER14-503-002).

PJM sought the limit after imports nearly doubled in the May 2013 Base Residual Auction, leading some to question their deliverability.

The new rules, which FERC approved in April, created five export zones with a combined limit of 6,499 MW for the 2014 BRA. Cleared generation imports dropped to 4,526 MW in 2014, a reduction of almost 40% from 2013. (See Capacity Prices Jump Following Rule Changes.)

In requesting a rehearing, IMEA said there was no substantial evidence supporting the requirement that external generation resources be pseudo-tied to PJM to qualify for an exemption to the import limit. It also argued that the revisions discriminate against load-serving entities that own generation resources outside of PJM.

FERC said that PJM established that a pseudo-tie is needed to address the risk of curtailment, noting that firm transmission into PJM was curtailed under 151 transmission loading relief-5 events between January 2009 and July 2013. “The risk of a TLR-5 event interrupting the transmission of energy necessary in an emergency situation is a sufficient basis to justify the capacity import limit, since such a risk demonstrates that resources external to PJM may not be equal to internal resources in satisfying a capacity requirement,” FERC said.

It rejected IMEA’s discrimination claim, saying the import limits are analogous to capacity emergency transfer limits, which apply to internal generation.

FERC also rejected the allegation by AMP and Northern Illinois that it had approved the limit without a proper analysis of its effect on competition in PJM’s capacity market.

“We find that an over-commitment of external resources in the Base Residual Auction would run a deliverability risk and distort the Base Residual Auction process by displacing resources that are deliverable,” FERC said. “… Systematic commitment of external resources at levels that cannot be reliably delivered will add resources to the supply curve in the auction and tend to reduce the clearing price below the level offered by resources that are actually deliverable to PJM.”