CARMEL, Ind. — MISO is seeking stakeholder feedback on its proposal to use a new calculation to crack down on generators that fail to follow dispatch instructions.
The proposed calculation, which comes after years of debate, will impose a “failure to follow dispatch” warning when a resource fails to move at least half its offered ramp rate over four consecutive dispatch intervals, MISO Market Quality Manager Jason Howard said during a Sept. 14 Market Subcommittee meeting. Generators are currently flagged after they deviate by more than 8% from dispatch instructions over four consecutive intervals.
MISO Executive Director of Market Design Jeff Bladen emphasized that the calculation is not yet final and asked for stakeholder suggestions.
After several months of delays, MISO said in May it was still developing software to support its effort to tighten tolerance bands on uninstructed deviations. The RTO’s Market Monitor has been recommending the project for more than five years. (See Monitor Again Criticizes MISO’s Uninstructed Deviation Rules.)
A MISO impact study using production data from May through July found that failure to follow dispatch increased from 2.4 to 6.1% under the new threshold. The study also found that the calculation reduced excessive and non-excessive energy charges by 4.4% across the MISO footprint for the three months, while Day-Ahead Margin Assistance Payment (DAMAP) disbursements decreased by 7.6% or $941,000.
MISO Market Monitor David Patton said the reduction in DAMAP payments is “huge” because it shows MISO will stop awarding make-whole payments to generators that fail to follow dispatch.
Howard said MISO now will seek feedback on the new calculation from the FERC Office of Enforcement and continue discussions with the Monitor’s staff. At an Advisory Committee meeting this spring, several stakeholders asked MISO to convene a workshop to discuss the RTO’s analysis and the possible shape of the proposal. (See “AC Prods Restart on Tighter Uninstructed Deviations,” MISO Advisory Committee Briefs.)
DTE Energy’s Nick Griffin asked if the new proposal might have “unintended consequences” by discouraging slow-ramping resources from offering in fear of being penalized.
“The goal here is to get people to offer the ramp rate that they are comfortable with and they actually can live with,” Bladen said. “We don’t want generators to offer a ramp rate that they can only meet half the time because the reality is we’re counting on the ramp. We’re counting on people to move.”
“It harms the system to provide a ramp rate that you can’t realistically meet,” Patton added. “Your offer parameters aren’t really accurate if you can’t perform to them.”
Some stakeholders expressed concern that the nearly $1 million in theoretically lost DAMAP would inordinately affect slower moving coal units.
“You’re talking about a million dollars [for] every generator [in] MISO. We’re not going to devastate anyone here,” Patton said. “There might be one or two units that are so inflexible that they might alter their offer, but that’s a good thing because we won’t be relying on flexibility that we really don’t have.”
The California legislature ended its 2017 session in the early hours of Saturday, drawing criticism for its last-minute pursuit of CAISO regionalization and for letting a 100% clean energy bill die in committee.
Assembly member Chris Holden (D) took the political heat on both the regionalization effort and SB 100, the clean energy proposal by Senate President pro Tempore Kevin de Leon that was hotly anticipated by renewable energy supporters. That latter bill died in the Assembly Committee on Utilities and Energy, which he chairs.
On Thursday, police officers guarded Holden’s office in Pasadena as a small band of protestors appeared, according to social media posts. As news spread that SB 100 had stalled, Holden was tagged on social media and actor Leonardo DiCaprio posted Holden’s phone number — and those of other lawmakers — to his more than 18 million Twitter followers.
Holden’s main vehicle to boost regionalization, AB 726, was kicked back to the Senate Rules Committee on Tuesday and would have required policy committee approval before returning to the Senate floor. Another bill containing regionalization language, AB 813, was amended by the Senate and referred back again to the Rules Committee the week before.
“It’s important to recognize that these bills did not authorize regionalization of the grid,” Holden said in a statement on Wednesday. “The bills established the next steps for the ISO to follow. But there is still more to discuss starting with the role of the legislature in review of any proposed governance structure of a new ISO. We will continue our work on the issues over the fall and likely revisit it in the second half of this two-year session.”
In an interview with RTO Insider last week, Holden said: “What we wanted to do on the regionalization piece is make sure there was legislative review of whatever came out of a committee evaluation. 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 initial focus was on taking advantage of expiring tax credits on wind and solar and addressing concerns among geothermal producers.
“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 energy from California and allow access to lower-cost renewables from 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.
In a blog post Wednesday, Natural Resources Defense Council Co-director Ralph Cavanagh said: “By not authorizing changes in how the grid is managed this session, lawmakers are delaying a prime opportunity to reduce utility bills, cut pollution and increase electric service reliability. And it wouldn’t have cost the taxpayers a dime.”
CAISO, which favors regionalization, said it had no comment.
SB 100 Fizzles, Drawing Ire
SB 100, the zero-carbon bill, widely anticipated by renewable energy advocates, faced strong headwinds, according to Holden. (See California Zero-Carbon Power Bill Advances.)
About 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 said he hopes to integrate several proposals so there is “a global fix to everything. But we are out of time.”
Labor unions, worried about the potential loss of jobs, also urged the legislature not to pass SB 100. The Coalition of California Utility Employees and the California State Association of Electrical Workers issued public statements opposing the bill, saying that the state is on the way to meeting its current renewable goals and that more information is needed on the proposal.
Legislature Passes Energy Storage Bill
The legislature did succeed in passing legislation meant to encourage the development of energy storage technology in California. AB 546, authored by Assembly member David Chiu (D), is intended to streamline the approval process for new storage installations. Chiu is chair of the Assembly Housing and Community Development Committee.
“Our future energy needs will require us to dramatically improve energy storage and increase the flexible management of electricity supply and demand,” Chiu said in a Sept. 7 statement. “California should encourage simplicity and standardization with local permits. When permitting conditions vary between cities, it can slow the industry down. Guidance that draws from best practices can help local governments standardize their processes so that the energy storage industry will grow quickly and safely.”
The bill requires the development of an energy storage-permitting guidebook by 2020 and requires cities and counties to accept electronic submissions of storage projects.
Aliso Canyon Bill Passes
The legislature also passed SB 801, introduced by Sen. Henry Stern (D), that would require publicly owned utilities in the Los Angeles Basin to support deployment of distributed energy resources (DERs) and energy storage and reduce the region’s reliance on gas-fired generation. (See Aliso Canyon Measure Clears Calif. Assembly Committee.) The bill was drawn up in response to the 2015 leak that resulted in the closure of the Aliso Canyon natural gas storage facility.
A spokesperson with Stern’s office said Gov. Jerry Brown is expected to sign the legislation.
The bill was amended to remove a requirement that investor-owned utilities make data available that would help DER providers identify solutions to increase reliability in the region. That provision that now applies only to the Los Angeles Department of Water and Power.
Also struck was language that would have required IOUs to maximize the use of demand response and other technologies in the areas affected by the well failure at Aliso Canyon.
The legislature reconvenes in January, when renewable energy interests, CAISO and other stakeholders will renew the debate over how aggressively California should pursue regionalization and further strengthen the most ambitious renewable energy requirements in the country.
SARATOGA SPRINGS, N.Y. — New York’s top regulator last week assured the state’s power producers that he would offer a steady hand in a time of dramatic change for the electricity sector.
“With me, you should expect a policy of continuity — continuity with the state’s energy policies,” New York Public Service Commission Chair John Rhodes said at the fall conference of the Independent Power Producers of New York.
IPPNY CEO Gavin Donohue introduced Rhodes by saying his group’s members are “very concerned” about New York’s natural gas infrastructure.
“The siting of natural gas pipelines is FERC’s jurisdiction, but the DEC [New York State Department of Environmental Conservation] has developed a pattern of denying water quality certificates for projects, most recently evidenced by the decision on the Millennium Pipeline,” Donohue said. (On Friday, FERC overruled the DEC, saying that by failing to act within the one-year time frame required by the Clean Water Act, it had waived its authority to issue or deny a water quality certification (CP16-17)).
Rhodes responded that his commission continues to support programs that lead to more gas customers.
“We support programs that encourage customer conversions from carbon-intensive petroleum products such as No. 6 heating oil,” he said, and when gas distribution projects “are economically and environmentally sensible, we clearly give the green light, and we have a track record of doing that.”
While about 38,000 New York customers are converting to natural gas each year, the commission doesn’t “have a lot to do with gas transmission,” Rhodes said. “That is a sister agency, principally the [DEC], but I’ll just note for the record, and it is in the record, that the state in all its agencies has been consistent in delivering … on all project proposals. Each project is based on specific circumstances and characteristics and is assessed on a series of clear, unambiguous, sometimes strict standards, appropriately strict standards having to do with environmental health and safety.”
Rational Actors
Rhodes cited the commission’s work on the Reforming the Energy Vision proceeding, the Clean Energy Standard and “the continuous matter of rate cases.”
“One could look at them as separate bundles of things … but also recognize that there is a commonality to them and to how we are dealing with them,” he said. “We’re seeking in all of these to achieve a cleaner, more cost-effective and reliable energy system.”
To achieve the state’s clean energy goals requires market actors “to commit one basic act … [to] make an investment decision,” Rhodes said. “It’s up to us — and this is the commonality, it’s up to us as the Public Service Commission … to set things up … so that those investments also serve our policy goals.”
Rhodes said that regulators can trust market actors “to act rationally … and our role is to keep the picture whole,” and that getting the transmission right is a way of harnessing the ability of the market to move toward the grid of the future.
The CES is “up and running” and the first request for proposals has been released, which, in combination with an RFP by the New York Power Authority, represents the largest procurement in New York and U.S. history, Rhodes said.
“These projects will generate 2.5 million MWh of electricity a yea r… and the response so far has been … robust,” he said.
The state has taken important first steps in pricing carbon into the wholesale energy market, Rhodes said.
“I’m told that it’s an elegant idea by certain editorial writers,” Rhodes said. “We kind of agree. The future carbon pricing policy can and must be a really effective instrument for achieving New York’s policy goals: a cleaner, more affordable energy system for the ratepayer. If we can harmonize the operations and rules of the wholesale energy markets with the state’s policy goals, we can decarbonize the state’s energy system in a better way.” (See NYISO Stakeholders Talk Details of Carbon Charge.)
PSEG Power’s Howard Fromer asked about the connection between carbon pricing and reform to the capacity market, a subject touched on slightly in the preface to the Brattle Report signed by Rhodes and NYISO CEO Brad Jones. (See NYISO Study Sees Little Cost Impact from Carbon Charge.)
The reference in the preface was intended to acknowledge that a carbon charge has consequences that “may go beyond another layer in the price tag,” Rhodes said. “We’ve got a system that works. If you perturb it, it’s going to be a different system. Make sure it works in the future, too. That’s just ordinary good housekeeping.”
John Reese of Eastern Generation asked about the many levels of REV, from the “umbrella level” to the core of the program.
“As a non-utility company without limitless resources, tracking the 46 REV-specific activities, the paper that comes through, and moving from the weeds back up a level to, ‘What does it mean in synthesis?’ … How can you help synthesize the information? … I mean, my REV reading list is waist-high,” Reese said.
“What did you do with the rest of it?” Rhodes joked, referring to the reading list. “REV’s outcome is simple. We want a system that’s more cost-effective, smarter investments, cleaner. We know it’s going to be more distributive because that’s what technology is telling us.”
REV’s regulatory proceedings “are many and complex, so there’s a complicated machine, but it’s aimed at some fairly direct, simple outcomes,” Rhodes said.
He said a “regulatorily naïve observer,” thinking about investment decisions and wanting to know where to focus attention, will eventually see a clearer picture emerge.
“I think we’re going to start getting the operational outcomes increasingly over time. … It’s on a conveyor belt that’s about to start coming out,” he said.
Indian Point and Transmission
Donohue asked Rhodes how the PSC will integrate NYISO’s study on the retirement of Entergy’s Indian Point nuclear plant into the work of the New York State Energy and Research Development Agency’s task force on the issue.
“That’s a complicated question and I’m going to give an over-simplistic answer,” Rhodes said. “The task force obviously has a broad remit, but the issues that it’s going to focus on … are relevant to the communities around the plant, so they have to do with taxes and economic development. They have to do with the site.”
NYISO’s Brad Jones addressed the issue of Indian Point’s closing from the ISO’s perspective.
“We have not yet received a completed notice of deactivation for the plant, yet we decided on Aug. 1 to go ahead and begin our reliability assessment,” said Jones. “And we do that somewhat outside our normal process for doing a reliability assessment … but we believe that, because of the significance of this unit, it’s important to study that now.”
NYISO hopes to complete the assessment by the end of this year, Jones said.
“There are a number of factors that continue to move, and we have to make assumptions, and we will have to do several sensitivity analyses around the report to get something that each of you will be comfortable with what you see,” he said.
Jones also said NYISO is wrapping up its role in developing the western New York public policy transmission line. If the grid operator’s board in October approves selection of NextEra Energy’s Empire State Line, the project will move into the state’s Article VII siting approval process. (See Public Policy Tx Project Wins Key NYISO Endorsement.)
Jones said the ISO’s work on the proposal for the AC transmission project proposed to run from upstate to load centers in New York City and Long Island will likely run into next year.
“We’re steadily in [the] process of moving the AC forward, and that’s also a significant project for the health of New York and the ability to move renewable generation around the state,” he said.
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.
