PJM told the Capacity Construct/Public Policy Senior Task Force (CCPPSTF) that it would eliminate the minimum offer price rule (MOPR) and include all units to which it currently applies in its new repricing structure.
“We would apply repricing as opposed to a MOPR approach,” said Stu Bresler, PJM’s senior vice president for operations and markets. He said existing MOPR exemptions would continue.
Bresler also announced two other changes to its proposal.
Any offers that trigger repricing would have their offer adjusted to the avoidable cost rate (ACR). PJM would maintain a table of default ACR values by resource class and location, but resource owners could submit unit-specific ACRs if preferred. “We heard loud and clear through the poll results that net CONE [cost of new entry] times B [as the adjusted offer] was not a popular approach,” Bresler said.
In addition, states’ option to direct PJM to pay adjusted resources less than restated capacity prices was removed. In the revised proposal, every cleared resource will receive the restated clearing price.
The number of proposals before the task force dropped by one when John Horstmann of Dayton Power and Light retracted his “capacity choice” proposal. That leaves eight options before the task force; Old Dominion Electric Cooperative had removed its repricing proposal from consideration in September.
There was no mention at the meeting of the Organization of PJM States Inc.’s Oct. 9 letter warning the PJM Board of Managers away from task proposals that OPSI said could raise prices significantly and restrict state public policies. (See related story, State Regulators Unhappy with PJM Capacity Discussions.)
But several proposers made revisions that appear to be keeping OPSI’s concerns in mind. American Municipal Power and LS Power updated their definitions for an “actionable” subsidy that expand upon the Independent Market Monitor’s definition for its extended MOPR proposal. The definitions identify exclusions for government-sponsored or -mandated procurement. The LS proposal specifically excludes renewables development and demand response programs.
The Monitor likewise added two exemptions to its MOPR proposal for public power and renewable portfolio standards.
CARMEL, Ind. — After months of stakeholder discord surrounding MISO’s plan to incorporate external zones into its capacity auction and divvy up excess auction revenues, Entergy last week emerged with its own plan.
The proposal comes a month after the RTO announced it would delay creation of external zones until the 2019/20 planning year and asked stakeholders to come forward with ideas on hedging mechanisms that would distribute excess revenues to external resources. (See MISO Postpones External Zones Until 2019 Auction.)
During an Oct. 11 Resource Adequacy Subcommittee meeting, Entergy’s Rachelle Johnson offered a proposal in which market participants would request hedges for supply arrangements with an external resource once a year. To be eligible, those arrangements must be active during the upcoming delivery period, have a term of at least five years and not already be covered by a hedge, Johnson said.
MISO would then perform a feasibility test of requested hedges using auction estimates from its loss-of-load studies, and deny hedges if they exceed estimated funds. If the amount of surplus auction revenue was insufficient to fund all outstanding hedges, then the funding of those hedges would be reduced proportionally.
Market participants would receive hedges for the next five years in the event the resource did not clear in the auction, Johnson said.
WEC Energy Group’s Chris Plante asked whether the proposal intended to align hedging with firm transmission service. Johnson said it could.
Indianapolis Power and Light’s Ted Leffler wondered whether external resources with firm transmission service would stop promising capacity to a particular zone, and instead shop for the best zonal resource credit.
“Are you just going to look for the easiest, cheapest place to dump it?” he asked, adding, “Not that that’s a bad thing.”
Laura Rauch, MISO manager of resource adequacy coordination, said firm deliverability means to deliver load to anywhere within the RTO, not to any particular zone or load.
Plante, who is also RASC chair, asked for more stakeholder proposals on how to provide hedges to external capacity suppliers. “This is why MISO delayed this, to get more stakeholder input on this topic,” he reminded stakeholders.
Rauch said MISO will continue to hold discussions on external zones in upcoming meetings up until its planned filing with FERC in early spring. She said MISO would lead more discussion on external zone hedging, in addition to how pseudo-tied resources and fixed resource adequacy plans would interact with external zones and how it will define border resources.
SAN DIEGO — The CAISO-run Western Energy Imbalance Market (EIM) has increased the operational flexibility of the region’s utilities and is leading to changes in resource procurement in states outside California, utility representatives said last week.
Speaking on a panel at Infocast’s Transmission Summit West, Matt Lecar, Pacific Gas and Electric principal of ISO relations and FERC policy, said “one of our big challenges is managing solar generation, and the EIM has been extremely valuable” by absorbing generation and reducing curtailment of renewables.
“We get to use more of our clean energy, more of the time,” Lecar said.
The EIM is also serving as a “proving ground as to how create a governing structure for a regional RTO,” he said, creating more planning certainty for entities in the West.
“The key here is to develop a culture of trust,” he said, adding that the EIM is proving the benefits of a regional market, and “the biggest enemy of trust is uncertainty.”
Even though the EIM is presently only a balancing market, it is already having an effect on resource planning in other states, NV Energy Director of Energy Market Policy Lauren Rosenblatt said.
“Now Nevada is highly affected by the regional resource mix in ways it wasn’t before,” she said. Nevada gets a lot of negatively priced solar energy from California, so power suppliers are less likely to build solar photovoltaic because they have the opportunity to obtain solar output from next door.
Idaho Power Vice President of Power Supply Tess Park said it is a positive that the EIM doesn’t require a participant to stay in the market for years, and if things don’t go well, “there is an out.”
The EIM has grown since its launch in November 2014, and panel participants said it has allowed energy resource-rich areas in the western interior to more effectively link up with the load-heavy population centers on the California coast. CAISO said the EIM produced $39.52 million in benefits for its participants in the second quarter, with CAISO gaining the largest share. (See CAISO Leads EIM Q2 Benefits, Exports.) As of the end of the second quarter of this year, benefits have been $213 million from more efficient dispatch, reduced renewable curtailment and reduced need for flexible ramping capacity, the ISO has said.
Portland General Electric joined the EIM on October 1 | CAISO
CAISO Strategic Alliance Director Don Fuller said the EIM has brought better economics and resources to electricity sector participants in the West. By taking advantage of excess capacity on the existing transmission system, the EIM helps avoid building of new transmission lines and makes for a more efficient regional grid.
“The idea was to take advantage of unused transmission, so it worked without new transmission,” Fuller said, adding that as new market participants bring transmission in, it helps all EIM entities move energy around.
The EIM took advantage of CAISO’s existing market platform and allowed easy entry and exit, allowing individual balancing authorities to retain control over their assets and join when they wanted. That has been a “key factor” in its growth, he said.
The market “has been another tool in our effort to manage renewables” and allows neighboring states to take advantage of low-cost power being produced in California, Fuller said.
Portland General Electric on Oct. 1 became the latest utility to begin operating in the EIM, and others have agreed to join but have not yet begun participating. Active participants include PacifiCorp, NVE, Puget Sound Energy and Arizona Public Service. Idaho Power and Powerex are due to join in 2018; Seattle City Light, the Los Angeles Department of Water and Power, and Balancing Authority of Northern California in 2019; and Salt River Project in 2020.
SAN DIEGO — The fate of the West’s coal-fired power was already sealed prior to EPA’s announcement that it will seek to repeal the Clean Power Plan, a panel of industry participants said last week at Infocast’s Transmission Summit West.
But those panelists also agreed there has not been adequate consideration of the impact of coal retirements on the region’s grid. The Trump administration argued that former President Barack Obama’s call for switching to more natural gas and renewable generation caused the agency to exceed its authority. (See EPA to Announce Clean Power Plan Repeal.)
ITC Grid Development’s Ron Belval said that while federal regulation affects coal-fired power, “I think it is going to be an economic decision; the wheels have already been set in motion” by low gas prices and more penetration of renewables. There might be some extension of the life of existing plants, but they will still be retired, he said.
The Western transmission network was designed for a traditional resource mix serving certain load centers, including areas that are served by coal, gas and nuclear, Belval said. The retirements of coal-fired plants will dramatically change how the system will be utilized, but the characteristics of the new system have not been identified.
Belval noted that there are also the requirements of California’s “duck curve” to consider. It is unclear what the mix of new resources will be or exactly where they will be deployed, he said, and the grid has needs in terms of frequency response and voltage regulation.
By 2025, about 5,000 MW of coal-fired capacity is scheduled for retirement in the West — basically all the large plants, according to Keegan Moyer, a principal with Energy Strategies.
“That is most of it; there is not that much more after that,” he said, adding that there is a not a “cookie-cutter” strategy for replacing those resources.
The retirements will free up transmission capacity that could be used by other resources, creating opportunities for new entrants, panelists said.
The transmission system is designed around natural gas plants that have also served to balance renewables and can quickly ramp up, and operators also are used to certain conditions, Belval said. “I suppose you could replace the gas resources, but I don’t know what those would be,” he said, noting that other resources are “not tried and true.”
“You have got to replace those with something that you know works,” and those resources need to be modeled in the operational time frame, he said.
Brian Cole, director of engineering at Arizona Public Service, said that at his utility, “the schedule for shutting down the older [coal] plants had already begun to be put in place. The Clean Power Plan just helped cement that and make that happen.” System operators are seeing the impact of renewables at the transmission and distribution levels, he said.
The coal-fired Mojave Generating Station in Nevada ran from 1971-2005
“We are trying to get our arms around it,” he said, adding that the removal of baseload generation also requires new ramping capabilities.
The CPP’s repeal effort has been accompanied by Energy Secretary Rick Perry’s recent directive that FERC ensure cost recovery for at-risk coal and nuclear generation in organized markets, representing an additional seismic shift in direction at the federal level. (See Perry Orders FERC Rescue of Nukes, Coal.) But panel participants indicated that the proposals are a long way from causing a surge in demand for coal-fired energy resources in Western states.
American Electric Power has filed a complaint against MISO for failing to collect and distribute millions in transmission charges from three defunct load-serving entities more than a decade ago.
In an Oct. 10 filing with FERC, AEP claimed that MISO owes more than $4.8 million to its PJM transmission affiliates after MISO failed to bill seams-related surcharges to energy providers Nicor Energy, Engage Energy America and The New Power Co., all of which shuttered before December 2004, when MISO created the charges (EL18-7). Nicor folded in 2003 amid financial fraud allegations, while New Power was liquidated in bankruptcy that same year. Engage went out of business in 2004.
AEP is seeking the money through the Seams Elimination Charge/Cost Adjustments/Assignments (SECA), a non-bypassable surcharge in MISO’s Tariff intended to recover lost revenues for a 16-month transition period during the elimination of through-and-out rates in late 2004 in the MISO and PJM regions.
AEP said that when MISO was setting up the SECA invoice system, Nicor, Engage and New Power were already defunct and not invoiced, but the RTO nevertheless listed their ensuing charges and “allocated even more SECA charges to the Nicor Energy and Engage sub-zones (based on 2003 data).”
“The allocation of SECA charges to nonexistent LSEs thwarted recovery of the SECA charges, ran counter to fundamental cost allocation principles and resulted in cost subsidies by reducing the SECA responsibility of others,” AEP said. “MISO did not bill and collect SECA charges from the three nonexistent LSEs, nor did it adjust the SECA charges allocated to them (as the RTO did to others) and, therefore, did not remit to the PJM [transmission owners] the revenue from all allocated SECA charges.”
AEP said it asked for compensation from MISO in conference calls in November 2016 and the following August, but the RTO refused to pay. The company asked FERC to either order MISO to pay the charges with interest or set up settlement proceedings to resolve the dispute.
WASHINGTON — A court ruling requiring FERC to consider the impact of greenhouse gas emissions won’t have a “significant” impact on the agency’s licensing of natural gas pipelines, Chairman Neil Chatterjee said Friday.
On Aug. 23, the D.C. Circuit Court of Appeals ruled 2-1 that FERC’s environmental impact statement (EIS) for the Southeast Market Pipelines Project should have included “reasonable forecasting” of the project’s impact on GHG emissions.
FERC had contended that the impact of the pipelines on GHG emissions was unknowable, dependent on variables including the operating decisions of individual plants and regional power demand.
Ruling in a challenge by the Sierra Club, the court said FERC had failed to meet the requirements of the National Environmental Policy Act. FERC “should have either given a quantitative estimate of the downstream greenhouse emissions that will result from burning the natural gas that the pipelines will transport or explained more specifically why it could not have done so,” the court ruled. (See FERC Must Consider GHG Impact of Pipelines, DC Circuit Rules.)
In a press conference Friday, Chatterjee said he didn’t “believe that [the court’s ruling] was going to significantly alter the way that we evaluate these projects.”
Nexus Order
As an example, he pointed to the commission’s Aug. 25 order approving the Nexus Gas Transmission Project, a 255-mile pipeline from Ohio to Michigan (CP16-22) that is being built by DTE Energy and Enbridge’s Spectra Energy. The order contained a lengthy discussion of the environmental impacts of the project, arguing that its analysis complied with the National Environmental Policy Act.
The commission also noted that, in the final days of the Obama administration, EPA had requested the removal of a statement from the project’s EIS that said that there is no accepted methodology for correlating specific GHG amounts to changes in a region’s environment. The agency also asserted that comparing a project’s emissions to statewide emissions did not contribute to an analysis on global climate change.
“The EPA provides no compelling reason to change or supplement the final EIS,” FERC wrote. “The final EIS specifically notes that comparing project-related GHG emissions to statewide GHG inventories provides a frame of reference for understanding the magnitude of GHG emissions in general, but that it does not indicate significance. … The final EIS appropriately discusses climate change, quantifies project-related GHG emissions, identifies emission reduction and mitigation measures and programs, and notes the projects’ consistency with climate goals in the Midwest region.”
“In many ways, that approval anticipated the court’s argument in the Southeast case and addressed a lot of it,” Chatterjee said. He declined to comment on any other projects.
The Sierra Club requested rehearing in the Nexus case, saying the commission’s GHG evaluation failed to meet the D.C. Circuit’s requirement. “Regardless of what methodology FERC ultimately uses, it cannot ignore the issue by claiming, without support, that there is no way fulfill its duty committed to it by NEPA,” Benjamin A. Luckett, senior attorney for Appalachian Mountain Advocates, wrote on the Sierra Club’s behalf.
Southeast Markets’ Supplemental EIS
On Sept. 27, the commission responded to the court’s remand on the Southeast Markets project with a supplemental EIS that included estimated GHG emissions but maintained that the project would have no significant effect on the environment (CP15-16, et al.).
| Duke Energy
The 685-mile project by Duke Energy, NextEra Energy, Spectra Energy Partners and the Williams Companies, is composed of three interconnected pipelines in Alabama, Georgia and Florida: the Hillabee Expansion Project, Sabal Trail and the Florida Southeast Connection.
FERC’s supplemental EIS concluded that three Florida natural gas generators that would be supplied by the pipelines — Florida Power & Light’s new Okeechobee Clean Energy Center; Duke Energy’s new Citrus County combined cycle plant and FPL’s existing Martin County Power Plant — would emit as much as 12.5 million metric tons of CO2e annually while retirements of coal, oil and natural gas plants replaced by the new units would eliminate 6.14 million metric tons — a net increase of 6.36 million.
Burning of the pipeline’s uncommitted capacity could add an additional 2 million metric tons, FERC said. The net total of 8.36 million metric tons equals 3.7% of Florida’s GHG emissions in 2015, the commission said.
The commission said, however, that it was unable to find a method to “attribute discrete environmental effects” to the emissions. “The atmospheric modeling used by the Intergovernmental Panel on Climate Change, Environmental Protection Agency, National Aeronautics and Space Administration and others is not reasonable for project-level analysis,” the commission said.
FERC also said the social cost of carbon tool is not useful for project-level NEPA review because it does not measure the incremental impacts of a project on the environment. The commission also cited a lack of consensus on the appropriate discount rate and “the monetized values that are to be considered significant for NEPA reviews.”
| Duke Energy
A group of Albany, Ga., residents responded to FERC’s supplemental filing with a protest, saying “it assumes that coal-burning power plants will be shut down in the future but does not consider the methane output from the many compressor stations that are also planned for these pipelines.”
Other Approvals
On Friday, FERC issued certificates approving two other pipeline projects: the Atlantic Coast Pipeline (CP15-554, et al.), which will deliver up to 1.5 million Dth/d over 604 miles of new pipelines between Harrison County, W.Va., and eastern Virginia and North Carolina; and the Mountain Valley Pipeline (CP16-10, et al.), which will transport up to 2 million Dth/d from Wetzel County, W.Va., to Pittsylvania County, Va.
My last couple columns have explored the Department of Energy’s “Cash for Clunkers” proposal. The first column discussed how it will cost tens of billions of dollars and subsidize less reliable generating resources to suppress more reliable resources.[1] The second column showed that the proposal is the direct result of meetings between President Trump and Robert Murray, coal mine owner and major fundraiser for the president’s campaign,[2] not some deliberative process involving well-informed, well-intentioned people.
Robert Murray’s Confirmation
A shout-out to Murray for providing a smoking gun one day after my last column ran, confirming that the DOE proposal is all about selling more of his coal to FirstEnergy power plants, one way or another.[3]
1 in 5,000, and Then Some
Some folks may still think that the situation can’t possibly be that outrageous. The DOE proposal can’t be that devoid of merit.
Wrong.
The smoking gun below is from ReliabilityFirst, the regional reliability organization responsible for reliability in the Mid-Atlantic and Midwest states (the states that are the focus of the DOE proposal).[4]
| ReliabilityFirst
Please bear with me in explaining this graphic. It’s displaying the winter. The leftmost column is showing generating resources. The next column is showing possible reduction in those resources due to resource outages, based on the last five winters (including the polar vortex). The percentages on the left are the chance of cumulative outages exceeding the associated outage quantity.[5]
The biggest cumulative reduction in resources has a 0.2% chance of occurring. That is one in 500.
OK, now skip the 50/50 Demand column and look at the 90/10 Demand column. That reflects a one-in-10 chance of the coldest weather.
Please note that resources at a one-in-500 worst case (the second column) are still much more than the peak demand in the one-in-10 worst case (the last column).
In other words, combined there is much less than a one-in-5,000 (500 x 10) chance of peak demand exceeding resources in the winter.
And there’s more!
What if that less-than-one-in-5,000 situation were to occur? Fuel supply interruption is unlikely to be a major factor.[6] And RTOs like PJM have tools to avoid customer impact, such as public appeals for conservation and voltage reductions.[7] And any resource-demand shortage would last only hours, not weeks or of course months.[8]
The DOE proposal is much ado about nothing.
The Worm Will Turn
Here’s the third smoking gun. If FERC goes forward with subsidizing certain resources for an insignificant quality like fuel supply on site, it should recognize really important qualities like environmental/public health damage.[9] In the case of coal, the National Research Council of the National Academies estimates that coal generation causes pollution damage averaging $32/MWh.[10]
This means coal resources should pay $32/MWh for their generation, to be subtracted from whatever revenues they otherwise would receive. The payments should be distributed to those hurt by coal generation.
This administration won’t do that, but no administration is forever. Once the precedent is set for FERC to put its thumbs on the scales, coal better hope that the worm never turns.
Murray said he had pressed Trump and Energy Secretary Rick Perry to have the secretary order financial support for at-risk coal plants using DOE emergency authority, but department and White House lawyers ruled that out. “They didn’t want to declare the emergency,” he said. “It was a low point because we worked hard at it and knew it was needed.“They’re doing it in a different way,” Murray said. “Now we have another approach that’s in use to get to the same point.” https://www.eenews.net/energywire/2017/10/11/stories/1060063287↑
ReliabilityFirst says, “To the left side of the range of random outages are probability percentages related to the amount of random outages that equal or exceed the amount of outages shown above that line on the outage bar.” ↑
“Between 2012 and 2016, there were roughly 3.4 billion customer-hours impacted by major electricity disruptions. Of that, 2,382 hours, or 0.00007% of the total, was due to fuel supply problems.” http://rhg.com/notes/the-real-electricity-reliability-crisis. ↑
ALBANY, N.Y. — Now that New York has done most of the hard policymaking, it’s time to focus on building individual renewable energy projects, speakers said Thursday at the Alliance for Clean Energy New York’s 11th Fall Conference.
“It is a great time to be a New Yorker advocating for clean energy policies in New York, but all these great, strong leading policies have not put us on an easy glide path to 50%” renewable energy, ACE NY Director Anne Reynolds said.
With a tradition of home rule and spirited opposition to large-scale projects, New York is a tough place for building, she said. Thus, ACE NY needs to focus on getting projects built, Reynolds said.
“Without this new focus, and without individual projects succeeding, our collective progress will be on paper only,” she said.
She also spoke of the Trump administration’s efforts to reverse its predecessor’s responses to climate change.
“It’s been a year in which I’ve been glad to focus on advocacy in Albany rather than in Washington, D.C.,” Reynolds said. “It’s also been a year when I’ve been happy to be living in Upstate New York, as we watched with hopes and prayers as Americans in Houston and Florida and Puerto Rico and in the Virgin Islands had a front row seat to a changed and changing climate — a dangerous and deadly front row seat.”
“New York really has set forth an extraordinarily ambitious agenda for climate policy and clean energy in the state,” said Alicia Barton, CEO of the New York State Energy and Research Development Authority, who spoke of the state’s “extraordinarily ambitious” clean energy goals: 50% renewable energy by 2030, while reducing buildings’ energy and electricity consumption by 23% from 2012 levels. It also has committed to build 2,400 MW of offshore wind in the same time frame. (See New York Seeks to Lead US in Offshore Wind.)
Meeting its goals will require scaling energy efficiency to deliver outcomes at a lower cost, she said. That’s why NYSERDA is making new investments in energy efficiency that are premised on different models than used before under the $10 billion, five-year Clean Energy Fund.
“For example, we’re working to launch later this fall a program that we’re very excited about called Retrofit New York, which is a $40 million initiative to enable new models to deliver deep energy retrofits in the multifamily housing space, which is an incredibly important segment of the building stock for New York,” Barton said. “Retrofit New York is based on a model that’s been deployed successfully in a number of European markets, and it’s totally new to the U.S. So again, we are asking for partnership from industry, from players in the design of energy-efficiency delivery and project finance.”
NYSERDA is also looking at a pilot around pay-for-performance in energy efficiency, but that’s in the “fairly early stages of conception,” Barton said.
Largest Procurement in the U.S.?
Government procurement is creating the demand that will allow renewable projects to get financed and built, said Joe Martens, director of the New York Offshore Wind Alliance and former commissioner of the state Department of Environmental Conservation.
“In New York, a developer’s current opportunities for long-term contracts arise from NYSERDA and the New York Power Authority and, to a lesser extent, the Long Island Power Authority,” Martens said. “As you know, there are many open solicitations from both NYPA and NYSERDA for an unprecedented 2.5 million MWh. This procurement, the very first under the Clean Energy Standard policy, is the largest single procurement that New York has ever conducted and, as far as I know, the largest in the United States.” (See NY Clean Energy Commitment Spurs Procurement.)
Rich Allen, NYPA’s vice president for project and business development, said he was excited to tell the conference about the agency’s procurement until he realized that — with a request for proposals open and client confidentially applying — he was not free to discuss many of the details. The authority was pleased to receive more than 100 proposals offering all the technologies sought, Allen said.
“Our procurement goal when we pulled together this RFP was to hit three bullet areas: The Clean Energy Standard; we also wanted to meet our customers’ renewable goals; and we’re also seeking lower-cost renewable energy,” Allen said. “The CES will require about 29 TWh of renewable energy statewide by 2030. NYPA’s share is about 4 TWh, 1 TWh of which it is seeking in the current RFP.”
All NYPA projects — either wind, solar, hydro or biomass — will be required to be in service by 2022, with a minimum size of 10 to 20 MW, depending on the technology.
The most innovative aspect of the RFP is NYPA’s use of a prepaid power purchase agreement, in which the agency would serve as matchmakers between generators and loads. NYPA can only procure as much renewable energy as its customers express an interest in.
Retirement Issues
Doreen Harris, NYSERDA director for large-scale renewables, said that one new aspect of the CES procurement is the setting of minimum quantity requirements. “So for this year, our minimum procurement target is about 1.3 TWh, and should in November we not obtain that quantity, we would issue a second solicitation in 2017,” Harris said. “And this will continue … and will set the stage for what will be a really significant pipeline of projects both under development and in construction in the state.”
New York Offshore Wind Map with Cables | NYSERDA
On Oct. 2, NYSERDA requested that the federal Bureau of Ocean Energy Management consider areas the state felt were best suited for offshore wind development. The selection process “really is the balance of all the uses of the ocean, including fishing, environmental questions and concerns, as well as cables and pipelines,” she said.
Asa Hopkins of Synapse Energy Economics addressed the fact that some older renewable generators won’t qualify for long-term contracts under Tier II rules. To be eligible, run-of-river hydroelectric facilities of 5 MW or less, wind turbines and direct combustion biomass facilities must have entered commercial operation and had their output included in the state’s baseline of renewable resources by Jan. 1, 2003. Under CES guidelines, they also must demonstrate that the renewable energy attributes of these resources are at financial risk.
“The existing independent New York resources are about 20% of the baseline or about 13% of the resources needed to get to the 2030 goal,” Hopkins said.
If these resources were lost, either by shutting down or by selling their environmental attributes and their energy to other jurisdictions, that could be a significant challenge for New York, he said.
“Opportunities for these resources to export their attributes are increasing,” Hopkins said. “Low market prices increase the risk of retirement. Just to reiterate, New York can only claim those resources for its goals if those attributes actually stay in New York. … Our estimate is that replacing these resources, if they are lost, with Tier I resources would cost New York ratepayers $1.1 billion, and our analysis indicates that there are other policy options that would retain some or all of these resources in New York for less than that.”
On an energy basis, these resources “are 47% hydro, 39% wind and the rest landfill gas, biomass and a little bit of solar,” Hopkins said. He added that in 2014, New York resources used for renewable portfolio standard compliance in Massachusetts were about 1 TWh, with about one-tenth of that amount used in Connecticut.
“These are fungible resources and they could be attracted back to New York depending on New York’s policy,” Hopkins said.
New York’s position as a leader in energy efficiency is falling, said Karl Rábago, director of the Pace Energy and Climate Center. Lime Energy CEO Adam Procell said the reason is that “30% of those electrons, or kilowatt-hours, are wasted in our buildings.”
Procell recommended New York regulators avoid being like Florida. “In Florida they love to trumpet their 10-cent energy rate,” he said. “They’ve kept the rates very low; that’s what regulators do in Florida. But when you’re paying 10 cents/kWh to run electricity through 20-year-old equipment and fluorescent lighting fixtures that we took out in Mass. 15 years ago, that’s a very expensive energy bill. Customers care about their bills, not their rates.”
It’s not a good idea to force yourself into playing catch-up on ambitious clean energy goals, said Steve Wemple, director of Consolidated Edison’s Utility of the Future Team.
Con Ed has four different incentives or earnings adjustment mechanisms under the state’s Reforming the Energy Vision. Some are tied specifically to megawatt-hour reductions, as well as peak megawatts, the traditional programmatic incentives for utilities. The company has two new outcome-based incentives that measure the energy intensity of customers and the adoption of distributed energy resources. Con Ed is also developing a carbon intensity metric that it hopes to use as an incentive mechanism in 2019.
| ConEd
To elicit behavioral change, the company is changing its approach to the market. “We used to have rebate forms, but now it’s point-of-sale,” Wemple said. “We’re trying to work upstream to make sure vendors are stocking the more efficient appliances and making it easier for customers to realize those incentives.”
Con Ed is also trying to work through the school system. “Getting school kids to guilt their parents is a very effective tool, and it will pay off down the road,” Wemple said. “Hopefully those students will stay in New York state, and we won’t have the leakage into Massachusetts.”
Procell had the last word: “If New York backslides from 2018 to 2020, we won’t make it to our 2030 goals.”
FERC on Friday rejected SPP’s request to remove its day-ahead must-offer requirement, saying the RTO had not provided “sufficient support” for its proposed Tariff revisions (ER17-2312).
“SPP’s proposal removes the only direct penalty, beyond referrals to the commission’s Office of Enforcement, for physical withholding and associated manipulative behavior in SPP’s day-ahead market,” the commission said. It also pointed out the RTO didn’t suggest additional protections going forward.
| SPP
“Removing the limited day-ahead must-offer requirement in its entirety would make monitoring and capturing potential physical withholding in the day-ahead market even more important,” FERC said.
MMU, Golden Spread Raise Concerns
SPP’s Market Monitoring Unit and member Golden Spread Electric Cooperative both supported the proposal, though not without reservations.
The MMU raised concerns about the potential for physical withholding without the requirement and requested the removal on an interim basis for 18 months — allowing the Monitor and SPP to determine whether it does result in increased withholding.
The MMU recommended in its 2014 State of the Market report that SPP remove the limited day-ahead must-offer requirement, establish a phased penalty structure for physical withholding, update the defined thresholds for physical withholding and revise the generator capability thresholds. However, those proposals failed to pass the stakeholder process.
Golden Spread’s issues were with the day-ahead market’s competitive operation without a must-offer requirement. The co-op said it is “unsound” to rely only on the expectation that the withholding rules will catch improper behavior. The co-op also argued the Tariff should be clear on what constitutes physical withholding, so market participants aren’t subject to an “information gap.”
Without access to the shift factors and other information SPP collects, market participants have no warning on the impact of their offers, forcing them to make guesses regarding resource demand and market clearing prices, Golden Spread said.
It also said that without the must-offer requirement, market participants may offer into the day-ahead market to avoid failing ambiguous physical withholding tests, rather than basing their decisions on economics.
‘Anectodal’ Evidence
FERC said SPP referred to “anecdotal” evidence that there is little reason to fear physical withholding but did not “provide further support for this assertion.”
The commission said that while SPP assured it that there is ample resource participation in its day-ahead market, “sufficient resource participation is not a safeguard against physical withholding and associated market manipulation.” FERC said a generating resource could hold local market power because of a transmission constraint, despite a large market-wide surplus.
“The must-offer requirement is the physical withholding analog to the market power mitigation rules to address economic withholding,” the commission said.
| SPP
SPP filed the request in August, saying the must-offer requirement was no longer needed and that its reliability needs are met “at all times” by the full must-offer requirements for its reliability unit commitment processes and real-time market. The RTO said the MMU’s eye on physical withholding in the day-ahead market has a “more significant impact on market participant behavior” and, based on three years of observational data, “robust” participation in the day-ahead market resulted in capacity offered in the day-ahead market “consistently exceeding” reported load by about 50%.
SPP’s request was the result of a directive from FERC when it conditionally accepted the RTO’s Integrated Marketplace in 2012. The commission asked SPP to revise its Tariff to create a process in which it or the MMU would:
Verify that market participants had not exceeded a predetermined acceptable load forecasting error; and
Establish noncompliance penalties if market participants’ estimations exceeded the acceptable range of load forecasting error.
SAN DIEGO — The electricity sector continues to identify possible applications for energy storage while costs for the technology steadily decline, but the lack of cohesive federal, state and local policy remains the chief obstacle to integration, a panel of experts said Wednesday.
“The technology piece has caught up. What we cannot afford to do is let the policy drag it down,” Kiran Kumaraswamy of AES Energy Storage said during a panel discussion at the Infocast Transmission Summit West. Industry and policymakers can develop a framework for adopting storage once they determine the magnitude and type of need for the technology, he said.
Storage has not traditionally been seen as a workable solution to solving locational reliability needs on the transmission grid, and there are questions as to whether it should be regulated as a generation or transmission/distribution asset. The U.S., especially CAISO, is in a leadership position as far as deploying storage, “but the rest of the world is catching up,” Kumaraswamy said.
Storage can also defer transmission investment, and “the ISO has been very progressive in considering non-wires alternatives,” he said.
CAISO recently launched a yearslong effort to develop a load-shifting product for energy storage, the third phase of its Energy Storage and Distributed Energy Resources (ESDER) initiative. (See CAISO Load-Shifting Product to Target Energy Storage.)
Even in situations in which conventional generation would be much cheaper, California regulatory policy and public opinion are driving storage applications. After CAISO recently performed a study finding that the $299 million proposed Puente Power Project is the cheapest alternative to energy storage and distributed energy solutions costing up to $1.2 billion, the California Energy Commission still indicated that it might not approve the plant. (See CEC Members Recommend No-Go for Puente Plant.)
There is “a very good working relationship between renewables and energy storage,” according to Tom Dagenais of Duke-American Transmission Co., a joint venture between Duke Energy and American Transmission Co. created to develop new transmission projects — such as the Zephyr line to carry wind energy from Wyoming to California, and the San Luis transmission project in California’s Central Valley.
Dagenais cautioned that integrating energy storage is a challenge, and that the decisions being made today as the technology enters the market will set the tone for how it is perceived in the future.
“If we screw this up, there is going to be a lot of fingers pointed and a lot of questions,” he said.
FERC last November issued a Notice of Proposed Rulemaking that would require each RTO and ISO to recognize the physical and operational characteristics of storage, and accommodate storage and aggregated distributed resources in organized markets. (See FERC Rule Would Boost Energy Storage, DER.)
Harding Street Energy Storage | AES
But the agency lost its quorum shortly after the proposed rule was issued, and it is unclear whether the new commission will act on it. It is also unknown how FERC will view storage as the commission becomes embroiled in controversy over Energy Secretary Rick Perry’s new proposed rule designed to bolster coal-fired generation.
Idaho Public Commissioner Kristine Raper asked the panel how a state like hers, which is long on capacity and has an abundance of hydroelectric generation, could take advantage of energy storage.
Jin Noh of the California Energy Storage Alliance noted that California has sufficient capacity but is still pursuing energy storage. “It is a question of what type of capacity,” Noh said. “There is a major need for flexibility capacity and opportunities to save ratepayer money.”
Dagenais said: “Idaho is in a pretty unique situation,” adding that many other states have a rapidly changing resource mix. He said that storage is still something worth looking into to cut costs and reduce use of lower-efficiency generation units at peak times.
