New York Attorney General Eric Schneiderman asked FERC on Friday to prevent a natural gas pipeline developer from clearing trees along the route of one of its projects while water quality permits are pending (CP13-499).
Constitution Pipeline wants to build a 124-mile pipeline through New York to connect shale gas fields in Pennsylvania with markets further east.
“Since cutting down trees in the pipeline corridor constitutes construction, the [Office of Energy Projects] may not grant the request to proceed unless and until Constitution has obtained all of the authorizations required under federal law to construct the proposed pipeline,” Schneiderman wrote in his request for a stay.
The pipeline has all the necessary permits except for water quality certification under Section 401 of the U.S. Clean Water Act. That application is pending before the state Department of Environmental Conservation. The project would cross 220 bodies of water along its route, according to the attorney general.
Schneiderman said tree cutting would cause “irreversible alterations” to property before required permits are obtained.
Constitution told FERC in January 2015 that tree cutting must be conducted between Nov. 1 and March 31 to comply with U.S. Fish and Wildlife Service recommendations to mitigate impacts on migratory birds and the northern long-eared bat.
“Constitution is therefore requesting written authorization … to commence limited, non-mechanized tree felling activities necessary to comply with these conservation measures,” the company wrote to FERC.
The developer said it would use chainsaws to cut trees at or above ground level and would not disturb soils or root systems. It said it would leave the felled trees in place until other construction started.
FERC granted Constitution a certificate of public convenience and necessity in December 2014. The project has encountered fierce opposition from the group Stop the Pipeline, which cites environmental threats to streams, wetlands and forests along its route. (See Constitution Pipeline Opponents Asks Appeals Court to Force FERC Action.)
Entergy wants state regulators to appoint an administrative law judge to counteract “political pressures” and referee disputes with New York officials in an investigation of the Indian Point nuclear power plant’s operations (15-02730).
The plant owner on Tuesday asked the New York Public Service Commission to appoint the judge to handle disputes over confidential documents and other matters related to an investigation of the plant ordered last month by Gov. Andrew Cuomo after two unplanned outages.
Indian Point Nuclear Power Plant (Source: Wikipedia)
Cuomo has called for closure of the plant for several years because of its proximity to New York City. He said the plant’s two units have had 13 unplanned shutdowns since June 2012, including two incidents nine days apart last month.
“We must ensure that the 20 million people that live within the shadow of Indian Point are truly safe from a nuclear incident … [so] I would specifically request that you examine the capital and maintenance budgets at the plants and their potential impact on these outages, and the impact these sudden outages can have on the continued safe operation of the plants,” Cuomo wrote in a letter to PSC Chairman Audrey Zibelman on Dec. 16.
Cuomo ordered the PSC to report the findings of its investigation by Feb. 15.
In two rounds of interrogatories in recent weeks, Entergy said, PSC staff sought information on finances and operations that go beyond a state’s jurisdiction and are the purview of federal regulators.
“Given the political and timing pressures being imposed on [Department of Public Service] staff, there is a particular need for an impartial ALJ to resolve Entergy’s objections,” the company wrote.
“The investigation is equally unprecedented in that it seeks highly detailed financial and operational information regarding Indian Point spanning across five- to 10-year time periods, even though Indian Point must earn its revenues from the wholesale markets pursuant to tariffs within the exclusive regulatory authority of the Federal Energy Regulatory Commission.”
Entergy said it will cooperate “in good faith” with many aspects of the investigation but finds the scope “objectionable.”
In December the Nuclear Regulatory Commission told Entergy it can continue to operate Indian Point’s Unit 3 under its existing 40-year license, which expired last month, while its license renewal review continues. Unit 2’s license expired in 2013, but it is also operating under an extension while the company’s application is under review.
The two outages that prompted Cuomo’s action occurred on Dec. 5 and 14.
In the first incident, a faulty electrical breaker controlling a roof fan caused a trip at Unit 2, according to NRC. The commission said operators manually shut down the reactor when the faulty breaker caused a drop in voltage to the mechanisms controlling about 10 of the reactor’s control rods.
On Dec. 14, Entergy said the shutdown was caused by a “disturbance” on the non-nuclear side of the plant that connects to the grid.
FERC on Wednesday approved the sale of two upstate New York power plants, the same day Gov. Andrew Cuomo vowed the generators would “transition” away from coal or be closed by 2020.
The commission approved the sale by Upstate New York Power Producers of the 312-MW Cayuga plant outside Ithaca and the 668-MW Somerset facility in Niagara County to Blackstone Group unit Riesling Power “as consistent with the public interest” (EC15-214).
With the Dec. 31 mothballing of NRG Energy’s Dunkirk plant and the 380-MW Huntley Power Station in Tonawanda expected to close at the end of March, Cayuga and Somerset will be the last two coal-fired plants in New York.
Cayuga Plant (Source: Wikipedia)
Their continued operation runs headlong into Cuomo’s clean energy agenda, which calls for the state to obtain 50% of its energy from renewable resources by 2030.
Cuomo repeated that pledge in his annual State of the State address Wednesday. “We will eliminate all use of coal in New York state by 2020. We will help the few remaining coal plants transition, but we must clean our air and protect our health and that must be our first priority,” Cuomo said.
According to the governor’s office, coal accounts for 4% of electricity generation in New York, a number sure to drop even more absent Dunkirk and Huntley.
A group of bondholders formed Upstate New York Power Producers to purchase Cayuga and Somerset from the bankrupt AES Energy East for $240 million in 2012. No price was disclosed when the sale to Riesling was announced in September. (See Blackstone Seeks Two Coal-fired Plants in New York.)
Cayuga is operating under a controversial reliability support services agreement that runs until June 30, 2017. It also has a proposal before the New York Public Service Commission to repower to natural gas with ratepayer assistance paid over the next 10 years. (See Cayuga Power Plant Repowering Opposed.)
The Sierra Club, which opposes the above-market payments, asked FERC to compel Riesling to provide information regarding the Cayuga plant’s future.
FERC ruled those questions outside the scope of the proceeding and said the sale “will not have an adverse effect on rates.”
No plans about the future of the Somerset plant have been made public. “There are a number of announced initiatives on the future of energy markets in the state of New York. The details on how they will be achieved while maintaining a reliable electric system in the state at a fair economic price will highlight the importance of these assets to the system,” Riesling spokesman Michael Enright said Monday. “We look forward to reviewing the details of the governor’s plan and will, upon approval of the sale by the PSC, seek to promptly engage in constructive dialogue with major stakeholders to create a path forward.”
That path, according to a briefing book released in conjunction with Cuomo’s budget, includes a directive to state regulators to work with NYISO to “develop a regulatory framework that will ensure system reliability while facilitating repowering to cleaner fuel or closure.”
In reaction to the budget and in anticipation of pending action before the New York Public Service Commission promoting clean energy development, an organization representing power generators again emphasized a market-based approach.
Gavin Donohue, CEO of the Independent Power Producers of New York, said “generators that are able to meet their emissions requirements and perform economically should be allowed to operate in the state.
“State strategies that pick winners and losers are especially redundant in light of record low fuel and wholesale market prices that are currently driving uneconomic facilities to retire,” he continued. “Just this past December, New York saw the lowest wholesale price of energy since the market was created, and those prices are being reflected in consumers’ energy bills and generators’ decisions to invest in new resources.”
Dhiman Chatterjee, MISO’s senior manager of market analysis, said he expected the commission to approve the request, which will be filed Feb. 1. The commission approved the product in October 2014 (ER14-2156).
“They have understood the need for a product to explicitly address ramp concerns,” he said at a technical workshop Friday, which focused on how stakeholders should incorporate new ramp capability software into their systems and how the product fits into MISO’s market.
“We’ll do our best to do what we can [to answer questions] today, and if we can’t address it today, we’ll make a note. We do have some time before the go-live date,” Chatterjee said.
A ramp capability customer care line is scheduled to open Feb. 9. MISO plans to make the production interface on ramp capability offers available on March 25.
In Development Since 2011
The software, which has been in development since 2011, is designed to respond to short-term variations in load by holding back a portion of rampable capacity from the five-minute dispatch.
With “increasing renewable penetration and interchange flexibility, net load variations and uncertainties impose challenges to maintain real-time power balance,” MISO said.
MISO will set ramp requirements for the day-ahead and real-time markets based on load forecasts and historical analysis. The new products won’t eliminate all short-term scarcity events, such as sudden generator losses and large changes in interchange.
“Now we’ll have the capability to prepare for both the anticipated and unanticipated ramp needs,” MISO Market Design Engineer Congcong Wang said.
Jason Howard, manager of market quality, said while participation isn’t mandatory, it would be difficult for operators to completely ignore the ramp software’s benefits, as revenues earned from software use would contribute toward reducing any owed make-whole payment.
“We’re essentially saying in our FERC filings that this is like our [revenue sufficiency guarantee] make-whole payments,” he said. Up or down ramp capability will be included as additional revenue components under the revenue sufficiency guarantee.
Resources able to respond to five-minute energy dispatch instructions — generation, type II demand response and external asynchronous resources — will be able to offer ramp capability. Energy storage is not eligible and dispatchable intermittent resources will be able to provide down ramp based on their ability to reduce output in accordance with load following needs.
Opportunity Costs
Resources that are dispatched out of merit order through the clearing of up or down ramp capability will be compensated for lost opportunity costs at a maximum of $5/MWh.
MISO says the product could save $3.8 million to $5.4 million in dispatch and commitment costs.
Howard said use of the ramp product will result in two new line items on settlement statements, a day-ahead procurement charge and a real-time procurement charge. Payments for those providing ramp will be included under make-whole payments.
Chatterjee said MISO will likely conduct a study on the ramp product to gauge effectiveness over its first few years of operation.
Jason Fogarty said Potomac Economics, MISO’s Independent Market Monitor, is supportive of the product. He said he isn’t worried about a small number of resources not offering ramp, but he would become concerned if a large portion of resources decline to participate.
“If ramp capability withholding becomes prevalent, we would make a suggestion to MISO to update their software programs,” Fogarty said.
Going forward, Fogarty said, the Monitor will report quarterly on quantities of withheld up or down ramp capability, the impact of the $5 demand curve on procurement and any potential “market power or efficiency concerns.”
MISO Senior Customer Trainer Ron Matlock said additional training sessions for stakeholders will be held on Feb. 17, Feb. 24 and March 2.
FERC has accepted ISO-NE’s 390-MW reduction in its load forecast, reflecting the impact of distributed solar resources.
The commission rejected the New England Power Generators Association’s contention that the calculations for behind-the-meter generation hadn’t been sufficiently vetted (ER16-307).
“We find that ISO-NE has properly incorporated non-embedded solar resources into its [installed capacity requirement] calculation and has supported that action. We dismiss the arguments made by protesters to the contrary,” FERC wrote.
Solar is only a small piece of the 35,126 MW of ICR resources in the 10th Forward Capacity Auction set for next month, but the reduction was enough to displace the need for one small generating plant for the 2019/20 capacity commitment period.
The RTO said the only change in its assumptions from prior auctions was the inclusion of behind-the-meter solar resources that are not yet reflected in historical loads.
However, FERC ruled that the process by which stakeholder committees had considered calculations for the solar values had conformed to the RTO’s Tariff, even though ISO-NE, the New England Power Pool and various stakeholders had failed to reach consensus.
OKLAHOMA CITY — Member frustrations with SPP’s Z2 crediting project bubbled to the surface again last week when staff told the Markets and Operations Policy Committee of a new delay.
“It’s an open wound that continues to fester and opens again whenever we seem to make progress,” said The Wind Coalition’s Steve Gaw.
SPP staff told the MOPC last Tuesday the project’s complexity and the challenges in processing historical data have pushed the project’s expected completion to November, when the first Z2 credits are now expected to be invoiced.
Not Pleased
That did not please members, who had been expecting an initial indication of their liabilities or credits this month.
The Z2 crediting project dates back to the last decade as a result of years of incorrect credits for transmission upgrades. The task force working on the project estimated last year creditable upgrades of $750 million but said in October it hoped to present better estimates this month. (See “Z2 Crediting Task Force Remains on Track” in SPP Markets and Operations Policy Committee Briefs.)
Some members requested notice from SPP about the size of the impact.
“We don’t know if it’s a 5-gallon bucket, a semi-trailer or an oil tanker,” said Oklahoma Gas & Electric’s Greg McAuley. “I can’t give my executive team any insight at all. We would like some transparency so we know what the size of the bucket is. If it’s a $5 issue, we don’t care. If it’s $5 million, we do.”
“Every single entity in this room gets impacted, because the longer this festers, the more FERC gets interested,” Gaw said. “The delay does not keep the amount of money from accumulating.”
Upgrades Since 2008
The project team is developing software that will properly credit and bill transmission customers for system upgrades that date back to 2008, in accordance with Tariff attachment Z2. The problem has been avoiding over-compensating project sponsors and including a way to “claw back” revenues from members who owe SPP money for other reasons.
“The project goes so far back in time many databases have changed format,” said Steve Purdy, manager of transmission service studies. “We knew there would be some of that, but those issues are taking longer to deal with than we initially anticipated.”
Purdy said staff has “modularized” the system, so that some software is functional before others. Staff has completed two modules — accounting for 48 of 58 total system components — and is testing a third.
Purdy said 17% of the components have yet to be developed, but that the transmission owner and customer collection effort is mostly complete. He told the committee that additional testing will be required to cover the more complex processes, where some manual procedures are in place.
“We will process data, stop and make manual adjustments,” Purdy said. “The system run times are estimates. We haven’t exercised the system yet, so we’re basing the estimates on what we think it will look like.”
Staff now expects the historical data processing to begin in late March and run through late August. The first reports would be generated and reviewed in August and September, with invoicing beginning Nov. 4.
“NextEra certainly doesn’t feel any better about this, given the answer you just gave,” said Aundrea Williams, director of regulatory affairs and strategies for NextEra Energy Transmission. “[This project] is past red, perhaps maroon. Why are you more confident today that I can rest assured Nov. 4 is a real date? Is there any way we can get anything going before Nov. 4?”
Additional Staff Assigned
Purdy said additional staff has been assigned to the project and some work is being conducted in parallel “to see if we can speed this up.” Staff is also considering postponing some work past the Nov. 4 go-live date and conducting “outreach sprints” with affected parties to speed up the process.
Purdy noted the project estimates are on the “long side,” given the historical data processing piece in the middle is “the squishiest part of the schedule.”
ITC Holdings’ Marguerite Wagner reiterated members’ desire for an “order of magnitude” number. Charles Locke, SPP lead regulatory analyst, responded, saying, “It’s a very long and complicated calculation even to provide an order of magnitude. We may be able to provide data on the gross payment obligations before September, but that won’t give the broad spectrum of impacts across SPP.”
“It’s very hard for me to explain in our public world,” said Xcel Energy’s Bill Grant, referring to his company’s responsibilities to shareholders and regulators. “This may be a big financial decision we’re fixing to make, or not at all. I don’t want to go back and say I made the wrong decision because I didn’t have the right information.”
Staff promised improved communications around the project. Gaw said when he participated in a Regional Tariff Working Group meeting two weeks’ prior, the November date was never mentioned.
“We will program in a number of checkpoints once we start processing data. The checkpoints will allow us to make more frequent adjustments to the schedule so we know what we have,” Purdy said.
‘Back Burner’
“It’s easy to look back and say we knew it would be hard,” MOPC Chair Noman Williams, of South Central MCN, told the Strategic Planning Committee on Thursday. Williams said the Z2 project “got put on the back burner” as SPP introduced the Integrated Marketplace and added the Integrated System.
“Getting our hands around all that data and the numbers is not an impossible task, but it will take a lot of effort to get there,” he said.
Given the project’s current status, the MOPC delayed approving a payment plan until its April meeting. The task force is currently suggesting two options, a traditional payment plan and a staggered billing approach, either of which will require a FERC filing.
Under the payment plan, SPP would offer each entity the option of being billed the entire amount at once (thus avoiding additional interest) or in equal installments, as determined by stakeholders. Under the staggered approach, stakeholders would be billed based upon time increments; years one and two would be billed in the first quarter after go-live, years three and four in the second quarter, and so on.
SPP’s regulatory and legal departments are currently identifying any Tariff provisions required by implementing the credit billing process.
Dynegy entered the Ohio PPA fray last week, floating an offer to the Public Utilities Commission of Ohio that it said would save consumers in the state $5 billion over eight years.
The company said it was making its counter offer “in response to the exorbitant and counterproductive subsidies currently under consideration” for American Electric Power and FirstEnergy. It would either provide power from its existing generation fleet in the state, or replace subsidized American Electric Power and FirstEnergy plants with new, natural gas-fired generation.
The Ohio-based companies have proposed power purchase agreements to PUCO that would provide a guaranteed return for their embattled generating stations for eight years. PUCO staff has signed on to both proposals, which have been attacked by independent power producers and others. (See Merchant Generators Lead Opposition to FirstEnergy-Ohio Settlement.)
Dynegy’s offer comes two weeks after Exelon made its own offer to PUCO, proposing a competitive bidding process to supply the 3,000 MW for which FirstEnergy is seeking guaranteed rates (the combined value of FirstEnergy’s W.H. Sammis coal plant and its Davis-Besse nuclear station).
Local Provider?
One difference in Dynegy’s offer is that it bills itself as a local provider. “The power provided by Dynegy will be generated by Ohioans, at Ohio plants, for Ohioans,” Dynegy said in its announcement. Dynegy said it has 5,400 MW of generation in Ohio and hundreds of employees in the state and would use the state’s natural gas, “providing further benefits to the state.”
Dynegy CEO Robert Flexon, who has threatened to sue if PUCO accepts either the AEP or FirstEnergy proposals, said his company has the winning answer.
“If the PUCO and other elected officials in the state are interested in protecting consumers’ and businesses’ long-term interests while ensuring long-term reliability and price stability, then in lieu of accepting FirstEnergy’s and AEP’s proposals for long-term power purchase agreements, the PUCO should adopt one of the alternate, superior proposals Dynegy is putting forth,” he said. “The PUCO could also institute a request for proposal process containing the same arrangements in the AEP and FirstEnergy PPA proposals. Exelon’s recent proposal is also thoughtful, and Dynegy agrees with Exelon that this process should be competitive.”
Flexon will join CEOs from Calpine, NRG Energy and Talen Energy, as well as officials from Advanced Power and the PJM Power Providers Group (P3), in Columbus on Wednesday to lobby against the deals. The officials will hold a press conference at the state capitol at 2:15 p.m.
FirstEnergy: Dynegy ‘Misses the Point’
FirstEnergy spokesman Doug Colafella said Dynegy’s offer is off the mark.
“Dynegy’s proposal offers few specifics and provides no assurances that its power plants in the region will continue operating over the long term,” he said Friday. “Dynegy is a power marketer from Houston with an established track record of entering and exiting competitive markets. While its brand of investors may be willing to tolerate its ‘boom and bust’ approach to energy markets, this approach fails to deliver on two key policy goals in Ohio — energy stability and economic stability.”
“In addition,” he said, “Dynegy’s offer to fill the void with gas-fired plants if Sammis and Davis-Besse were forced to close completely misses the point about having a diverse set of fuels available to produce electricity in Ohio, an important ingredient for ensuring price stability for customers.”
AEP: Dynegy Wants Higher Prices
AEP Ohio spokeswoman Terri Flora also took a shot at Dynegy’s new generation option.
“If Dynegy could build new generation in Ohio under current market conditions, they would,” she wrote. “But, they haven’t built new generation in Ohio and they can’t afford to build it under current conditions. They need energy costs to rise dramatically for their business model to work so they want to force existing power plants to close.”
FirstEnergy Hearings Continue
The sparring proposals and letters came as PUCO continued hearings last week on the FirstEnergy proposal. The hearings are expected to run through the end of this week. Final arguments are likely in February and a commission vote possible by March, the Cleveland Plain Dealer reported.
On Thursday, lawyers for the Sierra Club questioned PUCO’s director of rates and regulatory affairs about FirstEnergy’s projection that natural gas prices will rise above $4/Mcf — a key assumption in the company’s contention that its proposal will save consumers money.
Prices for January are below $2.40/Mcf and New York Mercantile Exchange futures are below $4 through 2024.
Amid an industry in transition, “a number of states are considering retail rate policy reforms that support long-term resource planning, generator diversity and economic stability,” wrote Steven Strah, president of FirstEnergy Utilities. “While some participants may disagree with our proposal, it is legal from a state and federal perspective, and consistent with traditional state and federal regulatory rules.”
Strah also criticized PJM’s request that PUCO require FirstEnergy and AEP’s Ohio generators to offer their output into the RTO’s markets at no lower than their actual cost, with no consideration of offsetting revenue provided by Ohio retail customers. (See PJM Seeks Changes to AEP, FirstEnergy PPAs.)
Strah said such a mandate would violate federal appellate court rulings that prohibit state regulators from “dictat[ing] generator offer behavior in PJM’s FERC-jurisdictional wholesale markets.”
Meanwhile, the independent generators received support from Advanced Power Asset Management, which is developing two combined cycle projects in Ohio.
In its letter to the PJM board, it called the FirstEnergy and AEP deals “a special subsidy to incumbent Ohio- and Indiana-based PJM generators [that] will circumvent the PJM capacity and energy markets,” lowering prices for other market participants and creating a disincentive to new investment.
Advanced Power is developing Carroll County Energy, a 700-MW natural gas-fired combined cycle generator expected to go online in the second half of 2017. The $899 million project is fully funded, “predicated on the PJM market mechanism, which is the largest and most liquid competitive capacity and energy market in the U.S.”
Also being developed — but not yet funded — is the 1,100-MW South Field Energy combined cycle project in Wellsville, Ohio.
WASHINGTON — Stakeholders from Maryland, Delaware and New York urged FERC last week to allocate the costs of the Artificial Island and Bergen-Linden Corridor transmission projects more broadly across PJM, while utilities in New Jersey and Pennsylvania called for continued use of the solution-based distribution factor (DFAX) method.
The forum focused on two questions: Is there a definable category of projects for which the DFAX cost allocation method might not be appropriate, and could a fair approach be developed prospectively for those occasions?
PJM Vice President of Planning Steve Herling told the commission staff that the RTO could devise an alternative to DFAX for certain fixes, but the scheme would be tricky to develop and wouldn’t be used very often.
Artificial Island (Source: Wikimedia)
PJM presented a matrix of project categories, showing that they could be defined as thermal violations, voltage/reactive, stability, short circuit, storm hardening, end of life/aging infrastructure or real-time operation concerns.
Since 2000, when PJM inaugurated its Regional Transmission Expansion Plan, there has been only one project each for the stability, short circuit and storm hardening categories. Artificial Island is the stability project; the Bergen-Linden Corridor is the short circuit project.
Regarding stability projects, Herling said, “I honestly don’t think we’re going to see many of those going forward. We might see one more next year and not another in 20 years.”
Solution-based DFAX works well for most of the project categories, Herling said, because in most cases those who caused the problem are the same ones who will benefit from it being repaired. The flow of electricity that the projects are designed to enhance can be measured. But flow is not the driver of stability or short circuit fixes.
“With stability and short circuit, that’s a trickier proposition,” Herling said.
Thirty years from now, for example, the stability benefits of the Artificial Island project probably won’t exist because one or more of the Hope Creek and Salem nuclear reactors might be retired.
“The point is that the initial benefit of solving the problem fades over time. So is there a way to calculate the benefits of solving the problem? There very well may be,” he said.
“The big benefit of going to DFAX is that you don’t have to divvy up all the problems and all the beneficiaries. You have one solution. Then you look at who’s using the fix. And that can be looked at year by year,” he said.
Status Quo
Testifying at the conference in favor of keeping the status quo for all projects were Frank Richardson of PPL and Takis Laios of Transource Energy, representing the PJM Transmission Owners, and Esam Khadr of Public Service Electric and Gas.
New Jersey’s Board of Public Utilities and Division of Rate Counsel also submitted comments recommending that the commission not distinguish among projects for cost allocation. “All projects to ensure the reliability of the bulk transmission system are related to flow,” the filing said.
It also noted that if the cost of the Artificial Island project is figured differently, it would allocate more costs to New Jersey ratepayers.
DFAX Unfair
Advocates for customers on the Delmarva Peninsula protested the DFAX methodology, which charged them the bulk of the Artificial Island fix.
“For non-overload projects, there is no rational relationship between flows and intended benefits,” Sasson said. “This makes the use of distribution factors as part of the DFAX analysis a ‘poison pill.’”
Short circuits, for example, are system disturbances, not the result of customer demand, he said, and the intended beneficiary is the transmission zone where the problem exists. The typical solution is to upgrade the breaker, not build a transmission line.
“The Bergen-Linden Corridor Project is intended to fix short circuits in PSE&G’s service territory. And as PJM recently informed its stakeholders, it remains necessary with or without the flow from Con Edison’s transmission contracts. Clearly, PSE&G is its intended beneficiary,” he said.
Laios, of the PJM TOs, argued that all projects involve flow.
“Why are circuit breakers there? They’re at a facility to carry flows. You could figure out who tripped it, but you’re back to a one-time violation calculation.”
He was referring to the violation-based DFAX method, a predecessor to the solution-based model, which went into effect in 2013.
Sasson said Con Ed is not proposing the violations-based method. “Our position is that, for non-overload projects, no DFAX analysis can apply because there is no rational or technical relationship between flows and intended beneficiaries.”
Ringhausen agreed. Representing 20% of the load in the Delmarva zone, ODEC stands to pick up a significant portion of the Artificial Island project cost. The primary component of the project is a 230-kV line that is not required to resolve any thermal or voltage reliability issues caused by load growth in the Delmarva zone, he said.
“The results of solution-based DFAX, then, do not signify any significant benefit to the Delmarva zone from the new line that could justify the proposed cost allocation.”
Allocation Based on Economic Benefits
“For a generator stability problem like Artificial Island, one potential alternative would be to allocate costs based on the relative proportion of economic benefits that result from a stability upgrade since a primary benefit of such a project is to increase the availability of a generator’s output to provide capacity and energy to the PJM region,” Ringhausen said.
PSE&G’s Khadr, however, pointed out that the project gives the Delmarva area, which has been subject to transmission constraint, another high capacity line. He also noted that about 30% of the zone’s generation is more than 40 years old and at high risk of retirement.
Laios cautioned creating “carve-outs” for certain projects.
“You’re inviting another driver where someone doesn’t like the cost allocation to argue they should be included in that carve-out,” he said. “Once you start a carve-out, where do you stop?”
PPL’s Richardson said that any attempt to categorize some reliability projects differently would be “fraught with problems.”
“Some results may look strange,” he conceded of the DFAX methodology. But, he said, “It is not arbitrary. It is defensible, and it is the best method that we have.”
Weishaar, counsel to the Delaware Public Service Commission, suggested that a cost allocation method based on economic benefits would be the best option to address stability issues.
“The process would be objective and neutral,” he said. “A narrow exception to the DFAX rule need not swallow the rule. It may be appropriate for the overwhelming number of projects.”
Ringhausen also backed an economic-based allocation.
“We would have PJM run their market efficiency models and allocate the cost based on that,” he said. “Solution-based DFAX is better for most, but for certain projects, it is not matching cost and beneficiaries appropriately.”
Laios objected to the idea of an economic solution.
“Why would you use economics for reliability projects?” he said. “If you did, wouldn’t you feel compelled to do it for all the projects? It’s still a one-time calculation. It’s not updateable each year.”
FERC staff said they would regroup to see if they had any more questions for the participants. Meanwhile, FERC on Thursday granted a rehearing for further consideration of PJM’s Tariff changes involving the cost allocations.
OKLAHOMA CITY — Reducing SPP’s current 13.6% reserve margin to 12% could cut required capacity by about 1,000 MW, saving $86 million annually and $1.3 billion over 40 years, a task force told the Markets and Operations Policy Committee.
The Capacity Margin Task Force has been evaluating resource adequacy since SPP became a central balancing authority with the Integrated Marketplace’s implementation in 2014. The RTO’s capacity margin has been unchanged since 1998 despite an expanding footprint, operational changes and significant transmission expansion.
Task Force Chairman Tom Hestermann, manager of transmission policy for Sunflower Electric Power, said the group believes the reserve margin can be reduced without affecting reliability. He said stakeholders have been supportive of reserve margins as low as 12.5% but less so when the margin drops to 12% or less.
“The more reserves you require, the more it will cost,” he told members during a four-hour educational forum preceding the MOPC meeting. “We want a good balance between reserve margins and system reliability. If 12% is where we want to be, we have a good story to tell. We believe we can do this successfully.”
The savings would come from reduced generation investment made possible by transmission upgrades. Hestermann said lower margins could align with generation retirements due to the Clean Power Plan.
Hestermann noted resource adequacy is generally expressed in terms of capacity margin or reserve margin for planning purposes. Both are measured using the same numerator: the difference between available resources and net internal demand. SPP uses capacity margin, in which resources serve as the denominator. Reserve margin, used by NERC and other regions, uses net internal demand as the denominator.
Hestermann said the task force will recommend switching to reserve margin, where a 13.6% margin is equivalent to a 12% capacity margin.
“NERC doesn’t have a standard for planning reserves,” Hestermann said. “SPP enforces this requirement through the membership agreement.”
The task force ran “limbo studies” — “How low can you go?” Hestermann explained — that simulated four reserve margin levels for each of three years: 2016, 2017 and 2020. The analysis found SPP could maintain required loss-of-load expectations in every case except 2017, and then only when the reserve margin was set at 7.53%. (The study assumed additional transmission infrastructure.)
“The current criteria requires an assessment every two years to ensure 12% is adequate,” Hestermann said. “What we haven’t done before is see whether we can go lower than that and still maintain a reasonable level of reliability.”
The task force has completed a white paper defining load-responsible entities, which was approved by MOPC and the board last July and is currently being discussed within various task forces. Tariff revisions or changes to previously approved policy will be brought back to the MOPC for approval.
The group will present its reserve margin requirements and a deliverability study for MOPC approval in April. It also will present a planning reserve assurance policy, an enforcement mechanism using payments, not penalties, from LREs short on capacity to those who are long.
The task force also is still working on a distributed energy resource policy.
RTOs and ISOs will take part in 15 research and development projects awarded almost $38 million in funding by the Energy Department last week.
U.S. Energy Secretary Ernest Moniz last week announced $220 million in funding as part of the Energy Department’s Grid Modernization Initiative, an effort by the Obama administration to integrate new technology into the country’s energy infrastructure.
The department awarded the funds over three years, subject to congressional appropriations, to its national laboratories. The labs will partner with grid operators, energy companies, universities and local government agencies on 88 projects, ranging from advanced storage systems to improving transformer resiliency, to accommodate increased transmission from renewable sources.
“Modernizing the U.S. electrical grid is essential to reducing carbon emissions, creating safeguards against attacks on our infrastructure and keeping the lights on,” Moniz said. “This public-private partnership … will help us further strengthen our ongoing efforts to improve our electrical infrastructure so that it is prepared to respond to the nation’s energy needs for decades to come.”
“A modernized grid will enable two-way communication and data flows, allowing operators to better understand the grid’s immediate operating status,” said Franklin Orr, DOE undersecretary for science and energy. “By having this information, operators can run the grid closer to its full potential and capabilities, resulting in greater efficiencies and reliability.”
PJM in 8 Projects
PJM will take part in eight projects, followed by ERCOT with six, MISO with five and ISO-NE, NYISO and SPP with three each, according to the department. CAISO is participating in one project.
Click for detailed description of projects.
The eight projects in which PJM is participating were awarded about $25 million. One involves enhanced grid modeling; the others address transmission reliability, said Emanuel Bernabeu, manager of applied solutions.
Bernabeu called the modeling project “critical.”
“Our load changes rapidly. The composition is changing, and the way the customer behaves is also changing,” he said. “Our model needs to be able to capture that. Otherwise, when I run a [model], it may not match reality.”
The project, which will cost $2.7 million, will be developed at Argonne National Laboratory in partnership with Iowa State University, ERCOT, Commonwealth Edison and Alliant Energy, among others.
The other projects span a wide range of grid reliability. One aims to improve situational awareness in the control room. Another project, a $3 million effort across eight of the labs, aims to enhance the modeling of extreme events, including cold weather, hurricanes and geomagnetic disturbances. “Extreme weather is becoming more prevalent now,” Bernabeu said.
SPP, MISO Team on Seams Project
SPP and MISO will be the key players in an effort to evaluate the HVDC and AC transmission seams between the U.S. interconnections, according to SPP. The $1.2 million Midwest Interconnection Seams Study “will explore timely questions about aging infrastructure and enhance existing regional and interregional planning processes,” said Lanny Nickell, SPP vice president of engineering.
“It’s a long overdue study. SPP has been recommending such a study to investigate the interconnections between the eastern and western grids,” said Jay Caspary, director of research, development and special studies for SPP. The project will also involve the Energy Department’s Western Area Power Administration, the Solar Energy Industries Association, Minnesota Power and Xcel Energy. “No individual regional planner can do this on their own,” Caspary said.
“This important work will play a key role as MISO continues to ensure reliability now and in the future,” said Jennifer Curran, MISO vice president of system planning and seams coordination.
Some RTOs’ Roles Unclear
It is unclear to what degree each RTO and ISO will play in the projects.
ISO-NE said it is only acting as an adviser to the labs for certain projects. NYISO said that, though it is listed on the department’s website, it declined to partner with it on WindView, a $1.8 million visualization program that would display wind forecast information along with system power flows in order to better monitor how wind power affects the grid as the resource becomes more prevalent throughout the U.S.
Companies Involved
Also among those participating in the projects are:
Utilities (including Southern Co., Dominion Resources, Tennessee Valley Authority, Duke Energy, National Grid, Louisville Gas and Electric);
Equipment suppliers (Alstom Grid, GE-Alstom, United Technologies);
Research organizations and universities (Electric Power Research Institute, George Washington University, UNC-Charlotte, Clemson University, University of Vermont, Regulatory Assistance Project, New York State Energy Research and Development Authority);
Trade associations (American Public Power Association, National Rural Electric Cooperative Association).
Suzanne Herel, Tom Kleckner, Amanda Durish Cook and William Opalka contributed to this report.
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