Page 1788 – RTO Insider

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

ISO-NE CEO: Despite Mild Winter, Region Still Needs Infrastructure

By William Opalka

The mild winter that has moderated energy prices in New England shouldn’t lull policy makers into complacence about the region’s infrastructure needs, ISO-NE CEO Gordon van Welie said last week.

In a Jan. 21 presentation to the media on the state of the energy market, van Welie acknowledged that this winter has been warmer than the previous two, resulting in less demand for power and natural gas and a reduction in pipeline constraints.

“But this is New England,” van Welie said. “Winter’s not over yet, and a mild winter or two doesn’t guarantee we won’t have extremely cold winters again.”

The increasing reliance on natural gas-fired generation and retirements of oil- and coal-fired power plants have created “an urgent need for more energy infrastructure,” he said.

ISO-NE began a winter reliability program for 2013-2014 that was essentially repeated for the current season. That supplemental program provided financial incentives for oil-fired generators to store more oil than they otherwise would have. It has encouraged dual-fuel capable generation that can switch from gas to oil.

Although the RTO has added $7 billion in transmission since 2003 and has generation projects totaling about 9,500 MW in its transmission queue, plant retirements are causing localized stresses.

“We’re already seeing worrisome conditions in greater Boston, with the recent retirement of the Salem Harbor station and delays in development of the proposed Footprint natural gas power plant. That area will be short of needed resources as soon as 2016,” van Welie said.

Southeastern Massachusetts and Rhode Island also are areas of concern, with Brayton Point’s planned retirement in 2017.

In addition, the RTO hasn’t been able to add natural gas pipeline capacity fast enough to react to increased power and heating demand.

For each of the last three winters, natural gas prices have risen steeply, showing the effects of increasing pipeline constraints. On Jan. 1, 2014, the spot price for natural gas in New England was nearly $20 higher than the price paid in most of the country.

“They were not only the highest forward prices in the U.S.; at the time, they were the highest on the planet,” van Welie said.

He said ensuring the reliability of the power system will likely require more gas pipelines, more liquefied natural gas storage and more transmission lines.

“The region faces a conundrum: who will be the customer to ensure new gas infrastructure is built? Will it be end-use electricity consumers or electricity producers — that is, generators?” he asked. “Thus far, electric generators have not signed up for additional gas infrastructure and as a result, the New England states have been considering making an investment in additional gas infrastructure on behalf of consumers.

“Until more infrastructure is added, consumers can expect volatile pricing for both natural gas and wholesale power, with price spikes when either the pipeline or power system is operating under stressed conditions,” he said.

January 27, 2015January 29, 2024

DOE-Funded Report Suggests ‘ISO’ for Gas-Electric Communications

By William Opalka

(Click to zoom.)

A U.S. Department of Energy-funded study on gas-electric coordination suggests natural gas pipeline operators create an independent system operator (ISO) to coordinate communications with electric grid operators.

The proposal is one of nine recommendations in a white paper on long-term electric and natural gas infrastructure requirements, conducted by the Illinois Institute of Technology for the Eastern Interconnection States’ Planning Council (EISPC) and the National Association of Utility Regulatory Commissioners. Although dated November 2014, the report was released by NARUC only last week.

Most of the report’s other recommendations — such as aligning daily gas and electric market schedules, building more pipelines to serve growing electric load and improving training — have been under discussion or development by industry participants for more than a year.

For example, in November 2013, the Federal Energy Regulatory Commission approved a rule allowing pipeline operators to exchange non-public operational information with RTOs. (See FERC OKs Gas-Electric Talk.)

But the report notes that while public domain information “is generally shared between pipeline operators and ISOs,” concerns about proprietary information remain.

“[E]stablishing a coordinator in the natural gas industry that could directly communicate with ISOs through appropriate protocols could be an option to solve the confidentiality problem and enhance the information sharing in natural gas-electric system planning,” the report says.

The recommendation doesn’t go as far as those from some other commentators, who have suggested a “Regional Pipeline Organization” or a centralized gas trading platform. (See Gas Trading Platform Finds Few Takers at Moeller Meeting.)

The report also calls for integrating natural gas availability into the North American Electric Reliability Corp.’s long-term and seasonal reliability assessments and for improvements to NERC’s Generator Availability Data System to better track generator outages resulting from a lack of gas supply.

The EISPC, which is funded by the Department of Energy, is a consortium of state-level agencies responsible for siting electric transmission across the 39 states in the Eastern Interconnection.

EISPC President David Boyd, a member of the Minnesota Public Utilities Commission, said the report will help regulators overcome challenges of the electric industry’s increased dependence on pipelines.

“As this report spells out, there are a number of differences between the two industries that, if not reconciled, could have unintended consequences for consumers,” he said in a statement.

January 27, 2015June 15, 2023

FERC Denies IMEA Request for Extended Waiver on Capacity Obligation

By Suzanne Herel

The Federal Energy Regulatory Commission on Thursday rejected the Illinois Municipal Electric Agency’s request for an extended waiver that would allow it to use capacity resources outside of the Commonwealth Edison Locational Deliverability Area to meet its internal resource requirement in serving its Naperville, Ill., load. (ER14-1681-001).

Last May, FERC granted IMEA a waiver for the 2017/18 delivery year after the ComEd LDA last year was modeled for the first time with a separate variable resource requirement curve (ER14-1681).

In June, IMEA asked FERC to clarify that the waiver extended beyond the one delivery year to the “term of the life of IMEA’s resource investments and commitments or at a minimum for the five-year minimum term of the [Fixed Resource Requirement] Alternative.”

Without a waiver, IMEA said it will be subject to unnecessary financial risks in any delivery year for which PJM uses a separate VRR curve, estimating the annual penalty charges at $100 million.

In its Jan. 22 order, FERC said it approved the one-year waiver because the short notice of PJM’s announcement to establish the separate VRR curve left IMEA little time to prepare to meet the internal resource requirement. “For subsequent delivery years, IMEA has sufficient time to prepare for the requirements of the FRR Alternative,” the commission said.

While IMEA contended that a longer waiver would have no adverse effects, FERC said it could expose customers in the ComEd LDA to higher prices because the aggregate internal resource requirement would need to be increased in future delivery years.

If IMEA decides not to continue under the FRR Alternative, FERC said, it could seek early termination from that status for the Naperville load and instead participate in PJM’s capacity auctions.

FERC’s ruling does not bode well for the waiver request IMEA filed earlier this month for this May’s Base Residual Auction (ER15-834).

But it may get some relief from PJM.

In December, stakeholders agreed to a problem statement proposed by Vice President of Market Operations Stu Bresler to review modeling practices that he said may be shortchanging loads with transmission agreements that pre-date the RTO’s capacity market. (See PJM MIC OKs Capacity Transfer Rights Query.)

Members approved a related issue charge earlier this month, agreeing to consider adding a mechanism in the capacity market similar to one used to allocate auction revenue rights to historical transmission paths in the energy market.

January 27, 2015

States, LSEs Skeptical, Utilities Split Over Capacity Performance

By Suzanne Herel, Michael Brooks and Rich Heidorn Jr.

More than 60 parties filed comments or protests in response to PJM’s Capacity Performance proposal before last week’s deadline, with states and load-serving entities expressing skepticism over the need for a major overhaul and generators split over elements they like and others they insist must be changed.

The Electric Power Supply Association, which represents generators, was singularly conflicted, saying it “generally supports” the proposal, but joined with other generators in complaining that the proposed changes to force majeure provisions were unduly punitive.

EPSA also joined states and LSEs in criticizing the limited stakeholder input before PJM’s Board of Managers made its unilateral filing with the Federal Energy Regulatory Commission on Dec. 12. But the association said implementation of the new structure should not be delayed by needed changes.

In a 51-page filing, PJM’s Independent Market Monitor said it “strongly supports” the proposal but listed numerous changes it said were needed to prevent market manipulation and clarify the oversight roles of PJM and the Monitor.

Most other commenters fell clearly into camps of supporters or opponents.

PJM’s proposal would increase the reliability expectations of capacity resources with a “no excuses” policy. It is expected to result in both larger capacity payments and higher penalties for non-performance. (See What You Need to Know about PJM’s Capacity Performance Proposal.)

The details are outlined in nearly 1,300 pages filed in two dockets:

EL15-29 contains proposed changes to PJM’s Operating Agreement and Tariff “to correct present deficiencies in those agreements on matters of resource performance and excuses for resource performance.”
ER15-623 proposes changes to the Reliability Pricing Model rules in the Tariff and Reliability Assurance Agreement.

Below is a summary of the main arguments presented in the comments.

Supporters

Those supporting the proposal included the Natural Gas Supply Association, America’s Natural Gas Alliance and the Energy Storage Association.

“The Capacity Resource Performance provision would begin to address PJM’s current difficulties by incenting investments by generators that would help them perform more reliably and economically even during periods of peak demand,” said the Natural Gas Supply Association, which represents gas producers and marketers.

The Energy Storage Association lauded the proposal as an opportunity for energy storage resources to participate in PJM’s capacity market.

Exelon said it “strongly agrees with PJM on the urgent need” for the changes to address “an imminent reliability crisis due to a capacity market design that fails to ensure that generators who have made capacity commitments actually perform when they are needed.”

Exelon, the nation’s largest nuclear operator, stands to benefit perhaps more than any other market participant from the proposal’s incentives to ensure generators have secure fuel supplies.

Penalties, Force Majeure

Unlike most other generators, Exelon complained that PJM’s proposed non-performance penalties were too lax. It said the RTO’s method for determining the hourly penalty rate is flawed and will result in much lower penalties than intended. It also called on the commission to clarify that a forced outage due to fuel unavailability during emergencies, or “performance assessment hours,” will result in automatic referral to the commission for violation of the Tariff.

Other generators complained that the penalties are already too harsh.

“Redefining force majeure to apply only when catastrophic conditions occur over the entire PJM region is unnecessarily broad and, as applied, too punitive to generators,” the PJM Power Providers (P3 Group) said. “Notwithstanding the most prudent investments, it is nonetheless impossible for every generator to foresee every eventuality. Equally as important, it is illogical to apply a penalty for nonperformance of a generator based on the requirement that the entire PJM operational system would need to be negatively impacted.”

Not Enough

American Electric Power, Dayton Power and Light, FirstEnergy, Buckeye Power and East Kentucky Power Cooperative also called for a reduction in proposed non-performance penalties in a 186-page filing.

The group, filing as the PJM Utilities Coalition, said the proposal is insufficient to correct a revenue inadequacy problem that they said is threatening reliability. They said that the proposal fails to eliminate incentives for bidding as a price-taker and that clearing multiple products simultaneously with different performance obligations will result in price suppression.

Too Much, Too Expensive

Load-serving entities, however, complained that PJM’s redesign is overkill and will result in unnecessary price increases.

“Capacity Performance is too much, too quickly, for no clearly stated reason,” the Old Dominion and Southern Maryland electric cooperatives said in a joint filing with American Municipal Power.

The Transition Coalition — whose members include the PJM Industrial Customer Coalition, cooperatives and other load-serving entities — said its members estimate the proposal would cost as much as $2.8 billion in the 2016/17 delivery year and $3.6 billion in the 2017/18 delivery year. “What will we get in return for billions of dollars in new payments?” it asked.

Similarly, Pepco Holdings Inc. said PJM should be required to provide a more thorough analysis of its proposal’s impacts, including costs and benefits.

Some commenters took aim at the transition provisions that would apply to resources that clear in the base capacity auctions this May and in 2016.

“Acceptance would constitute retroactive ratemaking,” the Retail Energy Supply Association said, while Direct Energy maintained the transition mechanism contained “billions of dollars in unforeseen costs on the region.”

Impact on Renewables

Public interest organizations said that renewable, energy efficiency and demand response resources would be disadvantaged by the new market structure, concerns echoed by the American Wind Energy and Solar Energy Industries associations.

The Environmental Defense Fund, the Natural Resources Defense Council, the Sierra Club, the Sustainable FERC Project and the Union of Concerned Scientists filed a joint protest, calling on FERC to either reject the proposal, set it for evidentiary hearing or exempt non-fossil fuel resources from the proposed penalties.

“Unlike fuel-based generation, renewable generation and non-fuel-based demand-side resources cannot become available all year round through upgrades, and cannot avail themselves to the benefits of being able to firm up fuel supply and pass associated costs to consumers accorded to fuel-based generation under this rule,” the group said.

States: Evidentiary Hearing Needed

The concerns of the states within PJM’s territory differed, with some warning of higher rates and others complaining the proposal violates state resource planning authority. Almost all states, even those who generally support PJM’s overhaul efforts, said the proposal needed changes as a result of it being rushed without adequate stakeholder input. Many also called for FERC to hold an evidentiary hearing.

The Organization of PJM States Inc. (OPSI) said it could not determine the need for the proposal or whether it would result in just rates because PJM had not provided sufficient analysis.

“To better quantify the impact of the proposal on customers’ rates, and on system operations and grid reliability … requires the development, presentation and evaluation of data that have not yet been provided by PJM.”

Capacity Performance is “Overreaction”

Some stakeholders also said the proposal changes more than is necessary.

The Delaware Public Service Commission called the proposal “an overreaction” to the poor generator response in January 2014. “All stakeholders should have an opportunity to fully evaluate the [proposal] before it is implemented with undeterminable and questionable costs and unquantified benefits,” it said.

In a joint protest, consumer advocates in Maryland, New Jersey, D.C., Delaware, Ohio and Illinois, along with the PJM Industrial Customer Coalition, said the proposal is “unnecessarily costly and disproportionate to the level of changes that are required. The sole focus should be on revamping the structure of penalties that applies to cleared capacity resources, to align actual performance with the level of revenue that cleared capacity resources currently receive.”

The Illinois Commerce Commission agreed. “Addressing deficiencies revealed by 2014’s winter conditions is a critical need, but the [proposal] goes far beyond addressing the specific issues that likely contributed to poor generator performance during this period,” the ICC said. “Rather, the [proposal] represents an extensive revision and, in some of its elements, is an unnecessary reworking of the RPM model.”

The Pennsylvania Public Utility Commission said it supports PJM’s changes to generators’ performance requirement. But it said FERC should “reject or modify the other changes to PJM’s Tariff filing wherein PJM seeks to unilaterally and, without stakeholder support, alter the provisions of RPM that have developed through much deliberation by FERC, PJM and stakeholders and that contribute to the functioning of healthy wholesale markets.”

For example, the PUC said it was concerned that how PJM defines what qualifies as a Capacity Performance resource would affect DR resources. “The characteristics of DR providers are not compatible with PJM’s proposed trading restrictions and should be eliminated for these types of resources given the fundamental nature of the underlying characteristics of residential, business and industrial customers,” the commission said.

January 27, 2015

SPP, MISO Move Ahead on Flowgate Rules

By Chris O’Malley

The Federal Energy Regulatory Commission last week approved SPP’s market-to-market coordination rules with MISO, after the two RTOs resolved an earlier dispute over the creation of flowgates (ER13-1864).

SPP had originally proposed restrictions on the right of either RTO to designate a new M2M flowgate — transmission lines or transformers monitored for overloads — outside of their mutually agreed-upon scheduling timeframes.

SPP would have allowed the creation of flowgates during extenuating circumstances or when the RTO seeking a new designation compensated the other for any re-dispatch that resulted.

PJM and Exelon filed comments supporting SPP’s position, with Exelon noting that MISO created 500 new flowgates between September 2011 and October 2012, while PJM designated only 80. SPP’s transmission owners also supported the restrictions, citing the administrative burdens of complicated resettlement processes related to re-dispatches.

MISO and its Independent Market Monitor opposed SPP’s proposal, which they said would effectively give one RTO veto power. The Monitor noted that M2M flowgates are dynamic, responding to changes in outages and constraint definitions.

Compromise Reached

Following a technical conference last September, SPP agreed to drop its prohibition in a compromise with MISO. The RTOs agreed on new language, which FERC accepted in last week’s order, spelling out the conditions under which one RTO will be compensated by the other for costs stemming from flowgate designations.

In its Jan. 22 order, the commission also agreed to allow the two RTOs to defer a day-ahead firm-flow entitlement exchange process until they decide whether its implementation outweighs its costs.

FERC also ordered SPP to report back to the commission every six months on its progress resolving concerns over interface bus modeling methodologies. The MISO Monitor says disparities in the methodologies used by MISO and PJM is resulting in double counting of congestion. (See related story, Patton Asks FERC to Set Deadline on PJM-MISO Interface Pricing Dispute.)

Noting that PJM and MISO have been unable to resolve their differences over two years of discussions, the commission said “we anticipate … that SPP and MISO could face technical challenges in identifying the appropriate pricing methodologies.”

MISO-SPP Flow Dispute not Affected

The order does not affect a separate dispute between MISO and SPP over flows between MISO’s northern and southern regions. MISO began limiting flows between the regions last spring after SPP complained that MISO breached their joint operating agreement by moving power over its transmission footprint in excess of a 1,000-MW physical contract path.

The commission said that issue, the subject of a separate docket (EL11-34), was beyond the scope of this proceeding.

January 27, 2015June 15, 2023

Patton Asks FERC to Set Deadline on PJM-MISO Interface Pricing Dispute

By Chris O’Malley and Michael Brooks

WASHINGTON — MISO’s Independent Market Monitor urged the Federal Energy Regulatory Commission last week to resolve a standoff between MISO and PJM over interface pricing that he said is costing consumers millions.

“We’re seeing tens of millions of dollars in uplift. We see transactions being scheduled that are not efficient. And the only way to really solve this is to get prices right,” MISO Market Monitor David Patton told commissioners during a panel discussion with RTO representatives and state regulators at FERC’s Jan. 22 meeting.

But PJM Market Monitor Joe Bowring and Stu Bresler, PJM vice president of market operations, said pressure for an immediate resolution could be short-sighted. “We have to be careful an arbitrary deadline does not force a bad answer rather than getting to the right answer,” Bowring said.

“I think a deadline that required a solution in a very near timeframe would be very difficult and potentially damaging if it resulted in an inferior approach,” agreed Bresler.

Whether the commissioners will set a deadline to help spur a resolution is unclear.

“I think we want to distill what we have heard today and get the sense of where the commissioners are,” Chairman Cheryl LaFleur said at a press conference following the meeting.

Two Years

MISO and PJM have been working for two years to resolve differences in the way they price transactions at interface buses.

The RTOs agree that the current methods undermine efficient scheduling of power because they cause both RTOs to model the same constraint, resulting in double-counting.

Patton says transactions are overcompensated when they are expected to relieve a constraint, and overcharged when they are expected to contribute to congestion. Interface pricing flaws “cost MISO some money. It costs PJM a huge amount,” he said.

Patton contends that PJM’s method exaggerates the effects of imports and exports on transmission constraints near the seam. As a result, he said, scheduling incentives have been inflated by as much as 600% at the Cook-Palisades interface in Michigan, the most active M2M constraint last winter.

“We massively overpriced congestion last winter and it resulted in an average of something like 3 GW being exported from PJM to MISO. This was during the timeframe when we were just coming out of the polar vortex and PJM had just incurred half a billion dollars in uplift, committing tons of generation under conservative operations, and they’re exporting gigawatts to MISO, where it’s demonstrably less valuable,” Patton added.

Bresler said he didn’t see the correlation. “PJM has made changes to its interface definitions in direct response to concern from MISO. Given the change we made, I’m not sure I understand the reference … to the polar vortex and the uplift,” he said.

Patton recommends removing the congestion component of the LMP for the non-monitoring RTO.

PJM offered an alternative in which each RTO would set its interface bus price relative to a common set of interfaces.

FERC to Set Deadline?

Patton said FERC should set a deadline for an agreement because there have only been two solutions under consideration for more than a year.

“We’ve had an incredible amount of analysis on those two solutions. Obviously, I think there’s one clearly correct answer, but not everyone agrees with me,” he said to laughter. “I think if we did have a deadline to file, it would be useful just to file and say ‘We’re agreeing to disagree, and here are the pros and cons of these two solutions that we have an enormous amount of research on, and then allow the commission to maybe weigh in and give some guidance and push the needle in one direction or the other.”

“We really need FERC’s involvement in this issue. We need a deadline to file a solution to this,” Patton told commissioners.

Bowring said he didn’t think a hard deadline made sense, although he suggested the RTOs could report back to the commission in June. “If we knew the answer, we would have told you already. We don’t.”

Bresler said Patton’s proposed solution to interface pricing could have negative impacts elsewhere.

“PJM has always defined our interface prices so that we reflect the impact of interchange transactions on the transmission system and more specifically on the transmission constraints which we are actually operating,” Bresler said. “And part of the solution that Dr. Patton has proposed is essentially eliminating the impact of some transmission constraints in the interface price.

“That may end up being the right solution,” Bresler added. “But I think the difficulty … is making sure that doing so doesn’t have detrimental effects elsewhere.”

LaFleur expressed frustration with the inability of the two RTOs to resolve the impasse.

“I am at least actively contemplating, should we do something more active than ask for another schedule, which is what we decided to do [in 2013] after a lot of tough talk,” she said. She acknowledged work done by the RTOs to address seams issues but added, “I’ve been a little disappointed with the level of progress on some of the thorniest issues, many of which have come before us today.”

Commissioner Philip Moeller said the problems are “partly our fault.”

“We kind of took our foot off the gas and stopped requiring the quarterly reports and basically lost focus on the fact that these issues were not going away,” he said.

Michigan Public Service Commissioner Greg White, another panelist, agreed a deadline could increase the parties’ “sense of urgency” but said he didn’t want to “end up with a product that is inferior because of a lack of time.”

Joint and Common Market Progress

The bus interface pricing issue has proven to be perhaps the most intractable issue facing PJM and MISO’s Joint and Common Market initiative, a joint stakeholder process to address seams issues.

Patton said the JCM process has borne fruit. He said MISO’s ability to export capacity into PJM has increased, although the two parties haven’t solved the underlying problems. “So while I don’t think we structurally have solved the problem and I don’t see a filing coming any time soon that will structurally solve this, I think the priority has diminished.”

Bowring was unapologetic. “There will continue to be issues as long as there are very substantial differences between the design for procuring capacity in MISO and the design for procuring capacity in PJM,” he said. “The … notion that there should be transfers no matter what I think is excessively simple-minded.”

Elizabeth Jacobs, chair of the Iowa Utilities Board, who represented the Organization of MISO States on the panel, said she was encouraged by MISO and PJM’s plans to introduce Coordinated Transaction Scheduling to improve interchange optimization. (See “PJM Posts MISO Price Predictions Before CTS Vote” in Market Implementation Committee Briefs, Jan. 12, 2015.) Jacobs noted that while the panel discussion focused on the PJM-MISO seam, many MISO members are facing new seams issues with an expanded SPP.

January 27, 2015

FERC to Tighten Policy on Hold Harmless Merger Commitments

By Rich Heidorn Jr.

The Federal Energy Regulatory Commission said last week that it intends to tighten the rules on the use of “hold harmless” commitments in support of merger applications and will prohibit commitments that are limited in duration, which could leave ratepayers vulnerable.

In a proposed policy statement (PL15-3), the commission said it was better defining the costs subject to such commitments and the accounting methods used to track them. The commission will accept comments on the proposal, which it called a reaffirmation of its 1996 Merger Policy Statement (Order 592), for 60 days.

FERC noted that hold harmless commitments — agreements not to seek recovery of transaction-related costs in rates unless they are offset by transaction-related savings — have become a common feature of merger applications under section 203 of the Federal Power Act (FPA) over the last decade.

The commission said, however, that “it has never defined those costs with much specificity, leading to inconsistency with respect to this issue.”

The policy statement’s definition includes the costs of consummating a transaction (e.g., legal, investment advisory, accounting and financing costs) and the capital and operating costs incurred to achieve merger synergies (e.g., severance payments, accounting and operating systems integration costs).

The commission said requiring applicants to explain how they track the costs will help ensure that they are not recovered in rates without commission approval.

Time Limits

The Merger Policy Statement requires that hold harmless commitments must protect customers “for a significant period of time following the merger,” a period that the commission has typically defined as five years.

FERC said it now realizes that such a limit “raises the risk that transaction-related costs could be included in future formula rate billings without applicants making the showing of offsetting savings.”

The commission said its concern arose from its experience auditing utilities with hold harmless commitments, the concerns of protestors in previous merger applications and the proposed treatment of certain categories of costs.

“For example, an applicant could try to include transaction-related costs in formula rates without making a showing of offsetting savings if the costs, though incurred during the hold harmless period, do not enter the ratemaking process until after the hold harmless period expires … Similarly, limiting the applicability of hold harmless commitments to specific time periods may incentivize applicants to delay incurring some types of transaction-related costs until after the hold harmless period expires.”

The new policy, FERC said, ensures “that the focus of a hold harmless commitment [is] on whether a cost is transaction-related, and not on when the cost is incurred.”

FERC also said removing the time limit will ensure proper treatment of costs that should be capitalized as an asset during the hold harmless period, but whose cost recovery would occur as the asset is depreciated over future periods that extend beyond the hold harmless period.

Changes are Prospective

The commission also reiterated its opposition to including acquisition premiums as transaction-related costs. It said it would continue to require a showing of “specific, measurable and substantial benefits to ratepayers” for recovery in a subsequent FPA section 205 proceeding.

FERC said the policy changes would apply prospectively and would not affect existing commitments or pending merger applications.