VALLEY FORGE, Pa. — Tier 1 synchronized reserve resources would be obligated to respond in emergencies and subject to penalties if they couldn’t, under a PJM-backed proposal approved Wednesday by the Market Implementation Committee.
The proposal retains Tier 1’s ability to receive compensation outside of synch reserve events whenever the non-synch reserve market price is more than $0. Units could opt out of the performance obligation, but by doing so they would forfeit any credit they would have received outside of responding to an event.
Estimated Tier 1 megawatts would still be considered when clearing the synch reserve market so that opting out could not be used to withhold supply from the market and drive up prices.
In addition, units would be made whole for the cost of responding to a spin event. However, that would apply only to units scheduled by PJM to provide energy or self-scheduled resources that are dispatched by PJM to run above their minimum rate.
The PJM proposal was one of three presented to address a problem statement raised last fall by Independent Market Monitor Joe Bowring, who estimated that the payment scheme dating to 2012 results in about $85 million in unnecessary expenditures each year. (See Monitor: Cut Pay for Tier 1 Synchronized Reserves.)
The other plans were crafted by Bowring’s Monitoring Analytics and PJM’s Industrial Customer Coalition.
Bowring’s proposal would have eliminated the compensation Tier 1 resources receive when they’re not responding to an event — what he classified as an unearned “windfall” — and would not have imposed a performance obligation. It failed, garnering just 29% of the vote.
Bowring said Tier 1 resources already can offer as Tier 2. “All of the functionality that PJM wants to add through these complicated changes are already there,” under current rules, Bowring said, sparking a brief debate with Adam Keech, PJM‘s director of wholesale market operations.
Keech said it is up to PJM to decide whether to accept Tier 1 resources seeking Tier 2 status.
“No one can force PJM to buy Tier 2 it doesn’t need,” Bowring agreed.
The proposal from the ICC would have compensated Tier 1 resources outside of an event, but at the non-synchronized reserve price.
The ICC’s Susan Bruce said the proposal was a compromise between the approaches of PJM and the Monitor. “The Industrial proposal is smack dab in the middle between the two.” It was rejected with a favorable vote of just 23%.
PJM’s scarcity pricing scheme was created in 2012 to accurately price energy and reserves when reserves are short — defined as less than the largest generating unit that is on-line. The mechanism allows the market clearing price to rise, creating an incentive for resources to respond in an emergency.
PJM’s proposal, which passed with 64% approval, will be heard at the Markets and Reliability Committee next month. If approved there, it will be presented to the Members Committee in October and implemented shortly thereafter. Manual language will be presented at the August MIC.
Market participants would be able to enter replacement capacity transactions earlier than Nov. 30 prior to the start of the delivery year if the need is linked to a physical reason that would prevent a participant from meeting its commitment, according to manual changes approved last week.
To prevent the opportunity for financial arbitrage between auctions, the changes prohibit generation that is replaced early from being recommitted for the delivery year.
The motion passed with 81% support, trumping an alternate measure introduced by Tom Rutigliano on behalf of EMC Development. That proposal, which would have placed no restrictions on what capacity could be replaced or on it being re-entered into the market, received 28% support.
Under the approved changes, replacements would be permitted when the owner could show the expected final physical position of the resource at the time of the request.
Existing generators could engage in such transactions if they are being deactivated, while new generators could replace themselves if their project was canceled or delayed.
Demand response or energy efficiency resources could be replaced due to the permanent departure of their loads.
Package Calls for Notice on Pricing Interfaces
PJM would be required to provide more public notice before it creates “closed-loop” pricing interfaces under a proposal approved by the committee.
Under the changes, the RTO would announce the implementation of such interfaces at least five days before the close of the next monthly financial transmission rights auction. Currently, there are no notice requirements except for sub-zonal demand response, which is announced the previous day.
The RTO also will provide notice when it begins studying a potential new interface that will be defined and able to be used, such as looking into modeling the interface. Notices will be posted on the OASIS site, triggering an email to stakeholders. The rule will allow an exception to the advance notice requirements for planned, emergency or maintenance outages of less than 10 days.
PJM uses closed-loop interfaces to capture operator actions in LMPs rather than in uplift because its modeling software is unable to set prices for voltage problems.
The change was approved by acclamation with 10 members voting in opposition.
PJM told the Operating Committee last week it plans to poll members on whether to expand the winter preparedness testing it began last year. The testing was credited with improving generator performance during the winter of 2014/15, but it came at a cost of about $7 million to load.
Susan Bruce, of the PJM Industrial Customer Coalition, said her members had questions about whether the testing “is a good use of ratepayer dollars.”
“It’s not a slam dunk to us that this should be expanded,” she added.
Gregory Carmean, executive director of the Organization of PJM States, which represents state regulators, suggested generators — not load — should be shouldering the costs. “What’s the rationale for load paying these costs in a Capacity Performance world?” he asked.
However, Brock Ondayko of American Electric Power noted that the coming 2015/16 winter will not be subject to the Capacity Performance rules, which don’t take effect until delivery year 2016/17.
Dan Griffiths, executive director of the Consumer Advocates of PJM States, was more sympathetic to continuing the testing, calling it a “pragmatic question.” But he requested time to poll his members before voting.
“If it’s useful for identifying problems it should be done,” he said.
Members will be asked to vote on four options, which would be reflected in Section 7.5 of Manual I4D:
Option 1, with the addition that the program would end after winter 2015/16 for CP resources.
Option 1, plus the following changes: Expand the exercise period from the month of December to the months of November through January; expand the maximum temperature for the testing to 40 degrees Fahrenheit in PJM’s southern zones (from 35 F); allow testing of more than 1,000 MW/day.
Option 3, with the program terminating after winter 2015/16 for CP resources.
In a survey in June, all but three of 119 respondents said they supported continuing the testing; 93 (78%) said they preferred maintaining the current rules while 26 (22%) favored making some changes, which were not specified. (See Why Did PJM Grid Fare Better This Winter?)
PJM Seeking to Tighten Training, Certification Rules
PJM will seek OC approval next month on an initiative to improve compliance with the RTO’s training and certification requirements.
The requirements cover transmission owners, generation dispatchers, demand response providers and energy storage device operators. While transmission owners are usually in compliance, PJM said in a problem statement, non-compliance by some in the other groups “has been continuing for many months and in many cases has increased or become chronic in nature.”
Although those not in compliance are required to submit mitigation plans, most have not done so or have failed to comply with them.
In June, nine generating companies, five small generators (>75 MW) and four DR and storage providers were out of compliance with training or certification requirements. Aside from seven of the generators, none had submitted mitigation plans.
PJM said the problem could lead to operational or reliability problems as some members are unaware of their responsibilities for providing instantaneous reserves and other generator data.
Glen Boyle, manager of system operator training, said the RTO hopes to complete the work, which it is recommending be conducted by the System Operations Subcommittee, within three months. “We’ve talked internally and have some options” for solutions, he said.
PJM said it will not consider changing the existing training and certification requirements within the scope of the problem statement.
Disconnect Between PJM, Members on Meter Accuracy
A proposed update of Manual 1: Control Center Requirements has exposed a gap between PJM and some transmission owners regarding accuracy requirements for system control and monitoring meters.
As a result — at PJM’s request — members last week endorsed changes to the manual except for Section 5.
“We need more time” before changing Section 5, PJM’s Ryan Nice told the OC. “PJM needs a better overall picture of the accuracy of metering data.”
While the manual requires accuracy of ± 2% for meters supplying data to PJM’s energy management system (EMS), it’s not clear that all meters are covered by that requirement. Some TOs have meters that are only accurate to within 3%, Nice said.
The gap affects real-time meters, not billing meters.
“We need to evaluate the cost” of requiring all meters to comply with the 2% requirement, Nice said, “to make sure the operational value justifies the cost and time to members.”
The General Assembly has exempted from public review some communications among members of the Public Utilities Regulatory Authority.
The legislature approved a bill exempting communications that occur between scheduled meetings after the regulatory agency said its communications were hampered by requests citing the Freedom of Information Act. Comments in public meetings are not exempt.
The three commissioners said they decide “complex, legal and technical matters” and discussions at public meetings can take hours.
Electric retailer North American Power has agreed to pay $2.6 million to settle complaints by state authorities that the company quickly increased rates for customers it had enrolled with a low introductory rate.
The supplier will pay $100,000/month over the next 26 months to Operation Fuel, a nonprofit that provides home energy assistance to residents. The settlement resolves a two-year investigation by the Public Utilities Regulatory Authority. The company made no admission of wrongdoing under the terms of the settlement.
Power Grid Upgrades Fail to Speed ComEd’s Restoration Times
Commonwealth Edison did not improve the time it took to restore power last year despite having spent more than $600 million to pay for smart grid improvements, raising questions about the effectiveness of the improvements.
ComEd’s restoration time averaged 196 minutes, according to its annual reliability report. The findings raised questions about the 2011 smart grid law, which allowed the utility to raise rates to finance a $2.6 billion grid modernization program over 10 years. ComEd also reported an average of just over one outage per customer last year, compared with 1.16 in 2012 and .99 in 2013.
Chief Operating Officer Terence Donnelly defended the utility’s performance, saying ComEd’s success in preventing outages has led to a longer average restoration time. “The outages that [occur cause] more significant damage and take longer to repair,” he said.
Gov. Mike Pence has written to President Obama stating the coal-dependent state will not comply with the Clean Power Plan unless major revisions are made. Pence said the plan would force premature retirement of coal-fired plants, “threatening our stable source of affordable electricity.”
The state would have to curb carbon dioxide emissions by 20% by 2030 under the plan that the Environmental Protection Agency is set to finalize in August. The state’s power plants ranked No. 4 in the U.S. in 2012 for the amount of CO2 emitted per unit of electricity.
Pence has repeatedly stated that he isn’t convinced that climate change is mostly caused by human activity, and he vowed the state was ready to use all legal means necessary to fend off EPA’s plan.
Anti-pipeline groups submitted more than 2,500 written statements with the Utilities Board to protest the Dakota Access pipeline, which would deliver 570,000 barrels of North Dakota crude oil across the state to Illinois.
“This huge hazardous liquid pipeline is threatening our land, our water and our very livelihoods, if not lives,” said Brenda Brink, of the Iowa Citizens for Community Improvement. “There’s not enough money in the world that they can give us to cross our land, they’ll never do it,” said Dick Lamb, a landowner.
The pipeline proposed by Energy Transfer Partners would cross four states.
A report by The Brattle Group concluded that the Calvert Cliffs nuclear energy plant contributes $397 million to Maryland’s gross domestic product and accounts, directly and indirectly, for 2,300 full-time jobs.
The study estimated that without the Exelon-operated plant, Maryland’s carbon dioxide emissions would be about 9 million tons higher.
The industry-commissioned report comes at a time when some U.S. nuclear facilities – including several of Exelon’s units in Illinois – are facing potential shutdowns due to economic and policy challenges. In Illinois, Exelon has proposed legislation that would help shore up its underperforming plants. (See Exelon-Backed Bill Proposes Surcharge to Fund Illinois Nukes.)
Gov. Charlie Baker is supporting legislation that could help import up to 2,400 MW of Canadian hydropower into the state.
Matthew Beaton, Baker’s energy and environmental affairs secretary, said the state needs more electricity from renewable energy sources such as hydropower if it is to meet a 2020 deadline for reducing greenhouse gas emissions.
Baker’s bill would require major electric utilities to seek long-term contracts from hydropower generators — most likely Canadian companies such as Hydro-Quebec and Nalcor Energy.
The Public Service Commission on July 9 approved the construction of solar facilities near the Golden Triangle Industrial Park and at Golden Triangle Regional Airport in Lowndes County. The two facilities will cost nearly $3 million and generate a combined 1.6 MW.
The new solar sites are among several approved by the commission this year. “The momentum is really picking up in Mississippi on solar power,” Commissioner Brandon Presley said.
Silicon Ranch Investments and SR Walker East will build, operate and maintain the arrays.
State regulators are set to approve a plan to allow Liberty Utilities to secure 115,000 dekatherms of daily capacity on Kinder Morgan’s proposed natural gas pipeline from the Marcellus Shale formation in Pennsylvania into New England.
The staff of the Public Utilities Commission signed off on the utility’s request to use the Northeast Energy Direct project to serve its 90,000 customers. The three-member commission still has to formally approve the deal after a July 22 hearing.
Representatives of the Pipeline Awareness Network, an advocacy group, criticized the PUC’s staff for endorsing the project despite testimony of the PUC’s own expert witness and the agency’s consumer advocate that questioned the need for the utility to procure such a large amount of capacity.
Residential air conditioners can be turned down by remote control during times of peak demand under a limited, voluntary program that began July 1.
Participating customers will be paid small stipends to take part in the program and could save an estimated $100/year or more through lower electricity use during times when the AC is dialed down. For now, Rochester Gas & Electric is offering the program only to certain customers in two towns in Ontario County. RG&E’s sister company, New York State Electric and Gas, is offering its program in similar high-demand pockets in southern Erie, Chautauqua and Putnam counties.
New York regulators mandated the initiative as part of the overhaul of the state’s energy distribution system, known as Reforming the Energy Vision. The hope is that “dynamic load management” programs will relieve stress on the electric distribution system and help consumers learn to better manage their own energy use.
Electric retailer HIKO Energy has agreed to pay $1.25 million to settle fraud claims by the state attorney general.
The attorney general’s lawsuit accused HIKO of defrauding 25,000 current and former customers between June 1, 2011, and Oct. 1, 2014. An investigation by the Consumer Protection Bureau found that the company promised lower rates to customers and then charged higher rates, enrolled new customers without their knowledge and made it difficult for customers to cancel their enrollment.
The settlement requires HIKO to pay $1.25 million to the attorney general’s office to be used in a restitution program.
Solar energy capacity in the state quadrupled from 2011 to 2014, which officials say is a sign that solar power is becoming a more significant factor in meeting the state’s energy needs.
By the end of last year, state residents had installed enough solar energy-generating capacity to produce 314.5 MW. In April, solar power accounted for nearly 0.1% of the state’s electricity production, according to the U.S. Energy Information Administration.
The amount of electricity generated from solar energy tripled in Western New York over the last three years, thanks to a combination of lucrative government incentives and a steady decline in the cost of rooftop solar energy systems, according to a new report from the New York State Energy Research and Development Authority.
In addition to a 30% federal tax credit on new solar energy systems, the state is offering $1 billion in incentives for larger-scale solar projects through its NY-Sun initiative.
The state is awarding $100,000 in grants to 83 groups for microgrid projects through a competition that is designed to promote small-scale, community-run electric generation.
The winners include Central Hudson Gas & Electric and NRG Energy, which have partnered to evaluate the potential of a resilient microgrid at Stewart International Airport that would also benefit critical facilities in New Windsor. If the project study is approved, it may be eligible for up to $1 million for development of detailed designs and up to $7 million for construction.
Pork Producers Ask Lawmakers to Keep Renewable Mandate
The state’s pork producers are asking lawmakers to maintain a provision in the state’s renewable energy law that requires a small percentage of power to be derived from swine manure.
The state’s utilities are asking, for the fourth year in a row, that the targets in the 2007 renewable energy law be postponed because no producers have been able to meet them. But some pork producers say they have already invested millions to develop manure management systems to capture methane from swine waste as an alternative to lagoon storage and field spraying. Smithfield Foods, the largest pork producer in the U.S., has spent $40 million developing projects at six of its hog farms.
“We don’t want to see anything about the law get changed,” Angie Maier, the N.C. Pork Council’s policy development director.
PSC Sees ‘Continual Stream’ of Pipeline Applications
Despite the downturn in oil prices, the Public Service Commission is seeing “a continual stream of applications” for crude oil pipelines from oil-producing areas.
Commissioner Randy Christmann said the applications for infrastructure investment in the Bakken Shale oil-producing areas is a bullish sign for the oil-producing state, despite the slowdown in drilling. “It is going to make the next time it picks up … far more pleasant,” Christmann said.
The PSC approved a siting application for a new pipeline last week and set a September hearing for a new 23-mile crude pipeline by NST Express.
Local Officials Appeal to Governor for More Control over Drilling
Some municipal and county officials have asked Gov. John Kasich to grant more control to local government over oil and gas drilling.
“The notion that our communities have the right to bar or limit activities which threaten public health or the quality of life of their residents has a long tradition in Ohio law,” the officials state in a letter to the governor, which was released by the anti-drilling group Environment Ohio. “… Yet the oil and gas industry has the audacity to insist that this basic principle of local control should not apply to its operations.”
Groups Accuses AG’s Office of Failing to Conduct Fracking Health Probe
Advocacy group Food & Water Watch has accused the attorney general’s office of failing to follow through on a promise to investigate complaints that the state Department of Health discounted reports of residents who said they had been sickened by hydraulic fracturing.
The group said Attorney General Kathleen Kane’s office had done only “a few cursory interviews” instead of a full investigation. It has filed a right-to-know request seeking any documents relating to public health complaints and fracking.
A spokesman for the Democratic attorney general’s office said it attempted to look into the allegations but were stymied by the Health Department, which was controlled by a Republican administration until January. “Our environmental crimes unit did pursue this investigation and interviewed a significant number of the complainants,” a spokesman said. “But because the Department of Health under the last administration was not cooperative, it was difficult to determine how they responded.”
The Public Utilities Commission has eliminated a “billing adjustment” charge assessed on electricity customers who switch from incumbent utilities to competitive suppliers.
The billing adjustment charge, which was put in place in 2010, was designed to compensate utility National Grid for the difference in the fixed rate it charges consumers for electricity and the underlying variable rates it pays to power generators from month to month.
The commission said the charge caused confusion among customers and inhibited the growth of competitive retail electricity markets.
Judge Grants Eminent Domain to Dakota Access Pipeline
A county judge granted eminent domain status to the Dakota Access crude oil pipeline, although the state Public Utilities Commission has not yet approved the project that would deliver North Dakota petroleum though the state.
The judge’s ruling will make it easier for surveyors to develop a route for the pipeline, which would run about 272 miles across the state. Dakota Access filed for the status in April, saying it was necessary for the surveyors to determine a suitable route for the pipeline.
Energy Transfer Partners is building the project, which would deliver 450,000 barrels of crude oil a day on a 1,134-mile route that terminates at a rail terminal and pipeline interconnection in Illinois.
Dominion Transmission has filed proposed route changes for its Atlantic Coast Pipeline through southern Virginia to more closely align the natural gas pipeline’s path with existing rights-of-way.
But Dominion has not altered the route through the western part of the state, where opposition to the project is strongest. “We’re still exploring new opportunities for routes, refinements and adjustments,” said Greg Parks, construction supervisor for the $5 billion, 550-mile pipeline project.
Dominion said that it is more difficult to co-locate the pipeline with existing utility corridors in the mountainous western region of the state.
Lawmakers Try to Clear County Block of Enbridge Pipeline
Republican lawmakers have proposed to strip a county government of the authority to demand that a crude oil pipeline obtain more insurance.
The lawmakers added language to the state budget bill aimed at Dane County, which required a crude oil pipeline operator to boost its insurance coverage. That requirement has impeded completion of upgrades that Enbridge is installing on its Line 61 pipeline from Superior to Illinois. The upgrades would double the daily capacity of the 343-mile pipeline from 560,000 barrels to 1.2 million barrels. The language also allows the company to increase the pipeline’s capacity in the future, without requiring county approval.
Enbridge said the county exceeded its authority since federal agencies regulate interstate pipelines. Enbridge also said that it has always been responsible for the costs of cleanups. But environmental groups protested the language, noting that Enbridge has a history of pipeline spills in the state.
State regulators, consumer advocates, generators and the Independent Market Monitor have asked the Federal Energy Regulatory Commission to modify its June 9 order largely approving PJM’s Capacity Performance plan.
Most of the rehearing requests were filed Thursday, along with PJM’s submission of a 556-page compliance filing responding to the commission’s request for changes to its plan.
Maryland and D.C. regulators asked the commission to reverse the order, while generators sought relaxation of penalty provisions. Two filings seek expedited review before PJM’s “transition” auctions begin July 27.
Load Forecast
One asked FERC to order PJM to update its peak load forecasts for the upcoming capacity auctions or delay them (EL15-83).
The complainants — the PJM Industrial Customer Coalition, the Sustainable FERC Project and regulators or consumer advocates from Delaware, D.C., New Jersey, Maryland, Pennsylvania and West Virginia — say that PJM’s newly designed load forecast could reduce the amount of capacity procured by approximately 7,000 MW, saving consumers about $625 million.
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While PJM told stakeholders at the May Load Analysis Subcommittee meeting that the new model is a “noticeable improvement” over the current forecast, the plaintiffs say, the RTO has said the new forecasts won’t be ready for incorporating in the capacity auctions until November.
The transition auction for delivery year 2016/17 is set for July 27-28 and that for 2017/18 for Aug. 3-4. The Base Residual Auction for 2018/19 is scheduled for Aug. 10-14.
The plaintiffs say FERC should either order use of the new models under the current auction schedule, delay the auctions until November or reinstate the short-term resource procurement target — also known as the “2.5% holdback” — for the BRA. FERC eliminated the holdback in its June 9 ruling. (See FERC OKs PJM Capacity Performance: What You Need to Know.)
They asked FERC to rule by July 17, saying continued use of the current model “will lead to substantial and imprudent over-procurement of capacity, resulting in unjust and unreasonable capacity prices for consumers.”
The plaintiffs said PJM has overestimated the RTO’s reliability requirement by an average of 6.25% in delivery years 2010/11 through 2015/16. The new model attempts to better account for energy efficiency and other factors.
PJM Vice President of Planning Steve Herling told RTO Insider on Thursday that the RTO reworked its load forecasting model with a focus on how it would affect the regional transmission expansion planning process. “We have not even begun to figure what the implication will be for” the capacity market, he said. “It started as an RTEP issue.”
In addition, he said, there is more work to do, including updating zones with new metropolitan area mapping and investigating the current practice of using 40-plus years in weather simulations. And, he added, the model has yet to pass through the stakeholder process. “Any change like that has to go through a vetting process,” he said.
Annual DR
Most of the same complainants — along with the Public Power Association of New Jersey, Duquesne Light Co. and regulators and consumer advocates from Illinois — also are seeking expedited hearing of a complaint seeking to allow annual demand response resources to bid into the transition auctions.
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The plaintiffs acknowledged that the commission’s June 9 order “did not discuss specifically” whether annual demand resources could participate in the transition auctions. “This specific issue was not raised for the commission’s consideration because, ostensibly, it was clear from the operative provisions of the as-filed version of Section 5.14D [of PJM’s Tariff] that the transition auctions applied to all Capacity Performance resources, which, by definition, includes annual demand resources and other types of resources.”
The complainants said PJM has told them and other stakeholders that the Tariff does not permit annual DR’s participation.
“PJM’s view is that only generation capacity resources are eligible to participate in transition auctions. PJM has acknowledged, however, that no operational basis exists for excluding annual demand resources from the transition auctions. It appears that PJM’s concern is whether sufficient bases exist under the Tariff language that has been accepted by the commission to allow all types of Capacity Performance resources to participate.”
PJM has not responded to the filing, but in a separate challenge by the Advanced Energy Management Alliance Coalition, the RTO said Thursday it intended to exclude DR and energy efficiency from the transition auctions.
PJM said the transition auctions were designed to “provide a glide path” for generation resources that needed time to make investments to meet Capacity Performance requirements.
“The decision to limit the transition auctions to generation capacity resources was made in light of the fact demand response resources or energy efficiency resources would not need the same glide path, and also taking into account the continued uncertainty associated with the availability DR and EE to serve as Capacity Performance resources” following the D.C. Circuit’s EPSA ruling voiding FERC’s jurisdiction over DR (EL15-80). (See Supreme Court Agrees to Hear Demand Response Appeal.)
Market Monitor: ‘Inconsistent’ Incentives
The Monitor requested FERC revise findings in its June order that it said “create incentives in the energy market that are not consistent” with the Capacity Performance market design.
The Monitor cited FERC’s rejection of PJM’s proposal to allow parameter limits based only on resources’ physical constraints, saying the commission’s action would result in increased uplift payments.
“By permitting generation owners to establish unit parameters based on non-physical limits, the … order has weakened the incentives for units to be flexible and has weakened the assignment of performance risk to generation owners,” the Monitor said. “Contractual limits, unlike generating unit operational limits, are a function of the interests and incentives of the parties to the contracts. If a generation owner expects to be compensated through uplift payments for running for 24 hours regardless of whether the energy is economic or needed, that generation owner has no incentive to pay more to purchase the flexible gas service that would permit the unit to be flexible in response to dispatch.”
In contrast, NRG Energy and Dynegy asked FERC to clarify that capacity resources will not be penalized if PJM does not schedule them or reduces their output as the result of parameter limitations approved by the RTO.
The Monitor also called for changes regarding eligibility and documentation of risk premiums, the sub-zonal dispatch of DR and the calculation of “performance hours” and peak load obligations.
State Regulators Fear Higher Prices
The Illinois Commerce Commission said the commission’s order will create unnecessary barriers to market entry and undermine market power mitigation, resulting in higher costs for consumers.
The ICC said FERC erred in eliminating unit-specific cost reviews and the 2.5% holdback. It also faulted FERC for limiting the types of resources permitted to aggregate for the purpose of performance measurements, and in prohibiting external resources lacking pseudo ties from offering as Capacity Performance.
The Pennsylvania Public Utility Commission and the Delaware Public Service Commission joined the ICC in challenging the commission’s changes to PJM’s market mitigation rules and the elimination of the 2.5% holdback. They also questioned how penalties will be calculated; changes to credit requirements; the transition mechanism; and the elimination of extended summer DR and limited DR.
The Delaware commission also filed a separate rehearing request asking FERC to “identify the components of the balance upon which it relied for the determination that the market rule changes were just and reasonable” and asking that PJM be required to make informational filings regarding the costs and benefits of the new rules.
“Without such a requirement from this commission, any information and/or data would only be available on an ad hoc basis, which would not provide an appropriate foundation for the commission to make any assessment as to the ultimate cost effectiveness to customers of [Capacity Performance] and, perhaps more importantly, whether the costs for the implementation of [Capacity Performance] are appropriate and necessary,” Delaware said.
Generators: Penalties Excessive
The PJM Power Providers (P3) Group supported the commission’s ruling but asked FERC to clarify that generators operating within their approved parameters would not be subject to non-performance penalties. It also asked for clarification on what “performance quantifiable risks” can be included in avoidable cost risk calculations for units seeking to submit offers above the market seller offer cap. Exelon also requested rehearing on the issue.
“While both PJM and the commission expressly supported Tariff provisions that allow risks of fulfilling the obligation to offer capacity to be reflected in capacity offer cap calculations, the commission should go one step further and direct PJM to specifically enumerate known risks in addition to permitting the reflection of all reasonable risks undertaken to support a capacity offer,” P3 said.
Essential Power, Competitive Power Ventures, NextEra Energy and Invenergy Thermal Development contested FERC’s decision to eliminate monthly stop-loss limitations from PJM’s proposal, saying it failed to justify its decision through “reasoned decision-making.”
The coalition also said the commission erred in deciding that generator non-performance should not be excused even in circumstances beyond the control of generators, such as catastrophic weather events, compliance with state-approved tariffs or PJM-approved transmission outages.
GE Energy Financial Services, the operator of the 1884-MW Homer City coal-fired generating plant in Indiana, Pa., challenged FERC’s decision to make generators liable for a failure to deliver due to problems with transmission lines and switchyard equipment outside plant boundaries.
It said FERC was wrong in agreeing with PJM that generators were the market participants best able to bear the risk of transmission outages. “The best-placed party to bear this risk is the relevant transmission owner (and through it, load), which already collects payments to maintain these facilities,” it said.
“Unlike the ‘strict liability’ standard for generation delivery included in the CP revisions, transmission owners have limited their liability based on the customary ‘prudent industry practice’ standard. Thus, a supplier may have no recourse at law against its transmission ‘vendor’ — a sole source provider — even though the transmission owner has been paid to provide the service that it failed to deliver.”
The generator acknowledged that PJM may designate a transmission outage as a “catastrophic force majeure” that excuses generators for non-performance. But it noted “those events are intended to be region-wide in nature, even though Homer City will be equally unable to deliver its power upon the failure of its local transmission lines.”
“The penalties assessed against Homer City in that event would be funneled to other, luckier resources, which were fortuitously not in the wrong place at the wrong time.”
Public Service Enterprise Group also asked the commission to reinstate the existing force majeure provisions.
Calls for Reversal
While most of the filings sought to tweak the new rules, regulators from Maryland and D.C. argued that FERC should reverse its approval of PJM’s overhaul of the capacity market, saying it is “unnecessary for reliable service operations” and will increase end user costs in PJM by as much as $6 billion.
The commissions said the penalty provisions are not consistent with the higher revenues expected under the changes and said it should have held evidentiary hearings over the cost effectiveness of the changes. They also contend that the transition auctions are unnecessary.
Public Citizen also asked the commission to reverse its approval, citing the dissent by Chairman Norman Bay, who contended PJM’s overhaul of the capacity market was unwarranted. (See Norman Bay’s Dissent: ‘Two Carrots and a Partial Stick’.)
The group also asked that the commission review rates resulting from future capacity auctions under its “just and reasonable” standard.
“Public Citizen does not believe that the findings in this case are supported by ‘substantial evidence,’ but rather by the commission’s desire to further its market-based experiments in promoting and enabling ISOs and RTOs. Public Citizen fears that in doing so, however admirable its original intentions may have been, the commission may have lost sight of the primary goal of the [Federal Power Act], the protection of ratepayers from excessive rates and charges, and in fact may be slowly conceding its ability to protect ratepayers at all.”
Spanish energy giant Iberdrola SA on Tuesday dropped its bid to acquire UIL Holdings but promised to file a new application by the end of the month that would address objections raised by Connecticut regulators.
The Connecticut Public Utilities Regulatory Authority issued a draft decision June 30 that lambasted the companies’ application, recommending a final rejection, while giving them a week to respond. PURA said the acquisition was not in the public interest and offered no benefit to consumers. (See Connecticut Regulators Threaten to Reject Iberdrola-UIL Merger.)
The companies last week asked for a 60-day extension to address the decision, which outlined conditions including “ring fencing” of the local utilities, a three-year rate freeze and a commitment to keep their headquarters in the state for seven years. PURA immediately rejected that request as not affording enough time for adequate review and said the companies should file a new application that resets the clock at 120 days.
“The applicants hereby withdraw the pending application, in order to have the docket terminated as of this date and the remaining procedural schedule cancelled, which would, in turn, facilitate the applicants’ filing of a new application,” Iberdrola wrote.
Iberdrola has offered $3 billion for Connecticut-based UIL, including its United Illuminating electric distribution utility and three gas distribution companies in Connecticut and Massachusetts.
In a separate filing made hours before the companies dropped their bid, the Connecticut Industrial Energy Consumers praised the PURA draft decision. “CIEC commends the authority for reaching conclusions regarding the public interest of the proposed transaction commensurate with the record evidence,” the group wrote.
In mid-day trading, UIL stock shot up $1.46 after the announcement to $47.19.
PURA said June 30 it would not approve the deal without “ring fencing” provisions to protect UIL’s Connecticut electric and gas distribution companies from bankruptcies by Iberdrola’s other operations.
Regulators also said they “cannot conclude that the applicants will continue to possess the ability to provide safe, adequate and reliable service to the public.” It said Iberdrola’s financial strength and managerial expertise were adequate, but the company did “not possess the requisite suitability and responsibility to acquire UIL Holdings.”
A crowded docket has delayed several key pieces of New York’s Reforming the Energy Vision, including the Department of Public Service staff’s Track 2 straw proposal on ratemaking and rate design.
That document — originally expected in January and then delayed twice to June 1 and July 1 — is now due on July 28, along with staff-proposed rules governing commission oversight of distributed energy resource suppliers.
The New York Public Service Commission secretary on Tuesday granted extensions to commission staff and a working group that faced July 1 deadlines. “These extension requests are generally premised on the need to address concerns expressed by parties and members of the public for relief from the potential burdens imposed by the simultaneous issuance of four products in this proceeding,” the secretary wrote.
In requesting the delay, commission staff noted the overlap among the proposals, its own workload and the public comment periods for each.
The Market Design and Platform Technology Working Group report is now expected on July 13.
The August 2014 Track 1 straw proposal preceded the first REV order, which created the framework for development of clean and distributed energy resources. That led to the February PSC order that also set the schedule for these four docket items. (See New York PSC Bars Utility Ownership of Distributed Energy Resources.)
“Track 2 will propose specific regulatory reforms to the utility business model, rate-making approaches and rate design to achieve REV policy goals,” according to the Rocky Mountain Institute, an advisor to the PSC.
The Federal Energy Regulatory Commission on Tuesday accepted NYISO’s new method for calculating payments for voltage support services (VSS), which will keep the overall expenditure constant in the near term (ER15-1042).
NYISO derived the $2,592/MVAR compensation rate by dividing the total VSS compensation paid to qualified VSS suppliers in 2012 by the total lagging and leading reactive power capability of all qualified VSS suppliers in 2012.
“This explanation demonstrates that the proposed amendments maintain the approximate total dollar value of the current VSS program in the near term,” FERC wrote.
NYISO used 2012 as the base year for its calculations when it began developing the proposal. From 2014 onward, the payments will be tied to the consumer price index.
“We find that by applying a VSS compensation rate to both leading and lagging reactive power capability, NYISO’s proposal reasonably addresses the failure of the existing rate to address a significant shift in reliability needs, from primarily lagging reactive power support to primarily leading power support,” FERC also wrote.
MISO and its Market Monitor have joined Dynegy in denying allegations of improper conduct in the RTO’s Planning Resource Auction last April, which resulted in a nine-fold price increase in Zone 4.
The filings with the Federal Energy Regulatory Commission were in response to complaints in May by a consumer group and the Illinois Attorney General that Dynegy may have illegally manipulated the auction (EL15-70).
MISO’s 186-page response insists that it followed commission-accepted rules (EL15-70). It also stated that its Independent Market Monitor confirmed that the auction was in compliance “and produced the results it should have produced” despite prices in Zone 4 clearing at $150/MW-day compared with just $16.76 a year earlier.
“Those higher prices are the source of complainants’ discontent. However, MISO conducted the auction exactly as required under its Tariff, and none of the complainants provides any evidence to the contrary. Accordingly, these complaints should be dismissed with prejudice,” MISO told FERC.
MISO’s filing came a day after public service commissions, consumer watchdogs and attorneys general in Illinois, Indiana, Iowa, Michigan, Minnesota and Wisconsin asked FERC to investigate the auction, saying they share concerns that Dynegy “was able to exercise market power” in Zone 4.
“Due to Dynegy’s control of such a significant portion of the capacity available in Zone 4, the capacity market [in the zone] may no longer produce competitive market-based prices for capacity,” the group wrote.
Public Citizen and Illinois Attorney General Lisa Madigan asked FERC on May 28 to investigate whether Dynegy illegally manipulated MISO’s auction through its bidding strategy. Public Citizen also alleged MISO brushed aside recommendations by its staff that Zones 4 and 5 be merged due to their concerns about Dynegy’s growing share of capacity in Zone 4 after the company acquired four generators from Ameren in recent years. (See Public Citizen: Investigate Dynegy Role in MISO Auction.)
Dynegy: We Didn’t Withhold
In a 304-page filing with FERC last week, Dynegy said merging zones wouldn’t have met the requirements of the MISO Tariff. The company said it made no secret of its opposition to merging, meeting at one point with FERC staff to discuss its position.
But Dynegy spent most of its filing denying the more serious allegations of physical or economic withholding. It said all 6,419 MW of its Zone 4 capacity was “either sold bilaterally or at wholesale, exported or offered into the auction.”
The company also rejected claims of economic withholding, including an affidavit from consultant FTI Consulting Managing Director Susan Pope.
“Because of uncertainty about the quantity of offers into the 2015/16 PRA auction from non-Dynegy parties, at the time it formed its offers for this auction Dynegy would not have known with certainty whether and to what extent its non-zero priced offers would be needed to meet the Zone 4 local clearing requirement,” Pope wrote. “This is because under the MISO PRA market rules, there is substantial uncertainty concerning the quantity of supply offers that will be made into the auction.”
The company also rejected the Illinois attorney general’s claim that Market Monitor David Patton improperly calculated its opportunity costs, saying his $155/MW-day estimate reflected its ability to sell capacity into PJM.
The company said the complainants ignored that PJM’s most recent Incremental Auction cleared at $163/MW-day less than a month before MISO’s auction last April.
Market Monitor’s Response
Patton fired back at the complainants’ premise that Dynegy had an unusually strong market presence in Zone 4 and free rein to commit economic withholding.
Zones with “pivotal” suppliers such as Dynegy “are extremely common,” and that’s one reason that RTOs have market power mitigation measures in place, he said, adding that MISO properly applies such measures in its Tariff.
“Our [monitoring] found no evidence of physical withholding,” Patton said.
Patton also said that despite substantially lower auction prices in Zone 4 in previous years, “the simple fact the price of Zone 4 is higher in this planning year than in previous planning years provides no meaningful evidence in support of the complaint.”
In fact, Patton contends prices in other MISO zones “are unreasonably low.”
Patton has often argued that MISO’s capacity market is flawed because it uses a vertical demand curve, which can result in unstable capacity prices. With a vertical demand curve, the last megawatt of capacity needed to satisfy the minimum requirement has a value equal to the deficiency price, while the first megawatt of surplus has no value.
“This means that as the surplus declines to zero, the market will suddenly start to clear at much higher prices,” Patton said.
He also previously said the need for reform “may become particularly acute” as planning reserve margins decline toward the minimum requirement level with the anticipated retirement of significant amounts of coal-fired capacity as early as the 2015/16 planning years.
The $150/MW-day in Zone 4 “is still relatively low when comparing the cost of building a new unit at $247/MW-day,” Patton added.
He said the Zone 4 clearing price also reflects the convergence between MISO and PJM markets, with more than 1,000 MW of capacity in the zone committed to PJM.
Reasons for Price Jump
In its filing, MISO said the fact that the auction prices vary sharply from one year to the next does not establish that prices are unjust or that they are “the product of any lack of oversight or administration on MISO’s part; or that the price was the product of market manipulation.”
Results can vary by location and by year due to commercial decisions of market participants or the supply of capacity offered into the auction, MISO said. In the most recent auction, higher-priced local resources were needed to meet the local reliability requirement in Zone 4, MISO said, because fewer resources were offered in at zero.
Compared to the prior auction, more price-sensitive offers were submitted and more capacity was procured through the auction than through bilateral contracts, MISO said.
Zones may be affected by differing state procurement rules applied to load-serving utilities.
“Each of these factors resulted in higher prices than in the 2014-2015 PRA and are examples of factors that can raise rates wholly independently of any seller misconduct.”
The complainants failed to provide facts to back their claims and their arguments are speculative, collateral attacks, the RTO said.
“For example, Public Citizen speculates that the rate for Zone 4 ‘may be the result of illegal manipulation and gaming of the auction bidding process’ and that ‘Dynegy may have engaged in intentional capacity withholding.’”
Market Concentration
In their complaints, Public Citizen and Madigan raised concerns about FERC’s approval of Dynegy’s acquisition of generating units from Ameren — questioning the commission’s market power analysis at the time.
In its response, MISO said the two complainants did not intervene in the commission proceeding involving Ameren’s application to sell generating units to Dynegy.
MISO said FERC rejected a protest that asserted Dynegy’s proposed acquisition of the Ameren units should be analyzed in a submarket, “finding that the MISO balancing authority area properly defined the geographic market for the purposes of analyzing horizontal market power issues.”
Moreover, MISO said it determined previously that 85% of the capacity for Zone 4 had to be located within the zone. That local clearing requirement was set as a function of local reliability needs, the capacity in the zone and its import capability.
Public Citizen alleged that failing to adjust the local clearing requirement following Dynegy’s acquisition of new generation in the zone may have helped it execute a capacity withholding scheme.
MISO countered that Public Citizen failed to explain how the RTO could set aside the mathematical calculation that its Tariff requires “or how local reliability needs would have been satisfied under its approach given the amount of capacity in Zone 4 and capacity import limits.”
Not ‘Bullied’
One of the more incendiary allegations in the Public Citizen complaint is that MISO rejected recommendations by staff members to merge Zone 4 and Zone 5, given Dynegy’s growing dominance in Zone 4. The alleged motivation: fear that Dynegy would leave MISO for PJM.
Public Citizen cited minutes from a 2014 MISO Loss of Load Expectations Working Group in which a manager of economic studies purportedly stated that staff “are concerned with Dynegy’s offer strategy in the next Planning Resource Auction as they [Dynegy] are now the dominant provider of capacity in the zone.”
Public Citizen alleged the zone merger proposal was swatted down due to “stiff resistance” from Dynegy. The group specifically pointed to Dynegy executive Mark Volpe, who served as vice chair of MISO’s Supply Adequacy Working Group, claiming his role and that of others in the auction design and coordination “do not lend credibility to the auction process and cry out for FERC review of the auction results under Section 206 at least.”
In its response, MISO said there is no basis in fact that Dynegy “bullied it” or threatened to defect to PJM.
MISO said it did study and engage stakeholders in talks about combining Zones 4 and 5 but did not make the change “because additional consideration was warranted based on extensive stakeholder feedback.”
That decision “was made based upon the requirements of the Tariff, overall stakeholder input and MISO’s independent analysis — not based on threats or pressure from Dynegy.”
Discussions about combining zones and other aspects of resource adequacy requirements should continue to be conducted through the stakeholder process, MISO insists, “which will more inclusively engender broad stakeholder and state regulator involvement as compared to settlement judge procedures.”
Connecticut regulators said Tuesday they will reject Iberdrola SA’s acquisition of UIL Holdings without much stronger ratepayer protections, issuing a draft decision in which they blasted the Spanish conglomerate’s management and said they would not approve the deal based on a “leap of faith.”
The Public Utilities Regulatory Authority said Iberdrola failed to reassure it that UIL’s Connecticut ratepayers would be adequately protected from any financial stresses the company may experience from its international operations or other units in the U.S. (15-03-45).
“The authority … questions why the applicants would file a change of control application and not be prepared to provide any evidence that would demonstrate that the transaction is in the public interest,” PURA said. “To not research or provide evidence as to how the transaction would benefit (or harm) ratepayers demonstrates a lack of concern or interest by the applicants in this important area.”
In March, Iberdrola announced it planned to acquire UIL, which has electric and gas distribution companies in Connecticut and Massachusetts, in a cash and stock deal valued at $3 billion. It said it would incorporate UIL’s operations into its U.S. subsidiary, Iberdrola USA. (See Iberdrola Broadens Northeast Footprint in $3B UIL Deal.)
PURA said it would not approve the deal without “ring fencing” provisions to protect UIL’s Connecticut electric and gas distribution companies from bankruptcies by Iberdrola’s other operations.
Regulators also said they “cannot conclude that the applicants will continue to possess the ability to provide safe, adequate and reliable service to the public.” It said Iberdrola’s financial strength and managerial expertise were adequate, but the company did “not possess the requisite suitability and responsibility to acquire UIL Holdings.”
Final Decision July 17
The companies have until July 7 to provide replies to the 43-page draft. PURA said a final vote on the proposed merger is scheduled for July 17. For the merger to proceed, PURA is also demanding a three-year distribution rate freeze and a seven-year commitment for the headquarters to stay in the state, among other items.
Reaction on Wall Street was swift. UIL stock was trading at about $47.60 throughout the day but immediately dropped to about $45.50 when the draft was released at 3 p.m. It recovered slightly to close Tuesday at $45.82, off $1.71.
UIL CEO James P. Torgerson issued a statement Wednesday saying the company was disappointed in the draft decision but noted that it “provides an opportunity to UIL and Iberdrola to address” regulators’ concerns.
“We look forward to providing clarification and additional information to PURA quickly,” Torgerson said. “We truly believe the proposed transaction can bring significant value to our customers.”
Iberdrola did not respond to requests for comment.
Ring Fencing
In hearings, the state Office of Consumer Counsel said regulators should insist on the type of ring fencing provisions that Exelon has agreed to in its proposed acquisition of Pepco Holdings Inc.
Iberdrola objected, saying the ring fencing conditions were “unprecedented, unnecessary and not within the authority’s jurisdiction.” It agreed to 39 of the 97 conditions proposed by the OCC.
PURA said those conditions were insufficient. “The authority concludes that ring fencing is a necessary condition for this change of control to protect ratepayer interests.”
Iberdrola had separately offered a $400,000 renewable energy integration study, various scholarships worth more than $300,000, charitable giving of at least $2.5 million over four years, a rate credit of $5 million, a $2 million economic development grant and a one-year freeze on electric distribution rates. PURA dismissed the offers — made more than halfway through its 120-day review — as “too little and too late.”
Local Control
Regulators also questioned Iberdrola’s promises that UIL would remain under local control, with the Connecticut management in place, noting the company’s recent history of buying and selling local distribution gas companies.
Iberdrola acquired Connecticut Natural Gas, Southern Connecticut Gas and Berkshire Gas, in Massachusetts, through its 2008 purchase of Energy East Corp., which it rebranded as Iberdrola USA. The company then sold the gas utilities to UIL in 2010. They would be reacquired in the proposed merger.
When Iberdrola first owned CNG and SCG, PURA said, it responded to regulators’ ruling in a 2009 rate case by ordering the gas companies to develop plans that included “austerity measures and work force reductions.”
“The authority is concerned with the applicants’ commitment to local management and whether its management and management practices are suitable for UIL,” PURA wrote.
One issue not raised in the decision is the fate of the defunct English Station generating plant, which sits on a contaminated site in New Haven. Some state officials believe the merger is an opportunity to finally clean up the site, but PURA has already determined it is outside the scope of the merger proceeding. (See Connecticut Officials at Odds over Plant Clean-up, Merger.)
The New England Power Generators Association says ISO-NE should adhere to a planned change to a sloped demand curve in the next Forward Capacity Auction (ER14-1639).
NEPGA has asked the Federal Energy Regulatory Commission to clarify a previous order that directed the RTO to continue the effort to eliminate the need for administrative pricing in zones that are short of generation resources or suffer from transmission constraints.
ISO-NE informed FERC in May that the complexities involved in switching to the sloped demand curve could not be resolved in time to “result in just and reasonable outcomes” in FCA 10, which is scheduled for Feb. 8, 2016. ISO-NE also cited the need to reconfigure the zones within the RTO to resolve transmission constraints identified since the last auction as an impediment to a timely resolution. (See ISO-NE Proposes New Capacity Zones for FCA 10.)
NEPGA suggests that FERC did not explicitly order a sloped zonal demand curve “only because it relied on ISO-NE’s commitment to file sloped zonal demand curves for commission review in advance of FCA 10.”
NEPGA is asking the commission to initiate a Section 206 proceeding and order ISO-NE to file the sloped zonal demand curves developed by the RTO and New England Power Pool stakeholders.
“Market participants have expected for over a year that their participation in FCA 10 would be based on both system-wide and zonal sloped demand curves. Clearing capacity resources on a curve better reflects the incremental value of capacity and leads to a more efficient market outcome,” NEPGA wrote.
