Page 1592 – RTO Insider

January 13, 2015June 15, 2023

Stakeholder Process Under Attack at FERC Hearing on PJM Financial Trades

By Rich Heidorn Jr.

pjm — Market Monitors Joe Bowring (PJM, left) and David Patton (MISO, ISO-NE and NYISO).

WASHINGTON — The RTO stakeholder process came under fire last week as financial traders said it was being used to quash competition and a leading economist blamed it for slowing market reforms.

The setting was a Federal Energy Regulatory Commission technical conference, part of the commission’s Section 206 inquiry into PJM’s treatment of financial transactions (EL14-37).

Section 206 Inquiry

FERC opened the 206 case in August, ruling that PJM may be improperly discriminating in its disparate treatment of virtual transactions. While incremental offers (INCs) and decrement bids (DECs) are charged uplift and subject to the financial transmission rights forfeiture rule, up-to-congestion bids (UTCs) are exempt from both.

UTC trading volumes have dropped by about 80% since Sept. 8 — the date from which FERC said any uplift ultimately assigned to UTCs will be applied. (See PJM Traders Continue to Shun UTCs on Uplift Fears.)

PJM Market Monitor Joe Bowring and David Patton, Monitor for MISO, ISO-NE and NYISO, were among 11 panelists who spoke during the all-day session Jan. 7. They were joined by economists and representatives of several financial trading firms critical of PJM’s rules and Bowring’s interpretation of them. Commissioner Philip Moeller sat in for the afternoon session but asked no questions.

Bowring often found himself alone in defending his views. At one point, Patton waded into a debate between Bowring and Inertia Power’s Noha Sidhom over whether PJM’s enforcement method presumes collusion. After beginning by offering himself as a mediator in the disagreement, Patton ended by criticizing PJM’s method as “arbitrary and capricious.”

“If that’s mediation,” Bowring responded dryly, “I’d hate to see him take a side.”

2013 Tariff Revisions

In 2013, PJM proposed Tariff and Operating Agreement changes to redefine UTCs as virtual transactions and make them subject to FTR forfeitures (ER13-1654). The RTO said the change was justified by the evolution of UTCs from a congestion hedge for physical transactions to a purely financial product.

That didn’t go far enough for FERC, which said it had concerns about differences in the way PJM planned to apply the rule. The commission also questioned why PJM was not assessing UTC uplift charges even though the RTO believes the transactions contribute to uplift.

Last week’s conference featured debates over the similarities between UTCs and paired INCs and DECs, the need for the forfeiture rule, the impact of the decline in UTC trading and the ability to assess market players’ contribution to uplift.

William Hogan, research director of the Harvard Electricity Policy Group and an intellectual forefather of current RTO market designs, was highly critical of FERC for not asserting more leadership.

“I think FERC is not doing its job in setting priorities and … forcing these processes to create efficient markets,” he said. “And it’s deferring too much to stakeholder processes and bottom-up, consensus agreement. It’s a big mistake and it’s hurting us more and more.”

Anticompetitive Motives Alleged

Two panelists accused Bowring and large market participants of having ulterior motives in assigning fees to financial traders.

Sidhom said UTCs cannot bear uplift charges because their profit margins are thinner than those of INCs and DECs. The Monitor’s motive “is to kill the UTC product,” she said.

Wesley Allen of Red Wolf Energy Trading said the cost allocation resulting from PJM’s stakeholder process is akin to Microsoft assigning costs to Apple, with the large utility holding companies using their domination of the stakeholder process to crush competition from small financial traders.

“When it comes to allocation of costs, a Fortune 500 company can allocate some of their costs to another market participant and simultaneously eliminate their competition,” Allen said.

“The stakeholder process is not there to come up with the best results for the market,” he said. “The stakeholder process is about people — Fortune 500 companies largely, who control the voting — managing their costs as best they can. Eliminating their competition as best they can.”

Although the holding companies must select membership in a single sector for sector-weighted votes in PJM’s most senior committees, they have multiple subsidiaries that vote in the lower committees in several different sectors.

PJM, he said, is returning to its monopolistic past. “We’re getting there through the allocation of fees,” he said.

FTR Forfeiture Rule’s Genesis

PJM moved swiftly to implement the FTR forfeiture rule in December 2000, filing it for FERC approval just two weeks after discovering that some traders were using INCs and DECs to create artificial congestion.

The traders were using radial paths — ones designed for future growth, which have few or no network connections. “They would increase or decrease congestion to increase FTR revenues in locations where we never saw congestion before,” said Stu Bresler, PJM vice president of market operations. The traders didn’t mind losing some money on the virtual trades because they were making more on the artificially created congestion.

“It is about manipulation,” Bowring told the conference.

Traders: ‘Worst-Case’ Selection Unfair

Under the rule, traders of INCs and DECs forfeit profits on FTRs when their virtual trades increase congestion and day-ahead/real-time price divergence. PJM identifies offending trades by first screening for those deemed to be “at or near” the constrained FTR paths. Then it determines whether the participant’s FTR profits are likely to have increased as a result of the virtual transactions by determining whether the day-ahead congestion revenues on the FTR paths increased relative to real-time revenues.

To estimate the effect of a transaction on flows, PJM must identify both the source and sink buses of the transaction. But because INCs and DECs have only one bus, PJM must select a second bus to complete the analysis.

For the second bus, PJM uses what it deems the “worst-case” bus to determine the potential impact of the trade on the FTR path. The worst-case bus is the one that has the highest net distribution factor — the percentage of the total energy of the transaction that flows on the FTR path. Trades with distribution factors of 75% or higher are deemed “at or near” the constrained FTR paths. (The worst-case identification is not necessary for UTCs, which have explicit sources and sinks.)

Harry Singh of J. Aron and Co. told the conference that PJM’s method is unfair. “Power doesn’t sink at the worst-case connection,” he said.

Inertia Power’s Sidhom also was critical. By using the worst-case bus, PJM is often attributing to one trader the actions of another, she said.

“The fundamental flaw is taking another person’s transmission into consideration,” she said. “Don’t have a rule that I can’t screen for.”

Referring to calls to extend the rule to UTCs, she asked: “Do we want to take a flawed rule and apply it to another transaction?”

The financial traders found support from Patton and Bresler.

“PJM’s opinion at this point is that we probably went too far with that,” Bresler said, “because we’re evaluating one participant’s activity against somebody else’s, of which assumedly they don’t have knowledge.”

Patton said using the worst-case bus leads to one of two results. “It’s either irrelevant or it’s leading you potentially to a bad decision,” Patton said.

But Bowring was unyielding, saying it is better to err on the side of over-enforcement rather than under-enforcement.

“The consequences of over-mitigation are very small,” he said. “The consequences of under-mitigation are very large.”

Bowring also insisted the rule is more efficient than a case-by-case review.

Bowring has recommended modifying the rule by evaluating traders’ portfolios. He also favors applying the rule to UTCs and counterflow FTRs in addition to the prevailing-flow FTRs now covered.

Bresler said there is no need to subject counterflow FTRs to the rule. “It’s much more difficult to manipulate through counterflows,” he said. He said he has concerns that a portfolio approach would result in false positives — “catching too many fish in the net.”

No Forfeiture Rule in Other RTOs

Unlike PJM, NYISO, ERCOT and MISO do not have a forfeiture rule, and ISO-NE has one that Patton said is never applied. “Whenever we’ve looked at it we’ve found the costs outweigh the benefits,” he said. The fact that it took FERC several years to act against Louis Dreyfus Energy Services for using virtual trades to boost its FTR revenues “illustrates it’s hard to develop a bright-line test,” he said.

Patton said generic market manipulation rules provide sufficient protection against gaming of FTRs. The scheme, he said, is easy to spot. “I’m not worried about the bank robber who comes wandering in without a mask on and stands in front of the security camera. And that’s effectively the people who would be caught by this rule.”

Bresler said PJM favors replacing the worst-case test with the use of a load-weighted reference bus for INCs and generation-weighted reference for DECs.

Sidhom said she supported such a change. “We’re not that far apart on the forfeiture rule,” she said. “I really don’t know if we need wholesale changes here.”

Assessing UTCs for Uplift

The other major issue at the conference was whether UTCs should be assessed uplift charges. Bowring believes they should, saying the disparity in treatment is a major reason why UTC trading volumes have increased in recent years while INC and DEC trading has declined.

Stephanie Staska, chief risk officer for Twin Cities Power Holdings, said no virtual trades should be assessed for uplift related to “deviations,” a term she notes is not defined in the PJM Tariff.

Based on the dictionary definition — “an action different from what is usual or expected” — uplift is properly charged to those whose real-time physical positions differ from their day-ahead positions, such as load that is under- or over-forecast and generation and demand response that fails to meet the scheduled output.

In contrast, Staska said, traders entering into financial contracts receive both a day-ahead and a real-time position that cannot be cancelled or altered after the day-ahead market closes.

Bowring disagreed, saying virtuals affect dispatch and commitment decisions. The Monitor said UTCs were responsible for 64% of the deviations corresponding to negative balancing congestion in 2013 and INCs and DECs added another 24%.

Bowring said virtuals’ uplift “allocation should be reduced … but there’s no reason to exempt anyone, including UTCs.”

Bowring said billing UTCs $0.57 to $0.65 per megawatt-hour would allow PJM to cut uplift charges on INCs and DECs by more than 80% and by more than half for day-ahead load.

PJM Charges Higher than Other RTOs

PJM’s current uplift charges are more than three times those in MISO, CAISO and ERCOT, according to a summary compiled by Allen, who said PJM has rejected traders’ request for a cost causation study.

Harvard’s Hogan said attempting to assess cost causality on uplift results in circular logic.

He recommends day-ahead transactions be exempt from uplift. Instead, he said, uplift should be allocated to real-time transactions with the lowest demand elasticity. “Then spread it wide” so the charges are small, he said.

PJM and Bowring are working on a joint proposal on uplift that they will present to the RTO’s Energy Market Uplift Senior Task Force, said Adam Keech, director of wholesale market operations. “Hopefully that can garner some support” among stakeholders, he said.

Fixed Fee

Keech said the task force’s consideration of replacing the current uplift formulas with a fixed fee was abandoned for lack of support.

“A fixed rate is simple. It’s also wrong,” Bowring said. “Every day it’s wrong.”

Abram Klein of Appian Way Energy Partners said a fixed fee is “not a horrible outcome. … That’s a proposal we could ultimately live with.”

Impact of Drop in UTC Trading

The panelists also sparred on the impact the drop in UTC trading since September has had on uplift and price convergence.

Scott Holladay, senior economist for Yes Energy, said the “before/after” analyses conducted by PJM and Bowring overlooked the fact that PJM’s load curves dropped as summer turned to fall. Holladay said his own analysis, which controlled for seasonality, showed that the decline in UTCs has resulted in a drop in price convergence and increased uplift. Allen said that Holladay’s analysis indicates the loss of UTCs has resulted in $1.2 billion in “increased inefficiency.”

Bowring said the $1.2 billion figure “has no basis in fact.”

Keech also rejected Holladay’s conclusion, saying uplift was at “historically low” levels since March 2014, averaging $30 million a month less than in 2013, thanks in part to a mild summer and low fuel prices. “I don’t want people saying that we took UTCs out of the market and uplift went up. That is not the case.”

It was difficult to determine the impact of the drop in UTCs, Keech said. “It’s not really clear that price convergence has gotten better or worse.”

Keech also said assigning cost causation “is extremely difficult.”

“We haven’t done a cost-causation analysis because frankly we haven’t defined what that term even means in the context of this discussion,” he said.

January 13, 2015June 15, 2023

Further Study Delays PJM’s Artificial Island Decision

By Suzanne Herel

PJM planners won’t be ready after all to recommend a stability fix for New Jersey’s Artificial Island in time for the Board of Managers’ regular meeting in February.

The winner of a contentious battle among four project applicants was expected to be announced at a special Jan. 25 meeting of the Transmission Expansion Advisory Committee.

But at the TEAC meeting last week, Paul McGlynn, general manager of system planning, said staff is working with consultants and industry experts to further study aspects of the proposals for the island, home to the Salem-Hope Creek nuclear complex.

“We have a consultant who’s been looking at sub-synchronous resonance issues for us,” he said, referring to a piece of Dominion Resources’ plan to combine thyristor-controlled series compensation (TCSC) technology with static VAR compensators (SVCs) to ensure stability.

The model was roundly criticized by Dominion’s competitors: LS Power, Transource and Public Service Electric & Gas.

PSE&G’s sister company, PSEG Nuclear, which operates the nuclear plants, last month called on PJM’s Board of Managers to reject using what it called unproven technology.

The company warned that such a system could result in damage to turbine generator shafts and widespread outages. (See PSEG Nuclear Calls on PJM Board to Block ‘Risky’ Artificial Island Fix.)

McGlynn said staff also is looking at the impact of installing fiber optic ground wire for shorter clearing times. That might reduce the size of the SVC, or supplant the need for one at all.

“We’ve actually got a lot of work going on,” said Steve Herling, vice president of planning.

After the meeting, Herling said he expected to have a recommendation ready to present to the TEAC next month. Discussions are underway to call a special meeting of the Board of Managers in March.

All of the potential solutions involve new transmission lines connecting Artificial Island to Delaware. LS Power and Transource have proposed a southern crossing of the Delaware River. Dominion and PSE&G offered a northern route with an overhead crossing. McGlynn has said that either path is expected to face permitting challenges.

LS Power’s proposal includes both overhead and submarine options for the river crossing, each of which would carry a binding cost cap of $146 million.

Transource has emphasized its 50-50 partnership with Pepco Holdings Inc. and said its submarine proposal will have the easiest time obtaining permitting.

Ronnie Bailey, manager of transmission planning for Dominion, stressed among his proposal’s advantages a 36- to 48-month turnaround time.

PJM planners had recommended PSE&G’s selection for the project but re-engaged the other three companies after being widely criticized this summer by environmentalists, New Jersey officials and spurned bidders. (See PJM Puts the Brakes on Artificial Island Selection.)

In an interview last week, Herling said none of the contestants had threatened a lawsuit, and that the delay was simply the result of PJM wanting to conduct a thorough review.

The project is PJM’s first under the Federal Energy Regulatory Commission’s Order 1000, which opens up transmission line projects to non-incumbent companies.

January 13, 2015

Northeast Utilities Rebranding as Eversource Energy

By William Opalka

Northeast Utilities, the holding company that operates six electric and gas distribution companies in three New England states, has announced a top-to-bottom rebranding by changing its name to Eversource Energy.

The corporate parent, with headquarters in Boston and Hartford, Conn., will use the name for itself and each of its units: NSTAR Electric, NSTAR Gas and Western Massachusetts Electric Co. in Massachusetts; Public Service Company of New Hampshire (PSNH); and Connecticut Light and Power and Yankee Gas Services in Connecticut.

The new name becomes effective on Feb. 2 and the company has requested its ticker on the New York Stock Exchange be changed to ES on Feb. 19.

“Energy is what brings us all together, and Eversource reflects the one-company focus we have been driving for the last few years,” Northeast Utilities CEO Tom May said in a statement. “Consolidating our brand was the obvious next step for us as we continually strive to improve energy delivery and customer service to our 3.6 million electricity and natural gas customers across the region.”

The Northeast Utilities name dates back to 1965, when CL&P, Hartford Electric Light and WMECo merged. NU acquired PSNH in 1992. According to the PSNH website, that company became the first investor-owned utility to go bankrupt since the Great Depression. PSNH spent the 1980s fending off financial crises precipitated by cost overruns, delays and opposition related to the Seabrook nuclear plant.

The biggest step in the makeover occurred in 2012 with the merger of Hartford-based NU with NSTAR, of Boston. The proposed pairing was announced in late 2010. During regulatory review, the new company pledged to maintain dual headquarters in its host cities. NU, with about 2.4 million customers, was twice the size of NSTAR with its 1.2 million customers.

Included in the merger was a negotiated settlement in Massachusetts for NSTAR to purchase electricity from the proposed Cape Wind project. NSTAR had committed to buy 27.5% of the 468-MW project’s output under a 15-year power purchase agreement. That project is now imperiled as NU and National Grid, another New England utility with a PPA with Cape Wind, have terminated the agreements due to the wind farm’s failure to meet contract benchmarks. (See related story, Terminated PPA Imperils First Offshore Wind Project.)

At the time of the merger announcement, the two companies were planning a joint venture to import Canadian hydropower into New England. The $1.4 billion Northern Pass transmission line in northern New Hampshire is now a wholly owned subsidiary of NU Transmission Ventures. The 186-mile line would bring 1,200 MW of electricity produced by Hydro-Quebec in Canada into the New England power market.

Although the project would use 147 miles of existing rights-of-way, it is mired in controversy because of the need to cross the White Mountain National Forest and its visual impact on other federal and state nature preserves.

Northern Pass requires a Presidential Permit from the Department of Energy because it crosses an international border.

The merger was almost derailed by criticism over CL&P’s response to Hurricane Irene and Superstorm Sandy in 2011. The Connecticut Public Utilities Regulatory Authority penalized the company by reducing its allowed return on equity by 0.15% for a year.

The financial markets seem to have shrugged off the controversies. NU stock ended 2014 at $53.52, up about 26% for the year above its 2013 close of $42.39.

January 13, 2015

MISO TOs Can Collect RTO Membership Adder — Once Base ROE is Found Just

By Chris O’Malley

The Federal Energy Regulatory Commission has accepted a request by MISO transmission owners to implement a 50-basis-point adder as an incentive for RTO membership.

But the commission suspended the adder (ER15-358) from being applied until TOs demonstrate that their base return on equity is reasonable based on an updated discount cash flow analysis. The resulting ROE, including the adder, must be within the 7.03% to 11.74% “zone of reasonableness” the commission set in June in a case involving New England TOs.

Last fall, MISO industrial customers filed a complaint contending that the TOs’ current base return on equity — 12.38% except for American Transmission Co. — is too high (EL14-12).

The industrials argued the base ROE for TOs should not exceed 9.15%, citing changes in financial markets. The lower rate would reduce transmission rates by $327 million, industrials say.

The base ROE case is now bound for a pre-hearing conference, after settlement talks broke down in December. (See ROE Talks Between MISO Industrials and TOs Collapse.)

TOs filed for the adder request on Nov. 6, in what industrials countered was an attempt to claw back some of the revenue TOs might lose if unsuccessful in the base ROE challenge.

Industrials have argued that TOs don’t need an incentive to remain in MISO and that granting the adder would not benefit the reliability, coordination or operation of transmission facilities.

In its ruling, FERC said industrials and other opponents of the adder failed to provide evidence for that argument.

“We reiterate that the basis for the incentive adder is a recognition of the benefits that flow from membership in an RTO, ISO or other commission-approved transmission organization, and that continuing membership is generally voluntary,” FERC said.

The MISO industrial customers include the Illinois Industrial Energy Consumers, Indiana Industrial Energy Consumers, Minnesota Large Industrial Group and Wisconsin Industrial Energy Group.

The TOs consist of 24 companies, including Ameren, ATC, Entergy, Indianapolis Power & Light and Northern States Power.

January 13, 2015June 15, 2023

PJM: EE, Renewables Could Save Some Coal Plants under Carbon Rule

By Rich Heidorn Jr. and Suzanne Herel

Some coal-fired power plants at risk of retirement under the Environmental Protection Agency’s proposed carbon emission rule could survive thanks to unlikely saviors: energy efficiency and renewable energy.

That is a surprising conclusion of a PJM economic and reliability analysis of the EPA’s Clean Power Plan, which PJM officials outlined last week for the Transmission Expansion Advisory Committee.

PJM had presented preliminary results on the study, which was requested by the Organization of PJM States Inc. (OPSI), in November. (See PJM: Regional Approach the Cheapest Way to Comply with EPA Carbon Rule.)

The analysis included eight compliance scenarios requested by OPSI and seven proposed by PJM. Among the issues it examined was the impact of the carbon rule on generation retirements.

The study forecast 20,000 MW of steam generation retirement by 2029 under the four high renewable/energy efficiency scenarios, doubling to about 40,000 for the four low renewable/energy efficiency scenarios.

Counter-Intuitive Result

“Although this seems counter-intuitive, under the proposed Clean Power Plan, more energy efficiency and renewable energy means lower CO₂prices, which implies that the financial stress on higher emitting resources is reduced,” PJM said. “In the extreme … it is possible to add enough energy efficiency and renewable energy so that re-dispatch is not needed since there will be sufficient zero-emitting resources to avoid re-dispatch.”

The EPA said last week that it will finalize the carbon rule for existing generators, along with companion rules for new and modified power plants, by mid-summer. (See related story, EPA Delays Power Plant Carbon Rules.)

The EPA’s proposal for existing generators would set interim carbon emission goals beginning in 2020, with emissions rate targets declining over the following decade. During the 2020 and 2029 “glide path” to full compliance, states would be permitted to average emissions, allowing them to “bank” earlier emissions reductions to be used in later years or “borrow” reductions that must be repaid in later years.

Retirements of less efficient, high-emitting generators early in the transition would provide an immediate cut in CO₂emissions, reducing the need for re-dispatch of more efficient, lower emitting sources. More efficient sources will face increasing pressure to retire as the emission limits decline and CO₂ prices increase.

Identifying At-Risk Units

PJM’s study set a benchmark for retirement based on the net cost of new entry (net CONE) for a combustion turbine or natural gas combined-cycle plant, depending on which was cheaper under the scenario. (Due to the stricter emissions targets under the proposed EPA rule, PJM said combined-cycle plants are the cheapest supply source for meeting reliability targets in many of the simulations.)

Generators were considered at-risk for retirement if their annual revenue requirements exceeded the net-CONE benchmark (either 0.5 or 0.6 of net CONE).

The study found that although increased use of energy efficiency, renewables and nuclear power reduce energy market prices, they also reduce CO₂ prices, which means less need for re-dispatching from coal to natural gas generators.

Increased Operations Trumps Lower Prices

“Being able to operate economically for more hours is more beneficial to coal unit revenues than the reduction in energy market prices,” PJM said.

Retirements of steam turbines — gas-, oil- and coal-fired resources whose prime mover is a steam turbine — would rise from less than 4,000 MW in 2020 to more than 20,000 in 2029 under the high renewable/energy efficiency scenarios.

Under the low renewable/energy efficiency scenario, retirements would rise from about 6,100 MW in 2020 to almost 40,000 in 2029.

The high renewable/energy efficiency scenarios assume achievement of at least 50% of the EPA’s 23.3-GWh energy efficiency goal. The low renewable/energy efficiency scenarios project wind and solar power and energy efficiency based on historic growth rates, with energy efficiency of 9.2 GWh.

PJM transmission planners will conduct reliability analyses on generators identified as “at-risk” in at least 50% of the scenarios evaluated to determine whether their closure would necessitate transmission upgrades or other actions. About 8,000 MW fell into that category in 2020, increasing to almost 40,000 in 2029.

“Through the course of January and early February we’ll be trying to get a handle on what kinds of upgrades might be required,” Paul McGlynn, general manager of system planning, told the TEAC.

Regional vs. State Compliance

PJM cautioned that the quantitative results of the study reflect many scenario assumptions, including fuel prices, electricity demand, retention of nuclear resources and whether compliance is done regionally or state by state.

“Given the uncertainty about future market conditions, the form of the final rule, and the form of state compliance plans, it is best to focus on the qualitative results, which show the direction of wholesale power prices, units ‘at risk’ for retirement, CO₂ prices and similar metrics,” PJM said.

In 2020, for example, PJM projects state-by-state compliance would result in twice as many retirements as regional compliance under the high renewable/energy efficiency scenario and 3.5 times as many under the low renewable/energy efficiency scenario.

The study also found that state-by-state compliance would be almost 30% more expensive than a regional approach. A regional compliance plan would allow states to trade reductions among each other, giving PJM access to lower cost units for re-dispatch.

“Not only is it more cost effective to do regional compliance, but there’s now fewer units at risk for retirement,” PJM Chief Economist Paul Sotkiewicz explained. “There’s a reliability message here.”

January 13, 2015

SPP Seeks to Bolster Market-Abuse Detection

By Chris O’Malley

SPP is seeking Federal Energy Regulatory Commission approval for a revised Tariff that the RTO says will more accurately screen generators for market power abuses in the form of uneconomic production.

The revised Tariff (ER15-788) is in response to FERC’s September 2013 finding that SPP lacked an automatic screen “to identify a broader range of resources that could be engaged in uneconomic production to cause or exacerbate a constraint.”

SPP has spent the last year updating its Tariff. Last March, the RTO transitioned from a real-time energy imbalance service market to the integrated marketplace design, which brought day-ahead and real-time energy and operating reserve markets.

Generators can manipulate the market by producing enough power to overload nearby transmission constraints, SPP said.

Under that scenario, the LMP on one side of the constraint could fall while prices on the relieving side of the constraint rise. Thus, a market participant could receive an uplift payment because of a low LMP on one side of the constraint — and receive higher energy payments for resources it owns on the other side of the constraint, SPP explained.

More Scrutiny

“SPP’s current Tariff language does not include provisions for identifying when the LMP is low enough for the relevant [generating] resource to be deemed uneconomic,” SPP told the commission.

In addition, its Tariff lacks a provision distinguishing offer parameters that properly represent the resource’s physical capability from those that are unreasonably inflexible, SPP said.

Among the proposed remedies, the new Tariff includes language that would permit SPP’s Market Monitor to deem a resource uneconomic if the LMP at the generator’s settlement location falls below 50% of the applicable “energy offer curve reference level.” SPP said the same threshold is utilized for identification of uneconomic production in the MISO energy market.

SPP’s revised Tariff also would compare a generator’s submitted parameters to reference levels developed by the Market Monitor. It would distinguish small fluctuations in parameters from those “that are intentionally unrealistic.”

No Sign of Widespread Abuse

The RTO’s most recent State of the Market Report states that there were a “small number” of periods when uneconomic production was identified.

SPP’s Market Monitor also had an eye out for abuses such as physical withholding and economic withholding. While a number of concerns were raised, “there is little evidence of any market power abuse,” the Monitor said.

The State of the Market Report was for the year 2013, prior to SPP’s transition to the integrated marketplace.

January 13, 2015June 15, 2023

Federal Briefs

Terrestrial Energy said last week it is working with Oak Ridge National Laboratory to advance a molten salt reactor from the design stage to the blueprint stage.

Molten salt reactors, or MSRs, are advanced breeder reactors that typically use a fluoride salt mixture as the coolant. They run at higher temperatures then water-cooled reactors. Terrestrial teamed with Oak Ridge in part because the lab ran a MSR prototype from 1965 to 1969. Terrestrial said it sees its design being used in modular reactors, from 80 MW to 600 MW. It said it expects to have the blueprints done by late 2016.

More: Nuclear Street

PacifiCorp Energy Fined for Bird Deaths at Wind Farms

The Department of Justice fined PacifiCorp Energy $2.5 million related to a spate of bird deaths at two of the company’s Wyoming wind farms.

The department said 38 golden eagles and 336 other protected birds have died by blade strikes since 2009 at the company’s Seven Mile Hill and Glenrock/Rolling Hills projects in Wyoming. The two projects have 237 turbines.

The government said PacifiCorp failed to make all reasonable efforts to build the projects to avoid the risk of avian deaths, despite guidance from the Fish and Wildlife Service. As part of the settlement, PacifiCorp agreed to develop and implement a plan to prevent further deaths at its Wyoming wind farms.

More: The Denver Post

STB Orders BNSF Railway to Come Up with Emergency Coal Plan

The Surface Transportation Board ordered rail giant BNSF Railway to come up with a plan to keep Midwest power plants supplied with coal this winter. Coal shippers have faced increased competition for rail capacity from crude oil and grain producers.

Citing supply problems at several Midwest power companies, the regulatory agency said its main concern is the railroad’s ability to respond “in the event that unanticipated circumstances cause one or more regionally significant generating stations to reach critical stockpile levels.”

BNSF had resisted releasing its supply plans, but it said Wednesday that it would comply. More than 50% of electricity in the Midwest comes from coal-fired plants. Several generating companies instituted conservation measures leading up to the winter to try stretch their coal supplies.

More: Star Tribune

NRC Taking Comments on Vermont Yankee Closing

Entergy’s plan for decommissioning the Vermont Yankee nuclear plant is open for public comment. The plant shut down for good on Dec. 29.

Entergy filed a Post Shutdown Decommissioning Activities Report, which puts the total decommissioning cost at $1.24 billion. The Nuclear Regulatory Commission is accepting public comments on the plan until March 23. Comments can be submitted online at www.regulations.gov, using Docket No. 50-271.

Company Hired to Dismantle Zion Station Running Out of Money, Exelon Says

EnergySolutions, a Utah-based company dismantling Exelon’s closed Zion nuclear generating station, says it is running short of funds to complete the task.

The company told Exelon that the project, paid for with $800 million collected from ratepayers over decades, will run out of money before all the buildings on the site are taken apart. According to the company’s agreement with Exelon, EnergySolutions would cover the projected shortfall. Zion was deactivated in 1998.

The arrangement was the first time the Nuclear Regulatory Commission allowed a plant owner to transfer a reactor’s operating license and liabilities to a third-party company for decommissioning. EnergySolutions owns a radioactive waste disposal facility in Clive, Utah.

More: Chicago Tribune (subscription required)

Initial Filings Made with FERC for New Nexus Pipeline

Nexus Gas Transmission, DTE Energy and Spectra Energy Partners have filed plans with the Federal Energy Regulatory Commission to build a 250-mile pipeline to transport natural gas from the Utica Shale formation to northwest Ohio.

The $2 billion Nexus Pipeline would run through 11 counties in Ohio connecting the Utica fields in the east of the state to the northwest. From there it will run into Michigan and connect with an existing pipeline in Ontario. The 42-inch diameter pipeline would deliver 1.5 billion cubic feet of gas a day.

More: Akron Beacon Journal

BOEM Being Sued over Refusing to Disclose Extent of Gulf Fracking

The Center for Biological Diversity filed suit against the Bureau of Ocean Energy Management, alleging that the agency refuses to comply with a public records request concerning the scope of hydraulic fracturing in the Gulf of Mexico.

The group said it has requested permits, documents and emails relating to approved drilling operations, but that the BOEM has refused all requests.

More: Grist

Department of Energy Challenging $54 Million New Mexico Fine

The U.S. Department of Energy is contesting a $54 million fine levied by New Mexico for safety and environmental violations at the Waste Isolation Pilot Plant and Los Alamos National Laboratory.

Federal officials are seeking to have the fine reduced or stricken altogether. The New Mexico Environment Department announced the fines last month. The violations resulted in the pilot plant being closed down.

More: Washington Times

January 13, 2015June 15, 2023

PJM Market Implementation Committee Briefs

The Market Implementation Committee will review modeling practices that PJM said may be shortchanging loads with transmission agreements that pre-date the RTO’s capacity market.

The MIC last week approved an issue charge proposed by Stu Bresler, vice president of market operations.

Bresler said the issue arose last year after a PJM member in Commonwealth Edison’s locational deliverability area (LDA) sought a waiver of PJM’s Reliability Assurance Agreement before last May’s base residual auction.

Bresler was referring to the Illinois Municipal Electric Agency, which won a waiver from the Federal Energy Regulatory Commission regarding its means of serving the Naperville, Ill., portion of its load.

Last week, IMEA filed a second waiver request for May’s 2018/19 BRA.

“The fundamental problem is that when a PJM zone is identified as a potentially constrained LDA (and therefore separately modeled with its own [variable resource requirement] curve), internal resource requirements are triggered that do not recognize or give credit for the capacity transfer capability rights of [load serving entities] that have historic, long-term, firm transmission rights to serve their network loads with external resources,” IMEA wrote in its request (ER15-834).

The MIC approved a problem statement on the issue in December. (See PJM MIC OKs Capacity Transfer Rights Inquiry.)

Market Monitor Joe Bowring questioned the impact of the rule change being considered by PJM. “It’s a broad issue because it creates the possibility of others requesting the same thing,” he said.

Bresler, however, said potential changes would affect an “extremely small population of market participants who find themselves in this situation.”

MIC to Work Synch Reserve Payments Inquiry

The MIC will hold special meetings to consider the Market Monitor’s effort to change compensation for Tier 1 synchronized reserves.

PJM’s Lisa Morelli suggested the approach after briefing the MIC last week about a Jan. 5 education session on the issue. No members objected to her recommendation.

Tier 1 synchronized reserves — all on‐line resources following economic dispatch and able to ramp up at PJM’s request — are paid the Tier 2 synchronized reserve market clearing price whenever the non-synchronized reserve price is more than zero. Bowring said it’s wasteful to pay Tier 1 the same price as Tier 2, because only Tier 2 are subject to penalties for non-performance. (See Monitor: Cut Pay for Tier 1 Synchronized Reserves.)

PJM Posts MISO Price Predictions Before CTS Vote

pjm mic — IT SCED provides four look-ahead solution intervals over a two-hour period, from Interval 4 (135 minutes before flow) to Interval 1 (30 minutes before flow). Click to zoom.

Last week PJM, which will seek stakeholder approval next month for an interchange trading product with MISO, released statistics on the accuracy of its predicted prices at the MISO interface.

The statistics were included in an MIC briefing on the proposed Coordinated Transaction Scheduling (CTS) product, which is similar to one PJM launched Nov. 4 with NYISO.

Under CTS, traders would be able to submit “price differential” bids that would clear when the price difference between MISO and PJM exceeded a threshold set by the bidder.

The product would use price forecasts generated by PJM’s Intermediate Term Security Constrained Economic Dispatch engine (IT SCED). From January through November 2014, IT SCED successfully predicted the MISO price within +/-$5/MWh about 60% of the time (see chart).

CTS is intended to reduce uneconomic flows between PJM and its western neighbor. PJM says almost half of the transactions from PJM into MISO occur when prices are higher in PJM.

Intermittent Resources Panel Wants to Stick Around

The Intermittent Resources Task Force, which completed its last assignment in October, is proposing a charter revision that would turn it into a standing subcommittee.

Among other duties, the subcommittee would monitor the participation of intermittent resources in the energy, capacity and ancillary services markets, and recommend improvements to PJM systems and procedures.

Like the task force, which was created in 2008, the subcommittee would report to the MIC. It would conduct business primarily through quarterly conference calls.

The MIC will be asked to vote on the new charter next month.

January 13, 2015

FERC Approves New England Demand Response Integration

By William Opalka

The Federal Energy Regulatory Commission last week approved rule changes allowing New England grid operators to fully integrate demand response into their wholesale markets, including their reserve markets (ER15-257).

The changes were proposed by ISO-NE and the New England Power Pool to bring their rules into conformance with FERC Order 745.

Some changes became effective on Jan. 12 in advance of the ninth Forward Capacity Auction, scheduled for Feb.2. Others will take hold on June 1, 2017.

FERC turned aside objections from power generators who want any rulings related to Order 745 deferred until a successful challenge to FERC jurisdiction over DR in a federal appeals court is resolved.

The New England Power Generators Association has argued that the D.C. Circuit Court of Appeals ruling in Electric Power Supply Association v. FERC says that FERC lacks jurisdiction to regulate rates for supply-side demand response resources and could extend to the forward capacity and forward reserve markets.

“We find it appropriate at this time to proceed with these market enhancements until further action is taken,” FERC wrote.

In 2011, ISO-NE and NEPOOL proposed a two-stage process to incorporate DR into the wholesale markets. Stage one defined an initial transition period that began in June 2012. Stage two rules were proposed in this docket in October 2014.

ISO-NE currently models a single DR asset that can both reduce its load and inject energy into the electric grid as two separate assets, according to FERC. ISO-NE and NEPOOL say the changes will allow DR to provide operating reserves as other resources without altering the existing co-optimized energy and real-time operating reserves market. “These changes include revisions to demand response resources’ energy market offer parameters to allow such resources to provide 10-minute and/or 30-minute reserves,” FERC said.

NEPGA also said the revisions discriminate against generation resources in the compensation of DR for avoided line losses.

FERC rejected that argument, saying that “under a common market structure, all resources will have comparable obligations and be paid the comparable price for delivery.”

January 13, 2015June 15, 2023

Generator Testing Slowed by Warm December

PJM generation owners conducted winter preparation tests of 156 infrequently used power plants between Dec. 5 and Jan. 2, cranking up 7,549 of a possible 9,349 MW for a success rate of 81%.

Units failed to start due to problems with fuel-handling systems and emission systems, as well as oil leaks, tube leaks and cranking diesel generator failures, PJM officials told the Operating Committee last week. The tests were considered successful if the units were able to generate installed capacity levels, even if it took two or three attempts to get them running.

Warm weather in December forced numerous test cancellations and pushed the testing into January. An additional 18 units (980 MW) were scheduled for testing last week.

The testing will result in more than $3 million in make-whole payments, officials said.

Operators of 91% of generating units — representing 98% of installed capacity — reported to PJM that they had completed their own cold weather checklist or the one in PJM Manual 14D.