CAISO last week finalized its proposal for preventing the retirement of unprofitable power plants that may be needed for future system reliability, addressing concerns of some stakeholders about the initiative.
The ISO will discuss the draft final proposal for its Capacity Procurement Mechanism Risk-of-Retirement Enhancements (CPM ROR) initiative during a Sept. 20 call.
Pacific Gas & Electric’s Moss Landing Gas-Fired Power Plant
The grid operator altered the proposal to allow resources that currently have a resource adequacy (RA), CPM or ROR contract to apply for a CPM ROR designation — although they cannot have multiple designations at the same time. The revised plan also adjusts the deadlines for applying for CPM ROR designation and makes other changes for three different types of CPM ROR designations.
Generation owners Calpine, Pacific Gas and Electric and Southern California Edison raised questions about the plan after CAISO introduced the CPM Tariff provisions in May. The larger issue, many say, is that CAISO’s market increasingly produces negative prices from excess solar that leave generators unable to earn adequate revenue unless they have RA contacts. (See CAISO Stakeholders Question Risk-of-Retirement Initiative.)
Generation Owners Such as Calpine Express Concern Over CAISO Markets
Power sellers commenting on the straw proposal had urged changes to the program, which proposed to open two application windows each year — in April and November — for three types of risk-of-retirement designations. (See Power Sellers, LSEs Question CAISO ROR Designation.)
The latest draft provides additional detail about the reliability studies the ISO will perform to determine the need to designate generators as CPM ROR resources.
CAISO also altered the cost threshold requirement for obtaining a “Type 2” designation during the April window, rolling back a previous stipulation that a resource may not submit an ROR request for April unless its costs exceed the CPM soft offer cap. Type 2 refers to a request by an RA or a non-RA resource for designation in the calendar year following the current RA compliance year.
The updated proposal requires that a resource attest that it “reasonably believes” its annual fixed costs meet or exceed certain price thresholds.
“This requirement will help ensure that only resources that are less likely to receive an RA contract will be eligible for a Type 2 designation,” CAISO said. “This change provides an option for resources to use the April window and not have to wait until the November window to seek a designation.”
The ISO reasons that higher costs indicate that a generator likely will not be chosen as an RA resource. It said that it wants the CPM ROR payment to be based on cost of service and that the resource should be the only one that could meet an identified reliability need.
NRG Energy commented that the requirement would have meant that a resource with costs below the soft offer cap must wait until the November window. Forcing a generator to wait until November to seek a CPM ROR designation effectively negates one of the primary reasons why resource owners sought a change in the ROR process, the company contended.
The ISO also said it continues to support cost-of-service pricing to determine compensation. Most stakeholders also support that approach, although some changes were suggested.
Notable in the latest proposal is a provision that a CPM ROR designation no longer be voluntary but mandatory. Some stakeholders had wondered why CAISO would allow a resource not to accept a designation after being found necessary for reliability.
“The CAISO believes that [mandatory designation] is appropriate in circumstances where the resource has requested a CPM ROR designation, the CAISO has committed time and resources to conduct a reliability study, and the CAISO is determined that the resource is needed for reliability,” the ISO said. The grid operator said that approach is better than what some suggested — requiring a unit to shut down if it decides not to accept the designation.
The CAISO Board of Governors is due to review the CPM ROR proposal at its Nov. 1 meeting.
ARLINGTON, Va. — Even before its release last month, the Department of Energy’s grid study generated dozens of headlines because of expectations that its focus on “resilience” might provide a policy foundation for subsidizing financially struggling coal and nuclear generators.
But a month earlier, the National Academies of Sciences, Engineering and Medicine’s DOE-funded report, “Enhancing the Resilience of the Nation’s Electricity System,” went virtually unnoticed. Last week, one of the leaders of the study briefed the department’s newly reconstituted Electricity Advisory Committee (EAC) on the report, which recommended ways to prepare for “large-area, long-duration” outages.
“A lot of folks have as a primary responsibility worrying about reliability. Almost nobody really has primary responsibility for resilience,” Carnegie Mellon University engineering professor Granger Morgan, chair of the committee that prepared the report, told the EAC on the first day of a two-day meeting at the headquarters of the National Rural Electric Cooperative Association (NRECA).
The study says resilience is broader than reliability. “Resilience is not just about lessening the likelihood that these outages will occur,” it said. “It is also about limiting the scope and impact of outages when they do occur, restoring power rapidly afterwards, and learning from these experiences to better deal with events in the future.”
The DOE grid study, ordered by Energy Secretary Rick Perry, also made the distinction, saying that while “markets recognize and compensate reliability … more work is needed to address resilience.” (See Perry Grid Study Seeks to Aid Coal, Nuclear Generation.)
Interest groups supporting coal and nuclear energy have attempted to monetize the concept of “resilience,” which they say is impossible without their “baseload” generation. Groups supporting renewables and natural gas also have issued studies and policy briefs making the case for their generation sources. (See Nuclear Industry Seeks PPAs, FERC, RTO Action After Grid Study.)
Large outages are more common than one might think | The National Academies of Science, Engineering and Medicine
Morgan said one of the findings of the Academies’ report was that large-scale outages, such as those resulting from this summer’s Hurricanes Harvey and Irma and Superstorm Sandy in 2012, are more common than widely believed. Yet winning support for spending on resilience is hampered because some of the worst events imagined “haven’t happened yet,” Morgan said.
Valuing Resilience
“The loss of load probability is not equal to a willingness to pay” for resilience, commented consultant Clark Gellings, an EAC member who served on the New York Governor’s Infrastructure Commission following Superstorm Sandy.
“The willingness to pay changes dramatically once they’ve experienced something like Sandy … or the events that have happened in the U.S. in the last week or two,” he said. “The enthusiasm in the Northeast for [the integration] of central and distributed resources is much different than it is in other parts of the country right now.”
The report noted that while there have been studies of the value of electric power during outages of a day or less, “we know very little about what society is willing to pay [for] full or partial back-up service during large outages of long duration.” It called for studies assessing the value to customers of providing partial service through reduced amperage or rotating service during long-duration blackouts.
Visioning
The study encourages planners to conduct “visioning” exercises to imagine the challenges of a prolonged outage, such as what could occur following earthquakes on the West Coast or mass solar ejections in the Northeast. In Pittsburgh, where Carnegie Mellon is located, the exercise produced the realization that the city needs electricity to pump sewage over its hilly terrain, Morgan said.
“We’re not naïve. We don’t expect this will result in a sudden transformation of how we think about these issues,” he told the EAC. “But if we can’t raise the visibility of the level of vulnerability our society faces to large-scale, long-duration blackouts, then because there doesn’t seem to be anybody in charge worrying about resiliency, I think progress will be much slower,” Morgan said.
Training
The report said operators of the electric system should conduct more regional emergency preparedness exercises simulating large-scale outages.
It acknowledged that more than 100 organizations participated in NERC’s November 2015 GridEx III, the latest of its biennial “distributed-play” exercises simulating cyber and physical attacks. But it also suggested current disaster drills are insufficient, saying “the level of sophistication of attacks may continue to grow along with the number of vulnerable cyber and physical targets.” (See GridEx III Shows Vulnerability of Power Grid to Cyberattack.)
Physical Assets
Researchers called for more investment in the physical components needed to recover from a large-scale blackout. “For example, DOE, [the Department of Homeland Security] and other agencies should oversee the development of more reliable inventories of backup power needs and capabilities, like the U.S. Army Corps of Engineers’ mobile generator fleet. Investments should also go toward expanding efforts to improve the ability to maintain and restore critical services like power for hospitals, first responders, water supplies and communications systems.”
It also recommended using non-traditional sources, such as locomotive engines and hybrid and fuel-cell vehicles, for backup power and universal credentialing of repair crews loaned to storm areas by other utilities.
Smart Grid
Morgan said that the promise of a self-healing “smart grid” is far from reality because many utilities are unable to island sections of their transmission networks. Researchers also noted that despite increasing deployment of distributed generation and microgrids, “most U.S. customers will continue to depend on obtaining their power from the large-scale, interconnected electrical grid at least for the next two decades.”
Cyber Resilience
The report refers not to cyber “security” but to cyber “resilience.”
“Cybersecurity implies trying to keep the bad guys out,” Morgan explained. “But the evidence is increasingly compelling that the bad guys, in many cases, are already in and are just sitting there waiting to turn something on.” Cyber resilience focuses on responding quickly to mitigate damage and return to normal operations.
Research and Development
The study also called for more rapid implementation of resilience-enhancing technologies and operational strategies and the expansion of DOE’s research and development efforts on grid modernization, systems integration and cyber monitoring and controls, a topic that also came up at a Congressional hearing on Thursday. (See related story, Hurricanes Steal ‘Baseload’ Thunder at Grid Resilience Hearing.)
Who Should be in Charge?
EAC member and Great Plains Institute CEO Rolf Nordstrom asked Morgan whether the Department of Homeland Security or DOE should be responsible for resilience. Morgan acknowledged the report did not make a recommendation on that issue, calling only for the two agencies to “work closely” with utility operators and others. It also recommended a joint program by the National Association of Regulatory Utility Commissioners and the National Association of State Energy Officials to provide state regulators guidance on how to respond to identified vulnerabilities.
Role of EAC
It is unclear how the study, and the Electricity Advisory Committee’s (EAC’s) review of it, will inform federal policy. The committee’s mission is advising DOE on “modernizing the nation’s electricity delivery infrastructure” and implementing the Energy Policy Act of 2005 and the Energy Independence and Security Act of 2007.
EAC’s 24 members, who meet three times per year, are drawn from academia (Washington State University, Georgia Institute of Technology, Texas A&M and Ohio State), utilities (Southern Company, American Electric Power and Florida Power & Light), state and local government (Washington House of Representatives, California Public Utilities Commission and Electric Power Board of Chattanooga) and other stakeholders (ERCOT, SPP, NERC and NRECA).
It has issued more than three dozen reports since 2008, including three in 2017. DOE issues a memo each year detailing its responses to the committee’s recommendations. DOE’s six-page February 2017 memo provided responses to eight recommendations from 2016.
Wednesday’s EAC meeting also featured a presentation on the North American SynchroPhasor Initiative by project manager Alison Silverstein, a former FERC official who was also one of the authors of DOE’s grid study.
Silverstein said phasor management units (PMUs) — which provide 30 to 120 samples per second, 100 times faster than supervisory control and data acquisition (SCADA) systems — are providing real-time situational awareness and early warning of grid disturbances and failing equipment.
In addition to saving money, identifying problems before equipment fails can protect utility workers, Silverstein said. A capacitor voltage transformer can explode when it fails, sending shrapnel flying in a switching yard.
“Had we had voltage stability monitoring in 2003, we wouldn’t have had the U.S.-Canada blackout,” Silverstein said. “Had we had phase angle monitoring, we wouldn’t have had the blackout.”
| North American SynchroPhasor Initiative (NASPI)
Most of the 2,500 PMUs installed nationwide were funded by the federal government under the American Recovery and Reinvestment Act following the 2008 financial crisis.
“In the last year or two, companies are seeing so much value that they no longer have to be bribed with federal grants,” Silverstein said. “SPP is rushing to get their blanks filled in.”
But Silverstein said the value of the sensors has been undermined by the reluctance of PMU owners to share their data. “There’s a lot more we could get done if we could get good, solid data sharing,” she said.
BOSTON — Former EPA Administrator Gina McCarthy said last week she is angry about the Trump administration’s efforts to dismantle the Clean Power Plan (CPP) and renege on the Paris Climate Accord but confident that the nation’s electric industry will continue reducing its greenhouse gas emissions.
The keynote speaker at ISO-NE’s public forum on its draft 2017 Regional System Plan Thursday, McCarthy cited former President Barack Obama’s observation that “the clean energy train has left the station.”
“And there’s no way that one person is going to slow it down,” she added. “…The science [on climate change] is only getting clearer and clearer. … If you look at the energy sector, the commitments are there, the solutions are on the table.”
“Did we do enough? Of course, we didn’t,” she continued, recounting questions she is asked frequently. “I can’t answer the question of whether it’s too late [to stop the worst effects of global warming]. … The only thing I know is I’m not going to admit that. I know it’s too late to have [climate] scientists continue to be vilified.”
McCarthy said Trump’s decision to pull out of the Paris Climate Accord was “shortsighted” and “embarrassing.” But she noted the U.S. can’t formally withdraw from the agreement until 2020. (Over the weekend, administration officials denied reports that they seeking ways to remain a party to the agreement.)
She also said she expected the courts to restrict her successor’s plans to sink the CPP. “I do trust the courts,” she said, claiming the agency won 90% of its challenges in the D.C. Circuit Court of Appeals during her tenure. The Trump administration, she said, has lost three of four appeals. “They were real picky with us. They’ll be real picky” with Trump, she said.
Since leaving EPA, McCarthy, 63, has been named to the board of directors of the Connecticut Green Bank and awarded fellowships at Harvard’s Institute of Politics and School of Public Health. She also advises Pegasus Capital Advisors on clean energy investments. “After 37-plus years in public service, I’m now free to say whatever the hell I want,” she said.
McCarthy said she is encouraged by the engagement of young people on climate change and predicts transportation will be “the next big kahuna” for carbon reductions, noting the rise of ride-sharing services and Volvo’s pledge to produce only hybrids and electric vehicles by 2019. “Young people are not as in love with their cars as we were,” she said.
McCarthy, who served as a state environmental official in both Massachusetts and Connecticut before moving to EPA, made it clear that New England is her favorite region. “Every time you get aggravated or upset with ISO New England, I welcome you to go to any of the other RTOs, ISOs. You’ll want to come back home, let me tell you,” she said.
The Michigan Public Service Commission issued an order Friday outlining how the state’s electricity providers must demonstrate they have sufficient capacity to serve their customers for four years.
The four-year requirement was established in Public Act 341 of 2016, which was passed along with another energy bill, Public Act 342, last December. (See Michigan Energy Bill Preserves RPS, 10% Retail Choice Cap.) Both laws took effect April 20.
The state’s electricity providers previously were only required to show MISO that they had enough capacity to meet their customers’ needs for one year. Legislators said that didn’t give the providers enough time to build or acquire additional capacity if they needed to replace retiring plants.
PSC Chair Sally Talberg said in a statement that the four-year look-ahead “will improve reliability because capacity at the state and regional [levels] will actually be secured in advance, whether by taking advantage of excess supply that exists today or investing in new resources.”
“This approach is also cost effective because the electric supplier is in the best position to pursue the lowest-cost options to meet its customers’ needs in a reliable manner and to manage the risk of importing capacity supplies from out of state,” she added.
The PSC issued a separate order Friday opening a docket for providers to submit capacity demonstrations for the first four-year period, 2018-21. Investor-owned utilities must submit theirs by Dec. 1; all other providers — municipal utilities, electric cooperatives and alternative electric suppliers — have until Feb. 9, 2018.
Options that providers can use to meet the capacity requirements include existing and new generation, purchased power contracts and existing and new energy waste reduction or demand response programs. “Michigan’s approach is ‘fuel neutral,’” Talberg said.
The closing of older generation plants, such as the J.R. Whiting plant in Luna Pier, Mich., has caused concerns about power supplies. | Consumers Energy
The PSC will allow providers to acquire up to 5% of their capacity portfolio through MISO’s annual capacity auction. Alternative electric suppliers that can’t or don’t want to acquire capacity to meet their requirements can instead rely on their local utility to provide “capacity service,” the commission said. They would pay the utility based on “State Reliability Mechanism” charges, which the commission said it is determining in several pending proceedings. The PSC said it’s on track to issue decisions in the proceedings by Dec. 1.
Public Act 341 established a “local clearing requirement,” which the act defined as “the amount of capacity resources required to be in the local resource zone in which the electric provider’s demand is served.” Municipal and cooperative electric utilities can aggregate their resources to meet the local clearing requirement, the commission said.
The PSC is not requiring power providers to meet a local clearing requirement in the 2018-21 capacity demonstration cycle but will require them to meet it in future cycles. The commission plans to open a new contested case to establish locational requirements for future cycles and will hold hearings and get technical assistance from MISO to help it set the rules.
This year, the PSC said, MISO required nearly 95% of the generation capacity used to serve customers in Michigan’s Lower Peninsula be located on the Lower Peninsula.
CARMEL, Ind. — MISO has decided to delay the formation of external resource zones for another planning year while it tries to gain greater stakeholder support and — by extension — better chances for FERC approval.
MISO Executive Director of Strategy Shawn McFarlane said the RTO will a pursue a March filing to implement external zones by the 2019/20 planning year capacity auction, instead of the originally targeted 2018/19 period.
“Please don’t read into this as a prelude of not going into this,” McFarlane told stakeholders during a Sept. 13 Resource Adequacy Subcommittee meeting. He said the reliability concerns MISO is citing to justify the proposal will not arise until the 2019/20 planning year.
The RTO was still preparing the proposal late last month for a FERC filing this month.
“We preferred to go forward this year with it, but there is insufficient progress with stakeholder alignment … and low likelihood of FERC approval in time for the 18/19 auction,” McFarlane said.
Given a July decision by the D.C. Circuit Court of Appeals that limits FERC’s ability to issue guidance on proposals, MISO needs a “clean filing” with firm stakeholder consensus, McFarlane said. In July, stakeholders warned that FERC might be less inclined to approve a contested proposal in light of its new express prohibition from ordering changes. (See MISO Members: Court Rebuff May Reduce External Zone Chances.)
McFarlane said MISO must “contemplate a rejection” of even a carefully vetted proposal but added that the RTO was happy with its progress thus far.
“We are calling for membership to come forward with ideas, but the clock is still ticking in March,” he said. “I’ve heard from stakeholders since I’ve taken on this post that ‘MISO does what it wants,’ so here’s a case where we’re giving latitude.”
Dynegy’s Mark Volpe asked how MISO determined that a reliability risk was not imminent until 2019/20.
“We’ve been working on this for two years,” Volpe pointed out.
MISO Manager of Resource Adequacy Coordination Laura Rauch said the RTO’s concerns stem from additional generators expected to participate in MISO as capacity resources after their commitments to PJM end in the 2019/20 time frame. External zones will need to be in place to handle the added capacity.
Some stakeholders are still skeptical of the proposal, which will integrate external resource zones into the Planning Resource Auction using a single clearing price for each external balancing authority.
“What’s the longest length that a radial transmission tie can have? Hundreds of miles and still be considered [a direct link to MISO]? I think we need to keep drilling on that,” Customized Energy Solutions’ David Sapper said.
Indianapolis Power and Light’s Ted Leffler expressed concern that some resources will be forced to shut down if they are excluded from hedging by obtaining a share of excess auction revenues needed to cover generation-to-load price separation. MISO last month said it would distribute historical supply arrangement credits as a refund for price separation to external resources with long-term and consistently used historical supply agreements. (See MISO Bolsters Case for External Resource Zones.)
Rauch said MISO will next month continue stakeholder discussions about the potential make-up of hedging mechanisms to distribute excess revenues.
Seasonal Aspect Back in Conceptual Stage
MISO similarly doesn’t plan to implement seasonal capacity procurements and accreditation in time for the 2018/19 auction. The RTO will instead spend this quarter getting stakeholder input on the subject, followed by publication of a white paper.
RTO officials say the proposal is no longer as simple as applying separate clearing requirements or limits in a two-season — or even four-season — capacity auction.
“Recently, we’ve seen peaks outside of the summertime and in [shoulder months], most lately in MISO South in October,” MISO analyst Dustin Grethen said.
“The thinking has evolved,” said MISO Executive Director of Market Design Jeff Bladen. “We have to open the aperture of how we think about it. We’ll look at this without a specific solution in mind but how to scope out the issue.”
Grethen said MISO and stakeholders will spend time evaluating whether the RTO’s current resource availability requirements and price signals need to be revised in light of tightening supply from planning resources, more regular extreme weather events and an aging generation fleet more prone to unplanned outages.
Some stakeholders warned MISO that not every emergency situation can be successfully averted through planning.
“What happened in Florida in the last week could not have been prevented,” said the Minnesota Public Utilities Commission’s Hwikwon Ham, referring to widespread outages caused by Hurricane Irma. “I think we have to be very careful when planning resource availability not to try to cover transmission outages. Reliability is very important, but it’s not at any cost.”
“If we had a system that never had a max warning, would a customer want to pay for that?” added Leffler. “We have not gold-plated the system, and perhaps we should not gold-plate the system.”
Grethen said MISO would continue to hold itself to a one-day-in-10-years standard, but it wants to have a “buffer” should shoulder generation warnings occur.
Bladen noted that MISO is not yet proposing anything specific at this point. “It’s one thing to plan enough resources, but another thing to make sure that those resources are available and operational when we need them. It’s a year-round, month-to-month, hour-to-hour issue,” he said.
Sapper asked how much a new seasonal proposal may have to do with the recent U.S. Department of Energy report that urged RTOs to value “resilient” resources with on-site fuel storage, such as coal-fired plants.
“This has nothing to do with that DOE report. I think the DOE report, in many respects, is a reaction to what we’re already experiencing,” Bladen said. “I know there is an attempt to try to read into this and see a favored resource type or a political hot topic, but it’s not. We’re simply seeing a narrowed reserve margin.”
CAISO is dropping a handful of proposed enhancements to the Western Energy Imbalance Market (EIM) less than two months before the ISO’s Board of Governors is slated to review a broader package that still contains other changes.
The ISO decided to abandon three portions of its Consolidated EIM Proposal initiative based on stakeholder feedback.
| CAISO
One proposal would have allowed non-EIM third-party transmission owners to provide transfer capacity in the market, another adjusted management of bilateral schedule changes, and a third was to ensure payments to EIM entities that currently don’t get compensation for wheeling power.
The purpose of the effort was to combine EIM initiatives from the 2017 roadmap into one package in order to gain stakeholder input.
“Based on stakeholder feedback from the issue paper and straw proposal, the ISO decided to remove the 2017 roadmap items from [the] scope of the initiative,” CAISO said in its Sept. 5 draft final proposal.
CAISO kicked off the EIM proposal process in June. (See Consolidated EIM Proposal Effort Gets Underway.) The broader package is due to be reviewed by the EIM Governing Body on Oct. 10 prior to a Nov. 1 vote by the board.
Third-party TOs had expressed interest in providing transfer capacity in the EIM, but that proposal fizzled. Some of those outside owners have since received approval to enter the EIM, and there was a lack of interest among stakeholders in the measure. (See CAISO Drops EIM Third-Party Transmission Plan.)
CAISO Market Design and Policy Specialist Don Tretheway told RTO Insider on Thursday that the third-party TO proposal will still be included in the ISO’s annual policy initiatives catalog. It might be a solution to concerns regarding net wheeling, and EIM transfer costs could be used to enable compensation for a transmission contribution, he said during a Tuesday presentation.
The ISO said it felt it was unnecessary to pursue changes to management of bilateral schedules. Some market participants want the base schedule deadline moved up 10 minutes. Under current practice, changes made after submitting base schedules are exposed to real-time imbalance settlement payments. The ISO provided examples of how EIM entities can manage bilateral schedule changes through their tariffs and business practices.
Also dropped was the proposal to compensate EIM participants for wheeling power through their balancing authorities into neighboring areas. All EIM entities currently show more net transfers in and out their territories than wheel-through transactions, so they are benefiting more than they are facilitating wheels, CAISO said. But the ISO will monitor and post net wheeling data and include it in the quarterly benefits report. That initiative will also remain in the catalog to be possibly addressed later.
Although CAISO dropped the enhancements, it is moving forward with new EIM functionalities to be implemented in the winter of 2017. They include automated matching of import and export schedule changes with a single EIM nonparticipating resource; automated mirroring of system resources at ISO intertie scheduling points; base EIM transfer system resource imbalance settlement; non-generator resource modeling functionality; and allowing submission of base generation distribution factors for aggregated EIM non-participating resources.
RENSSELAER, N.Y. — NYISO’s Business Issues Committee on Tuesday endorsed a public policy transmission planning report’s recommendation to build NextEra Energy’s proposed Empire State Line in western New York.
NextEra Empire State Line transmission project recommended by NYISO for western New York | NYISO
The line was one of 10 transmission projects evaluated to relieve constraints in the region. Independent consultant Substation Engineering Co. (SECo) estimated the project would take 40 to 49 months to build and cost about $181 million. NYISO set an in-service date of June 2022, basing the schedule on SECo’s estimates.
Dawei Fan, NYISO supervisor of public policy and interregional planning presented the report, which detailed the grid operator’s methodology in ranking more than $3 billion in proposed projects for efficiency, operability and cost-effectiveness.
The report represents NYISO’s inaugural evaluation of transmission needs stemming from public policy requirements. The ISO kicked off the process in August 2014 by seeking stakeholder input on policy-driven requirements for the system. In July 2015, the New York Public Service Commission issued an order identifying a need in western New York. (See NYISO Identifies 10 Public Policy Tx Projects.)
Lessons Learned
Several market participants raised concerns that NYISO had not provided sufficient methodology background and detail on the evaluation. Some also questioned the emissions data used in the study.
Fan said “the NYISO considered emissions in the western New York evaluation based on RGGI [Regional Greenhouse Gas Initiative] carbon price forecasts instead of social cost of carbon,” which led one participant to suggest that the PSC needs to define upcoming public policy needs.
“The worst thing we could do is dispatch on one price of carbon and then turn around and redefine the emissions cost using a different price. That is the path of stupidity,” said Mark Younger of Hudson Energy Economics.
David Clarke of the Long Island Power Authority said he would like to see detailed analytics such as the breakdown of production cost by zone, so that LIPA can determine “who will benefit” from the recommended transmission project.
NYISO officials spoke of eventually holding a session on “lessons learned” in the grid operator’s first try.
“Speaking of lessons learned, any process that takes three and a half years is broken,” said Howard Fromer, director of market policy for PSEG Power New York. He added that leaving unresolved issues that have an important effect on the market has a “chilling effect on the market.”
Most Efficient
NYISO planners have found the Empire State Line project to be the most cost-effective solution of all proposals for the region. A substation proposed for Dysinger would become western New York’s new 345-kV hub — connecting seven 345-kV lines — and help reduce the transmission distance between Niagara and Rochester.
A proposed phase angle regulator (PAR) on the Dysinger–East Stolle Road 345-kV line would provide additional operational flexibility to the system. The project still demonstrates significant benefits even when the PAR is bypassed, according to the evaluation.
NYISO cited the project’s independent cost estimate and cost-per-megawatt ratio as among the lowest of all proposals, while its production cost saving over the cost ratio is the highest across all scenarios. The evaluation found no critical risks for the line regarding siting, equipment procurement, real estate acquisition, construction or scheduling.
Monitor Approval
Pallas LeeVanSchaick of Potomac Economics, NYISO’s Independent Market Monitor, joined by phone to give a presentation showing how the Monitor found the recommended project to be “economic under a variety of conditions.”
LeeVanSchaick said NYISO identified qualitative factors not fully reflected in the quantified benefits that further support selection of the Empire State Line. While the Monitor found the ISO’s methodologies to be sound, it did point out several enhancements to consider in future public policy transmission evaluations, including:
Incorporating additional priced and unpriced benefits of new transmission projects into a single benefit/cost metric;
Factoring non-capital costs and life-cycle capital costs into the benefit/cost metric;
Developing tariff provisions allowing developers to take on the risk of project cost overruns;
Modeling entry and exit decisions for generators in a manner consistent with the expected competitive market outcomes;
Refining assumptions for future operation of key plants in New York based on latest available information;
Modeling variability resulting from loop flows around Lake Erie in production cost simulations;
Considering transmission outages and other unforeseen factors in estimating production cost savings; and
Enhancing the quality of natural gas and emission allowance price forecasts.
The committee recommended that the Board of Directors approve the project. If the Management Committee also recommends approval this month, the report will be delivered to the board in October.
SACRAMENTO, Calif. — State legislation that would regionalize CAISO and mandate 100% zero-carbon retail electricity sales statewide by 2045 sputtered with just days left in the legislative session and will not pass this year, a key legislator told RTO Insider on Wednesday.
State Assemblymember Chris Holden (D), who sponsored two bills that would regionalize CAISO, said he plans to go forward with the regionalization effort next year. His main vehicle for regionalization, AB 726, was kicked back to the Senate Rules Committee yesterday and would need to be approved by a policy committee before returning to the State Senate floor.
That won’t happen, Holden said, because it was not assigned to a committee and will not be heard. Another bill with regionalization language, AB 813, was amended last week by the Senate and referred back again to the Rules Committee.
“What we wanted to do on the regionalization piece is make sure there was legislative review of whatever came out of a committee evaluation,” said Holden, who chairs the Assembly Utilities and Energy Committee. “We wanted that committee to be unanimous. The strategy was then to move to the legislature where people who represent all parts of California had a chance to sign up and speak. It is big legislation, and we wanted to make sure everybody had a say in it.”
Both bills also contain a provision that would require California electricity sellers with more than 100,000 customers to procure “tax-advantaged” renewable generation above that required by the state’s renewable portfolio standard and recover costs from retail ratepayers. The measure is intended to encourage the development of new renewable resources within the state before the expiration of federal production tax credits in 2020.
Holden said his focus initially was taking advantage of expiring tax credits on wind and solar, and there were also concerns in the geothermal community.
“Regionalization was introduced into the conversation around the bill, which I had no problem with doing, as long as it was broken into two pieces — multiple pieces — so it’s not like ‘here’s what we’re going to do and we are cutting everybody out,’” he said.
Independent Energy Producers Association CEO Jan Smutny-Jones said that regionalization would make it easier to export excess solar from California and allow access to lower-cost renewables around the West.
“Obviously, we have spent a lot of time on these issues this year. It’s unfortunate that we couldn’t quite get it out of the legislature this first year, but we look forward to working on it when we come back in January,” he said.
The ISO has allowed for more efficient use of transmission, and the same would be true with regionalization, Smutny-Jones said.
“From a market efficiency perspective, it will work a lot better,” he said. He noted that the Western Energy Imbalance Market (EIM) is working well on a regional basis, but it is only a five-minute market and does not allow day-ahead transactions like a full ISO.
CAISO itself also favors regionalization. It did not return a request for comment as of press time.
The zero-carbon bill, SB 100, introduced by Senate President pro Tempore Kevin de Leon and widely anticipated by the renewable energy community, faces strong headwinds, according to Holden. (See California Zero-Carbon Power Bill Advances.)
Of SB 100, Holden said, “That is not going to move — there is overwhelming opposition to it. And there is not time to work that out.” He is hoping to integrate the various proposals so there is “a global fix to everything. But we are out of time.”
MISO is recommending a new version of a transmission project intended to alleviate constraints in the West of the Atchafalaya Basin (WOTAB) area straddling Texas and Louisiana, but some stakeholders are balking at assumptions underpinning the proposal.
The $129.7 million project involves construction of a new substation in eastern Texas equipped with a 500/230-kV transformer. The facility would accommodate a new 500-kV line running from Hartburg, Texas, as well as a reconfiguration of the existing Sabine-McFadden and Sabine-Nederland 230-kV lines. The expanded voltage is expected to fully relieve area congestion and reduce the amount of voltage and local reliability make-whole payments needed in the WOTAB load pocket.
New WOTAB Project | MISO
“We’ve looked at this project every which way … and this is robust and cost-effective, even under conservative assumptions,” said Arash Ghodsian, MISO manager of economic studies.
Flowgate Oversight
An earlier $137.6 million proposal called for a new 500-kV line from Hartburg to Sabine and an expansion of two existing substations. That project was identified in MISO’s annual Market Congestion Planning Study, which this year focused exclusively on possible MISO South projects.
After local transmission owner Entergy increased a flowgate rating in March, the project no longer met the 1.25 benefit-cost ratio required to qualify as a market efficiency project for this year’s MISO Transmission Expansion Plan. While TOs can increase or decrease line ratings without permission from MISO, they must update facility ratings with the RTO.
MISO initially overlooked the spring flowgate rating change. The RTO waited until July to model that change and study three project alternatives, eventually settling on the revised 500-kV proposal. Some stakeholders objected to last month’s last-minute unveiling of possible projects, noting that the Board of Directors reviews MTEP projects in early December.
Two other smaller projects resulting from the Market Congestion Planning Study — also in the WOTAB load pocket — were unaffected by Entergy’s flowgate change. (See Congestion Projects, Siting Review on MISO Slate.)
Last-minute Concerns
Xcel Energy expressed concerns about MISO’s decision to change the modeling and weighting of MTEP futures for the study after having developed and approved the study’s supporting models and initially identifying congestion in the area. While stakeholders last year agreed on the relative weight of MTEP futures in planning studies, the RTO allowed a unique weighting for MISO South after the region’s TOs and state regulators asked for reduced emphasis on a future scenario involving accelerated alternative technologies. (See MISO Changes MTEP Futures Weighting for South.)
Xcel said that MISO — in the spirit of openness — should have reopened the planning study’s project submission window after changing the weighting.
“Without reopening the entire development process and reopening the window after the new models and weights were decided, MISO set a very concerning precedent which introduced gaming of the study results by allowing this unacceptable change to happen without a sufficient level of stakeholder involvement,” Xcel said in comments filed with the RTO.
NRG Energy also cautioned MISO against making last-minute modeling changes.
“New or changes in modeling assumptions can be requested at the beginning of each Market Congestion Planning Study cycle,” the company said in comments. “However, last-minute modeling changes should not be allowed unless they are necessary to correct gross errors. Otherwise, this would set a dangerous precedent and the process could well become a ‘free-for-all’…
“All modeling changes should be thoroughly vetted in the stakeholder process for approval and implementation.”
‘No Process is Perfect’
Ghodsian said the new project has been subject to open and transparent vetting despite the change in modeling criteria. Other stakeholders, including DTE Energy, LS Power, Apex Clean Energy and ITC Holdings, supported MISO’s analysis behind the project alteration.
Apex said it’s clear that the load pocket needed a high-voltage project to mitigate voltage and local reliability issues.
“The transmission system needs expansion. Lack of high-voltage solutions for WOTAB has inhibited growth in an area of the country which has seen unrivaled increases in petrochemical manufacturing in addition to the production and export of LNG,” Apex said.
Some stakeholders did take issue with MISO modeling a $1,000/MWh emergency energy price in the study when it currently caps prices at $3,500/MWh. Entergy’s Matt Brown called for aligning the emergency pricing in the models for MTEP 17 with the RTO’s actual cap.
“We can’t just continue to kick this can down the road. … This issue has been with us for a while now, and at some point, we have to address it,” Brown said.
Ghodsian said MISO will address new emergency energy pricing in the models starting with MTEP 18.
“No process is perfect, and we welcome suggestions on improving [it],” Ghodsian said.
The three projects arising from the Market Congestion Planning Study will go before the board’s System Planning Committee next week and the Planning Advisory Committee later this month.
The Illinois Commerce Commission on Monday conditionally approved Ameren Illinois’ request to lower the utility’s energy-efficiency goals established under the state’s recently enacted Future Energy Jobs Act.
The commission’s approval came despite extensive pushback from consumer and environmental nonprofits — who accused Ameren of attempting to bypass efficiency targets — and a preliminary ruling from an administrative law judge denying the requested change (17-0311).
| Ameren Illinois
The judge last month issued a preliminary order rejecting the utility’s plan, saying Ameren could shift money and priorities around to meet its annual energy savings goal while staying within the law’s budget cap. (See State Could Reject Ameren Illinois Efficiency Target Reset.)
Still, the commission approved Ameren’s plan despite its relatively high costs for each unit of energy saved. Under the plan, Ameren expects to spend 32 cents/kWh saved, compared with the 21 cents/kWh saved for residential customers and 13 cents/kWh for business customers during 2016.
Critics had wanted Ameren to squeeze more energy savings out of the $114 million per year the utility has allocated to the program, but the commission agreed with the company that the “unique circumstances” of its “largely rural” service territory — in which many customers are exempt from the efficiency provisions — made it difficult to achieve higher savings.
The proposed measures “promote the objectives of the statute,” the ICC found.
Conditions Apply
The commission’s approval also came with some strings attached.
“Ameren Illinois’ request for approval of modified goals is conditionally granted, provided that the company present to the commission, as a compliance filing, amendments to its plan design that provide additional annual savings that will assist more Ameren Illinois customers,” the ICC said in its ruling.
Among the conditions: Ameren will be required to attend at least three workshops hosted by commission staff where “stakeholders may offer proposals to aid Ameren Illinois in achieving statutory savings goals” in future plans. Commission staff will make a report following the workshops.
The commission also said it will reassess Ameren’s goals and performance after a year and required that the utility donate any performance incentives from meeting its modified savings goals to nonprofits that assist low-income communities with energy-efficiency measures.
“By proposing to donate any performance incentives it might realize, Ameren Illinois satisfactorily addresses any concern that it is attempting to profit by manipulating savings goals so that it will be certain to achieve them,” the commission said.
Under the Future Energy Jobs Act, Ameren is required to meet 9.8% in cumulative annual energy savings by 2021, but the utility is planning for 8.24% in savings. The utility had allocated $114 million per year for the program, the maximum budget under the law, but it claimed it still could not meet the savings goal. A maximum budget triggers the ICC’s authority to reduce annual incremental savings goals.
Ameren said it remains committed to achievement of the agreed upon savings target of 13% by 2025.
“Based on our initial understanding of the order, we are in agreement with the commission on many points. Our innovative energy efficiency plan will result in customer cost decreases,” Ameren Illinois spokesperson Marcelyn Love told RTO Insider.
Rehearing?
The Environmental Defense Fund said it would seek a rehearing on the issue after learning of the decision, citing the ALJ’s preliminary order. EDF, the Natural Resources Defense Council and the Citizens Utility Board “provided numerous suggestions for Ameren to meet its efficiency goals and provide maximum savings to a greater number of customers,” EDF said.
“Ameren is abandoning its energy-efficiency commitments, meaning fewer customers will get help lowering their energy bills, and those who do will be saving less. … The decision robs people in Central and Southern Illinois of the cleaner air, lower bills and clean-energy job opportunities they were promised by the Future Energy Jobs Act,” said EDF’s Christie Hicks.
The Illinois Clean Jobs Coalition also expressed disappointment with the order, saying the ICC disregarded the opinion of its own ALJ.
“Ameren’s plan to scale back savings from energy-efficiency services will prevent people in Central and Southern Illinois from reaping the same benefits that people in Chicago and Northern Illinois will receive under the Future Energy Jobs Act,” the coalition said. “Disadvantaged communities should be prioritized for investments, and we believe that Ameren can and should also provide the same quality of services.”
