Four developers proposed 18 offshore wind projects last week in response to a solicitation by the New York State Energy Research and Development Authority in consultation with the New York Power Authority and the Long Island Power Authority.
New York’s Public Service Commission last July authorized state agencies to procure 800 MW of offshore wind energy by the end of this year after Gov. Andrew Cuomo set a target of 2,400 MW by 2030. Last month, he dramatically upped that goal to 9 GW by 2035. (See New York Boosts Zero-carbon, Renewable Goals.)
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Five developers initially told NYSERDA they intended to respond to the request for proposals NYSERDA issued in November (ORECRFP18-1), but one, Mayflower Wind Energy (a joint venture of EDPR Offshore North America and Shell New Energies US) did not submit a bid by the Feb. 14 deadline, the agency said.
Those bidding were:
Atlantic Shores Offshore Wind (a joint venture of EDF Renewables North America and Shell New Energies US), which would build off the New Jersey coast.
Bay State Wind (a joint venture of Ørsted A/S and Eversource Energy), which is proposing a project called Sunrise Wind that would be in the waters off Massachusetts and Rhode Island, about 30 miles from Montauk Point.
Equinor Wind US, which proposed a project called Empire Wind. The company (formerly Statoil) said the 80,000-acre lease it won in 2016 could produce up to 2,000 MW. It is located 14 to 35 miles south of Long Island in the New York Bight.
Vineyard Wind (a joint venture of Copenhagen Infrastructure Partners and Avangrid Renewables), which partnered with Anbaric Development Partners in proposing up to 1,200 MW of offshore wind. The joint venture, Liberty Wind, submitted proposals sized at 400, 800 and 1,200 MW, each of which couples energy generation with transmission components.
“Today’s record response provides the robust competition needed to responsibly develop offshore wind for New Yorkers while spurring billions in private sector investment in New York, creating thousands of jobs and putting the state on a path to a carbon-neutral future,” NYSERDA said in a statement.
Companies Scramble for Position
Vineyard last May won a contract from Massachusetts for a 1,200-MW offshore wind project off Martha’s Vineyard. Anbaric helped build the 660-MW Neptune HVDC cable linking PJM to Long Island and contributed to the 660-MW Hudson project connecting midtown Manhattan to the RTO.
Anbaric also has several interconnection requests and slots with NYISO, including for a 500-MW HVDC line and 800-MW AC line connecting into Ruland Road on Long Island, as well as a 1,200-MW HVDC line and additional 800-MW AC connection into the Farragut substation in Brooklyn. (See Anbaric Pushes Offshore Grid Plans.)
The Liberty Wind proposal includes fabricating foundation components at a port facility near Albany and transporting them down the Hudson River to the project site in the Atlantic Ocean.
Bay State announced on Feb. 7 that Eversource had paid about $225 million for 50% of Ørsted’s Revolution Wind and South Fork Wind Farm projects and its 257-square-mile tract off the Massachusetts and Rhode Island coasts — assets Ørsted acquired in November from Deepwater Wind.
Equinor said its Empire Wind project is the first step toward its plan “to take a leading role in renewable energy development in the U.S.” It also is proposing Boardwalk Wind in response to New Jersey’s offshore wind solicitation in December. Equinor acquired a second lease area in December, a 128,000-acre site off the coast of Massachusetts.
EDF and Shell announced Atlantic Shores as a 50/50 joint venture in December. The companies’ lease area has potential for producing 2,500 MW. EDF, which has 2,800 MW of offshore wind in development or operation in Europe, said the joint venture is part of its plan to double its global renewable capacity to 50 GW by 2030.
Benjamin Sloan will join OMS beginning March 1. He most recently served as a special assistant attorney general in the Mississippi Attorney General’s Office, where he tracked MISO and FERC issues. Sloan was also active in OMS discussions prior to being hired by the organization.
“I am very excited to have Ben join the team,” OMS Executive Director Marcus Hawkins said during a Feb. 11 OMS Board of Directors meeting in D.C. on the sidelines of the National Association of Regulatory Utility Commissioners’ Winter Policy Summit.
“I am honored to have been trusted with this role and excited to help shape and coordinate the crucial voice of the State Regulatory [Authorities] sector within the MISO stakeholder process,” Sloan said in a release.
OMS touted Sloan’s legal and writing experience from his previous roles at the Mississippi Department of Human Services and the Mississippi-Alabama Sea Grant Legal Program. Sloan earned a bachelor’s degree in English and political science from the University of Mississippi and a law degree from the university’s School of Law.
OMS-RSC Talks Continue
Meanwhile, OMS continues to work with SPP’s Regional State Committee on how to solve MISO and SPP’s seams issues. (See MISO, SPP Regulators Continue Seams Talks.) The two regulatory organizations met with FERC staff in closed session on Feb. 10 ahead of the NARUC meeting. Missouri Public Service Commissioner Daniel Hall said FERC staff offered useful information during the private meeting. “They are willing to be partners in this effort,” Hall told OMS board members on Feb. 11.
Hall said future meetings between OMS and SPP’s RSC will be open to the public.
WASHINGTON — Declining costs and new market rules are opening opportunities for energy storage, but the technology’s operating characteristics are proving challenging to system operators and market designers, speakers told the Energy Storage Association Policy Summit last week.
Jurisdictional questions also are creating uncertainty, speakers said.
David Kolata, executive director of the Citizens Utility Board in Illinois, captured the optimism at the daylong conference, declaring his consumer group as “bullish” on the technology.
“In our minds, the declining cost curve of batteries and other storage technologies is the single most encouraging trend in the electricity space today,” Kolata said. “We see storage as an essential component of a least-cost future, and we say this because if we get the policy right there are multiple sources of consumer value.”
Kolata cited lower cost for frequency regulation, reduced costs for integrating renewables, increased grid flexibility and reliability and the deferment of transmission and distribution system investments.
“And perhaps most importantly, storage can lower peak demand. From the consumer point of view, nothing is more important than reducing the peak. As you know, a large percentage of overall system costs are driven by 30, 40, 50 hours a year, so if you can reduce that peak, there are benefits for all consumers.”
Kolata said storage — along with time-based rates — will be crucial to ensuring transportation electrification brings benefits.
“At CUB, we see the potential benefits from electrification, but … only if vehicles charge when they should and don’t charge when they shouldn’t,” he said. “If transportation electrification increases peak demand, it’s going to be bad for the environment and bad for consumers.”
No Tx Projects Yet
FERC Chair Neil Chatterjee, who joined the commission in August 2017, while the Notice of Proposed Rulemaking that led to Order 841 was pending, recalled Sens. Sheldon Whitehouse (D-R.I.) and Ed Markey (D-Mass.) telling him during his confirmation process of “the importance of storage as a transformational technology.”
Order 841, which required RTOs and ISOs to remove barriers to entry for storage, was approved in February 2018, two months before Order 845, which revised generator interconnection rules. (See FERC Order Seeks to Reduce Time, Uncertainty on Interconnections.)
Although storage can replace or defer more expensive transmission upgrades by reducing thermal loading, no RTOs or ISOs have selected storage as an option in their regional transmission plans, Chatterjee noted. “In fact, the commission has not received a single request for rate recovery from a storage project that was actually built to provide transmission services,” Chatterjee said. FERC did approve a request in 2011 to recover the cost of storage facility through CAISO’s transmission rates, but the project was never built.
“If storage as transmission were to gain more traction in the regional planning processes, that could really open up big opportunities,” he said.
He said storage’s role on distribution grids will be uncertain until legal questions are answered.
Several protesters have sought rehearing of Order 841, saying FERC overstepped its authority regarding distribution-level storage. Once FERC rules on the rehearing requests, there could be further challenges at the D.C. Circuit Court of Appeals.
“While Orders 841 and 845 did a lot to level the playing field for storage, I don’t think that means our work is done,” Chatterjee said.
Andrew Levitt, senior business solution architect for PJM, said the order was a challenge because the RTO strives for a resource-neutral policy. “And then we get Order 841, that says you have to have a resource-specific energy storage resource participation model and here’s how it’s going to have to work,” he said. “Those two perspectives don’t quite mesh.”
Daniel Harless, lead market design engineer for SPP, said stakeholders were sharply divided on the RTO’s pre-Order 841 rules, with some “people believing that some existing market rules were barriers [and] other people who believe that those existing market rules were a safeguard to [protect] reliability.”
Christopher Parent, director of market development for ISO-NE, said, “Getting [storage] modeling correct is challenging. It’s challenging for combined cycles; it’s challenging for storage; it’s challenging for wind.”
It is even more challenging, he said, “when you start combining these technologies together,” as in co-locating solar and storage.
But he said prior experience with renewables has helped analysts develop answers.
“Inverter-based resources — energy storage, wind, solar — because they don’t have unit commitments, because they don’t really have ramp limits — all those resources are completely dispatchable, down to zero in the case of wind and solar, and down to negative whatever in the case of batteries,” he said. “We actually found that our wind, solar implementation in the markets in the industrial optimization side of the market, was very easily portable over into energy storage.”
But Michael DeSocio, senior market design manager for NYISO, said storage’s physical capabilities have outstripped the ISO’s optimization software.
“I’m [not] worried about 10 or 20 MW of storage resources and managing the system with that. … [I’m worried about] [Year 2030] storage goals for 3,000 MW of these resources. That’s 10% of our load. If we get schedules wrong, we’re going to have problems on the grid. We’re going to create situations where we’re either going to be more conservative, and therefore we’re going to overcommit just so we have backup resources available, which I don’t think helps the clean energy side of the equation. Or we’re going to under-commit and then we’re going to have issues with trying to keep the lights on.
“So, we need to figure this out. We’re going slow mostly because when we presented some information to our stakeholders, we were unable to get eight storage assets to solve simultaneously in the market simulation app. We’re looking at way more than eight” storage assets, he said.
Market Design
Peter Fuller of Autumn Lane Energy Consulting said market rules need to be changed so that “low-marginal-cost resources can still set prices … rather than defaulting to sort of an average cost, all-in, cost-of-service methodology. That’s a gap we need to work on. But I don’t think it’s a suggestion that we don’t continue to push forward with markets.
“It’s been close to 20 years now that I’ve been thinking about trying to design and build these wholesale markets. Where we run into trouble is where we try to make exceptions and do things just for this or just for that. … I think the more we get back to first principles and simplify overall, we’ll be better off. … We have 20th century markets. We need 21st century markets. We have a long way to go,” he said.
“Twenty years ago, … combined cycle developers were all saying, ‘I need a long-term contract.’ We built markets that actually accommodated them very, very well and no longer do we see that kind of requirement coming from that community.
“Now we’re seeing it from the renewable and storage community. … In a fairly short time, in my opinion, I think with well-structured markets we’re going to see the need for long-term contracts kind of fade away.”
Investment Tax Credit?
U.S. Sen. Martin Heinrich (D-N.M.) told the conference he has won Sen. Cory Gardner (R-Colo.) as a co-sponsor of legislation they will introduce for an energy storage investment tax credit. Heinrich has been unsuccessfully pushing for the credit since at least 2016.
The 2017 version of the bill would have given commercial storage applications the same tax incentive that solar energy receives under Section 48 of the Internal Revenue Code, including the phase-out over five years.
All energy storage technologies with a capacity of at least 5 kWh, including batteries, flywheels, pumped hydro, thermal energy and compressed air, would qualify. The IRS currently allows an ITC for an energy storage resource only when it’s combined with a solar energy system.
The bill also would provide homeowners the same credit as currently available for solar energy in Section 25D of the code. Currently, only battery storage with a capacity of 3 kWh or more is eligible for the residential ITC.
Both the residential and commercial ITCs are worth 30% for projects begun by the end of 2019. The ITC drops to 26% for projects begun in 2020 and 22% for projects started in 2021. After 2021, the residential credit is eliminated, and the commercial and utility credit will drop to a permanent 10%.
At a Senate Energy and Natural Resources Committee hearing on cybersecurity at which Chatterjee appeared the day after the ESA forum, Heinrich asked the chairman about the status of Order 841. “What kind of a timeline are we looking at?”
“We’ve heard from a number of stakeholders that they’re waiting for our action on rehearing,” Chatterjee said. “These are very, very complex issues. We understand that people want that clarity going forward. My colleagues and I are committed to doing it right, and we understand the agita and the desire to get it done. Better to do it right than rushed.”
“We do need to get this right, but it is also a pretty urgent matter,” Heinrich replied. “It certainly opens up an enormous amount of economic activity and a resiliency that we need to be supportive of. I would just once again emphasize what an urgently important order that is.”
WASHINGTON — Compared to the rancor often on display when the Senate Energy and Natural Resources Committee discusses topics like climate change or grid resilience, Thursday’s hearing on preventing cyberattacks on the bulk power system (BPS) was less partisan, with senators soberly asking informational questions.
That was, until it was Sen. Angus King’s (I-Maine) turn to speak.
“There’s a weird calmness about this hearing,” King said at the session, which featured FERC Chairman Neil Chatterjee, NERC CEO Jim Robb and Karen Evans, assistant secretary of the Department of Energy’s new Office of Cybersecurity, Energy Security and Emergency Response (CESER). “This is not a threat. This is happening now. We are under attack! This isn’t something that may happen next year or two years from now. And I’m not revealing anything classified in the sense of quoting news articles and presentations by the Department of Homeland Security. We are in a very dangerous place, and I just think this has to be … an emergency, an urgent situation.”
King has previously called for the federal government to develop an “offensive response” to attacks on the grid and other critical infrastructure, a proposal he repeated Thursday. (See “Sen. King Calls for ‘Offensive’ on Cyberthreats,” Overheard at NECPUC 71st Annual Symposium.)
Growing Concern
In late 2015, the Associated Press reported that “so many attackers have stowed away in the largely investor-owned systems that run the U.S. electric grid that experts say they likely have the capability to strike at will.”
The report did not cause much of a stir in the energy industry at the time. But concern has steadily grown, especially since the revelations of Russian hackers’ attacks on Ukraine’s electric grid and their interference in the 2016 U.S. presidential election.
The U.S. Intelligence Community’s 2019 Worldwide Threat Assessment, released late last month, reported that “Russia has the ability to execute cyberattacks in the United States that generate localized, temporary disruptive effects on critical infrastructure — such as disrupting an electrical distribution network for at least a few hours — similar to those demonstrated in Ukraine in 2015 and 2016. Moscow is mapping our critical infrastructure with the long-term goal of being able to cause substantial damage.”
The report also said that “China has the ability to launch cyberattacks that cause localized, temporary disruptive effects on critical infrastructure — such as disruption of a natural gas pipeline for days to weeks — in the United States.”
King asked Robb to confirm that “Russians are already in the grid.” Robb declined to answer.
“Well can you comment on a public story about something released by the Department of Homeland Security?” King asked.
“Uh, no,” Robb replied.
After a brief pause, King said, “OK, let me ask another question. Do any of our utilities have Kaspersky [Lab], Huawei [Technologies] or ZTE equipment in their systems?” Kaspersky is a Russian company, while the latter two are Chinese.
“We issued a NERC alert —”
“I didn’t ask you if you issued an alert,” King interrupted, repeating the question.
“Not to my knowledge,” Robb said. In response to another question from King, Robb also said NERC had not surveyed utilities.
“I think that’d be a good idea, don’t you?” King said.
“I’ll take that on,” Robb replied.
“I don’t mean to come off as negative,” King said later. “I just think this has to be addressed with a real sense of crisis.”
Sen. Martha McSally (R-Ariz.) agreed.
“If I close my eyes, this sounds like a hearing from 19 years ago in many ways,” she said. “And I don’t want to take away from some of the things that have been done, but what has changed in 19 years — more rapidly than us figuring out how to defend, protect, share information and do whatever it takes — is the threat is real and it’s happening.”
“I worry we’re not moving fast enough,” Sen. Martin Heinrich (D-N.M.) said, “especially in a world where it’s often viewed that if it works, just leave it alone.”
Mandatory Pipeline Standards?
Both Chatterjee and Robb told the ENR Committee that NERC’s mandatory reliability standards for electric utility companies are among the many ways the organization guards against cyberattacks. “Mandatory standards, coupled with effective mechanisms to share information, provide robust and flexible tools to protect the BPS,” Robb said.
Chatterjee noted that he and Commissioner Richard Glick wrote an article in June last year expressing their concern about the Transportation Security Administration’s oversight of natural gas pipeline security, concerns vindicated by a Government Accountability Office report in December that found TSA is hampered by staffing constraints and vague criteria for identifying critical facilities. (See GAO Critical of TSA Pipeline Security Efforts.)
“Since the publication of that op-ed, I’ve been pleased to hear from many members of the natural gas pipeline community, who have expressed their appreciation for these concerns and willingness to continue taking steps to improve their security posture,” Chatterjee said in remarks echoing those he had made the day before at the National Association of Regulatory Utility Commissioners’ Winter Policy Summit.
Chatterjee told both the NARUC audience and the Senate committee that he had met with TSA Administrator David Pekoske “and was impressed by his focus on this vital issue, as well as his pledge to taking further action to improve TSA’s oversight of pipeline security.”
Speaking to reporters at the NARUC meeting Wednesday, Chatterjee said he met with Pekoske and TSA staff near the end of last month. “It was clear that they were taking seriously the concerns that Commissioner Glick and I had raised [and] also were taking very seriously the GAO report that pointed out things that could be improved about the process. And so, I feel very good about the actions that industry has taken and that TSA and DHS have taken to address some of the concerns that we raised.”
But he declined, both with reporters and under questioning by King and Heinrich, to say whether he thought the responsibility should remain with TSA or shift to a different agency. In the June op-ed, he and Glick wrote, “Given the high stakes, Congress should vest responsibility for pipeline security with an agency that fully comprehends the energy sector and has sufficient resources to address this growing threat.” They suggested DOE, noting the recent creation of CESER.
He also declined to say whether there should be mandatory reliability standards for pipelines, saying that standards were “one way” but “not necessarily the only way” to protect them.
“Of course there should be mandatory standards for gas pipelines!” King said. “They’re part of the electric system. … It seems to me we’ve already passed this effective system for the electric utilities, and Mr. Chairman, I’m with you 100%, but I just don’t want you to hedge about it. I think you should come right out and say, ‘We got to do this.’”
Chatterjee noted that TSA has the authority to issue mandatory standards. “It would take Congress” to change the agency responsible.
“I think we should all be thinking about this question,” Heinrich said to his colleagues. “Where is the right place to do this?”
WASHINGTON — More than 1,000 policymakers and industry officials gathered here last week for the National Association of Regulatory Utility Commissioners Winter Policy Summit, where they heard discussions on prospects for the growth of organized markets in the West, the future of coal and nuclear power, and President Trump’s environmental policies and re-election chances. Here’s some of the highlights of what we heard.
Brittany Bolen, associate administrator of the EPA Office of Policy, was the first to speak at the summit Feb. 11. Acting Administrator Andrew Wheeler was scheduled to appear, but according to NARUC President Nick Wagner, “he had something come up at the last minute.”
Bolen defended the agency’s actions under Trump that she said have provided “regulatory relief to create jobs and foster economic growth” while improving air quality.
“Within the last two years, we’ve been able to finalize 33 deregulatory actions that have saved the American people $2 billion in regulatory costs,” she said. At the same time, she said, “U.S. greenhouse gas emissions fell 12% since 2005. From 2005 to 2017, U.S. energy-related CO2 emissions fell by 14%.”
Last month, the Rhodium Group estimated that U.S. CO2 emissions rose 3.4% in 2018, something the Energy Information Administration predicted a year ago.
“We’ve given utilities and states the regulatory certainty they need to invest in new technologies,” Bolen said. “We recognize that you and your partners in the states have worked to provide efficiencies for a long time, and we are no longer ignoring you or, worse, usurping your authorities. We want to work together with you, and we believe our approach will provide greater certainty for you to implement your ideas and serve the people in your states.”
She said the agency is still reviewing comments on the Affordable Clean Energy (ACE) Rule, the Trump administration’s replacement for the Obama administration’s Clean Power Plan, on which the Supreme Court issued an “unprecedented” stay.
“With regards to the [ACE] Rule, what I’d like to do is just say at the outset: We are in fact regulating CO2,” Bolen said. “We are proposing to reduce CO2 emissions comparable to that of the Clean Power Plan,” saying it would result in a 34% reduction in electricity sector emissions below 2005 levels.
The ACE Rule identifies on-site heat rate improvements as the best system of emission reductions (BSER) for existing power plants, as opposed to the CPP, which set state emissions limits and encouraged switching to natural gas and renewables.
“So, unlike the CPP, our ACE Rule respects the rule of law and operates within the four corners of the Clean Air Act,” she said.
Similarly, she called the Obama administration’s determination that carbon capture and sequestration was the BSER for new coal-fired power plants “disingenuous. We believe they knew the technology was not adequately demonstrated as required by the statute.”
Bolen also defended the agency’s recent proposed finding that it was not “appropriate and necessary” to regulate mercury emissions.
“We’ve spent the last several months trying to communicate to the public and those interested about what we were doing with this proposal,” she said. “I know there’s some … misinformation about what is in this proposal.”
She stressed that the proposal was merely in response to the Supreme Court’s ruling in 2015 that EPA had not properly accounted for the costs of its Mercury and Air Toxics Standards, though it left the standards’ hazardous air pollutant (HAP) requirements in place. Though EPA issued a supplemental A&N finding the next year, Bolen said it still relied on the co-benefits of regulating mercury to justify the rule, “outside of the specific statutory requirements.”
But, she said, “we are not repealing the HAP emissions standards or other requirements of the MATS rule, which have been in place since 2012. … We recognize that power plants have spent roughly $18 billion to comply with the 2012 standards, and we acknowledge that in the last decade alone, mercury emissions have decreased by 90%.”
Bolen did not take questions from the audience.
Murkowski Optimistic on Congressional Action
Sen. Lisa Murkowski (R-Alaska), chair of the Senate Energy and Natural Resources Committee, said she was “on a celebratory high” as she received a standing ovation before speaking Wednesday.
The day before, the Senate had overwhelmingly passed sweeping conservation legislation that she and Sen. Maria Cantwell (D-Wash.) had introduced at the beginning of this year to protect millions of acres of land. It was the first of several bipartisan bills that Murkowski said could be approved by the new Congress.
“This is going to be the Congress that can finally reach agreement on a major policy act that promotes energy innovation, efficiency and so much more,” Murkowski said. “I think you have a different dynamic in this Congress.”
She said that because of the takeover of the House of Representatives by Democrats, people have expressed skepticism to her about any major legislation passing.
“I disagree on that. I think we can find some common ground here,” she said, noting the conservation bill again. “I think we’ve demonstrated that not only can we do something in a bipartisan way, but also in a bicameral way.” According to The Washington Post, the bill is broadly supported in the House, which will vote on it later this month, and White House officials have indicated privately that the president will sign it.
But Murkowski expressed some frustration over the “billions, literally billions, of dollars of energy infrastructure projects, including pipelines [and] LNG export facilities … in the queue” at FERC. The commission “needs to have that full team to address that growing backlog,” she said.
Another priority for Murkowski is reforming the Public Utility Regulatory Policies Act. “We all love PURPA right?” she asked, prompting groans.
Murkowski was asked about whether there had been any progress on the Nuclear Waste Fund. According to an audit report by the Energy Department’s inspector general in May last year, $44.5 billion sat in the fund, intended to be used to build a permanent repository for nuclear waste. Since the Nuclear Waste Policy Act became law in 1983, utilities purchasing power from nuclear plants have paid fees into the fund, passing the cost through to ratepayers.
Congress designated Yucca Mountain in Nevada as the site for the repository in 1987, but the state has continuously opposed the move, tying it up in the courts, eventually leading the Obama administration to abandon the choice.
“The reason I am optimistic that you will see some progress in nuclear: This is something that, every time I talk with [Energy] Secretary [Rick] Perry, he brings it up with me,” Murkowski answered. “Every time I have an opportunity to be in the same room with [Sen.] Dianne Feinstein [D-Calif.] and [Sen.] Lamar Alexander [R-Tenn.], we all look at one another and say, ‘Wait a minute. We have got to get back to our nuclear waste act that we rolled out congresses ago.’ …
“There’s a dynamic right now on this discussion of nuclear waste that I haven’t felt or been part of for a good handful of years right now. So I feel more optimistic than ever. So, keep urging us in that direction, because that helps.”
FERC Chairman Neil Chatterjee later Wednesday also told the audience that PURPA reform was “one of my top priorities.”
“Given the front-line role that states play in implementing PURPA, I know this is an important subject to many in this room, and one that many of you have reached out to me about most frequently,” Chatterjee said.
He noted that in 1979, the year after PURPA was enacted, Sony released the first Walkman.
“Fast-forwarding to today … the Walkman was followed by the Discman, MP3 players and the iPod, and now streaming services.
“We’ve similarly seen the rise of renewable resources. They’ve become better able to compete in the marketplace, and those marketplaces themselves have evolved significantly. But notably, our PURPA policy hasn’t seen the same sort of evolution.”
Chatterjee also said the commission needs to revisit Order 1000. “I’ll just put it to you straight: Everyone seems to agree that Order 1000 is not working as intended. But when it comes to this topic, that’s about the only thing stakeholders can agree on.”
Some stakeholders have told him FERC should “repeal and don’t replace” the order, but Chatterjee defended competition in the transmission sector as a way to lower costs to consumers. “As we think about addressing Order 1000, I believe we owe it to consumers to put our best effort forward toward spurring competition to work and getting the scope of competition right,” he said.
Speaking to reporters after his speech, Chatterjee said, “I don’t like to set expectations or timelines, but I am very optimistic that 2019 will be a fruitful year at the commission, and that many of the issues that I laid out here today will be things that we will address.”
Asked about the impasse over natural gas infrastructure approvals, Chatterjee would only say that he was “very encouraged by the constructive dialogue I’ve been having with all my colleagues.” (See related story, Glick Shines Light on FERC Dispute over GHG.)
Washington Utilities and Transportation Commissioner Ann Rendahl moderated a panel on the Western Energy Imbalance Market’s growth and plans to add a day-ahead market to its current real-time offering.
Jennifer Gardner, senior staff attorney for Western Resource Advocates, noted that although the EIM’s member companies are expected to serve two-thirds of the West’s load by 2020, only 5 to 10% of total transactions occur in real time. One challenge: Day-ahead transactions will have to include payments for transmission access, unlike the real-time market in which transmission is “essentially free,” she said.
Robert Taylor, head of federal regulatory affairs for Arizona Public Service, said the key to the EIM’s growth has been its “evolutionary” not “revolutionary” pace, contrasting it with past failed efforts to develop a Western market.
“The reason this one … has been so successful is because it’s worked at an incremental pace. The EIM was a nice start. We were able to go in one at a time. We were able to get more comfortable with the market, the market rules. We were able to get more comfortable with our trading partners. And, quite frankly, we were able to get more comfortable with the CAISO — understanding how they work and that they would be responsive to our needs,” Taylor said. “It’s just a natural evolution to take a look at what the next step is with the day-ahead market and see if we can bring additional benefits to our customers.”
Idaho Public Utilities Commissioner Kristine Raper agreed that “evolutionary change” has led to the prospects of a true regional market. “I think it is reasonable for the regulators to want to be part of something that has a little more teeth than what the [EIM] Governing Body currently has within the larger CAISO,” she said.
Former Montana Public Service Commissioner Travis Kavulla, a member of the Governing Body, said he is seeking feedback from transmission-dependent utilities, independent generators and power marketers. “Clearly we can’t have a market design solely intended to benefit big vertically integrated utilities that have both big power fleets and a lot of transmission,” said Kavulla, now director of energy and environmental policy for think tank R Street Institute. “We need to be fair and equitable to all of the participants.”
Kavulla also said he is concerned about CAISO’s role.
“I’m just very conscious that we can’t let RTO management become a kind of Hal 9000 which is saying, ‘I can’t let you do that, Dave,’” he said, in a reference to the malevolent A.I. in “2001: A Space Odyssey.”
“It’s become a real problem in other parts of the country where RTOs somehow have, by default, or by delegating powers under themselves, become de facto policymakers. That’s not appropriate, and it’s not the role that was envisioned for them. They’re there to ensure economic efficiency and make sure the market works, but ultimately to accommodate the desires of stakeholders, including the foremost among the stakeholders: consumers and their government representatives,” he said. “I have lots of opinions on whether policymakers are making wise decisions about energy policy. I do know, though, that RTOs should not be the referee in that particular situation.”
In a panel on the future of nuclear power, Doug Vine, senior energy fellow at the Center for Climate and Energy Solutions, said zero-emission credits, such as those enacted in New York, New Jersey and Illinois, are the best policy solution available for keeping financially ailing nuclear generators in operation.
Vine said keeping existing nuclear plants operating is crucial to meeting greenhouse gas reduction targets. “This is why we’re saying that we need nuclear and renewables, not renewables attempting to replace nuclear power.”
John Parsons, executive director of the Massachusetts Institute of Technology’s Center for Energy and Environmental Policy Research, agreed.
“To reach the [state emission] targets, it became clear the reactors needed to be a part of the equation,” he said.
In New England, which lost the Vermont Yankee nuclear plant in 2014 and faces the closure of the Pilgrim nuclear generator in Plymouth, Mass., by June 1, “we are going to fail to meet our 2020 targets,” Parsons said. “I think the numbers are what will force people to confront the choices that have to be made. And that favors appreciating the value that’s in the nuclear plants that people found easy to overlook.”
But Steve Clemmer, director of climate and energy research and analysis for the Union of Concerned Scientists, said it is unrealistic to expect the U.S. can extend licenses to keep all its remaining generators operating for 80 years. The Nuclear Regulatory Commission, which initially licensed plants for 40 years, had granted 20-year extensions to 89 reactors through early 2018. Three of those have since retired regardless. The first request for a second 20-year license extension was filed by the Turkey Point Units 3 and 4 reactors in January 2018.
“It might make sense to keep some plants going,” Clemmer said. “Others it makes sense to retire. There’s going to be significant investments needed to replace equipment. There’s legitimate safety issues to keeping them operating that long.
“It really comes down to are we going to be able to reduce the cost of new nuclear versus competing options like — not just renewables and energy efficiency — but also carbon capture and storage,” he added. “We’ve done some long-term analysis through 2050 … and some of those studies show that natural gas with carbon capture and storage might become a very competitive option in the future. And nuclear could be if we achieve the cost reductions that the industry is promising. But that’s highly uncertain.”
Political Analyst Sees Close 2020 Race
Political analyst Stuart Rothenberg predicted the 2020 presidential race will be close, despite Trump’s current low approval ratings.
Rothenberg, who writes for Roll Call, said that because Trump has largely held on to the base of his coalition, he is unlikely to face a serious challenge in the Republican primaries. On Friday, William Weld, former governor of Massachusetts and the Libertarian Party candidate for vice president in 2016, announced he would challenge Trump for the Republican Party nomination.
In the 2018 midterm elections, the GOP lost many of the white, college-educated voters — particularly women — who supported Trump in 2016. Despite that erosion, Trump will be a formidable opponent, Rothenberg said.
“While he … looks behind when compared with generic Democrats, once the Democrats pick a candidate, he is going to skewer that nominee and attempt to demean, demoralize and destroy that candidate and polarize the country.”
DOE’s Walker Presses ‘Resilience Model’
Assistant Energy Secretary Bruce Walker, who heads the Department of Energy’s Office of Electricity, continued DOE’s campaign in support of coal and nuclear plants, repeating warnings about the U.S.’ increasing dependence on natural gas-fired generation. He also touted the grid “resilience model” DOE is developing.
He noted that most of the electric grid was built before computers and before the Sept. 11, 2001, terrorist attacks.
“What I’m really here to ask — particularly given the role of everybody here in this room — is that you take a step back and look at things like our [renewable portfolio] standards, look at affordability, look at emissions. But more importantly, look at the reliability and resilience of the system. We no longer live in an age where the infrastructure is not at risk. … I would ask that … you take those [threats] into consideration when things are being funded.”
On March 28, FERC and DOE will host a joint technical conference to discuss current cyber and physical security practices and how federal and state authorities can provide cost recovery for security investments.
‘Clean’ Coal Efforts Continue
Another DOE official, Lou Hrkman, deputy assistant secretary of the Office of Fossil Energy, said U.S. policymakers should be focused on developing carbon capture technology to keep coal generation viable.
“Worldwide there’s really two conversations going on: Here in the U.S., where we’re trying to destroy coal, and the other conversation is in Asia, where they take a more realistic and pragmatic approach, while at the same time expanding coal’s usage.”
Because the Paris Agreement on climate change puts no cap on China’s GHG emissions until 2030, Hrkman said, “they will use this time to build some 1,900 coal power plants around the world.”
“You could shut down the entire U.S. coal fleet … and you’ll have absolutely zero effect on worldwide CO2 emissions,” he continued. “Once you … accept that simple fact, the goal should be carbon-free fossil energy.”
He said DOE is funding research that will lead to small modular coal plants that would be able to compete with natural gas on cost and ramping flexibility. The U.S. goal is to “leapfrog” the technology of coal plants being built in Asia, which have efficiency ratings as high as 42%.
Hrkman said the goal is to reach 50% efficiency and reduce carbon capture to $30/ton. “Currently capture technology that we’re looking at is around $47/ton. It’s a hard goal to reach. But we think … some of the new technologies out there, have the potential to get us there in the not too distant future.”
“Once we achieve the $30 carbon it will be affordable for industry to adopt and deploy. And if you combine that with 45Q tax credits, we think there’s quite a business case to have out there for the investment community.”
The federal judge overseeing Pacific Gas and Electric’s bankruptcy case suggested last week he might prohibit the utility’s electricity suppliers from seeking FERC’s help with disputed contracts and order the agency to leave the fate of the contracts to the Bankruptcy Court.
PG&E has indicated it may seek to rescind costly PPAs with solar and wind generators. The utility said it has 387 power purchase agreements with 350 companies worth about $42 billion. Some PPAs, entered into before wind and solar dropped in price, are likely far above current market rates. (See PG&E Wants to Undo Contracts, Revamp Biz in Bankruptcy.)
“The debtors respectfully request that this court issue an order …. [blocking] any entity’s attempt to enforce the FERC order, and any action by FERC, or any other entity, that would attempt to divest or otherwise nullify or impede this court’s exclusive authority to approve or deny the debtors’ requests to assume or reject executory contracts under Section 365 of the Bankruptcy Code,” PG&E’s lawyers wrote in their Jan. 29 motion.
At a hearing Thursday, lawyers for PG&E and generators including NextEra and Calpine, which have PPAs with PG&E, debated the pros and cons of an injunction before Judge Dennis Montali, of the U.S. Bankruptcy Court in San Francisco.
Judge Dennis Montali | Commercial Law League of America
To preserve their PPAs, the generators are seeking to intervene in the PG&E bankruptcy case — another issue Montali must ultimately decide. They also want Montali to deny the injunction.
FERC wants the jurisdictional dispute, involving the Bankruptcy Code and Federal Power Act, heard by a U.S. Circuit Court of Appeals. “The circuit courts have ‘exclusive’ jurisdiction to ‘affirm, modify or set aside’ FERC orders,” lawyers with the U.S. Justice Department argued in court papers filed Feb. 6.
The adversarial proceeding between PG&E and FERC is separate from the utility’s bankruptcy, but the cases are closely linked and are both being heard by Montali for now. FERC’s motion to withdraw the adversarial proceeding from Montali’s courtroom is pending a hearing in May.
At times during Thursday’s hearing, Montali questioned the need for an injunction, but at other points he seemed inclined to issue one. Toward the end of the hearing, he said he might even skip the usual step of issuing a preliminary injunction and move straight to a permanent injunction.
There are no disputed facts in the case, just questions of law, he noted. Issuing a permanent injunction would allow the generators to file a direct appeal, letting a higher court decide the matter and speeding up the case, he said.
“There’s nothing to do between preliminary and permanent” because there are no factual disputes to resolve at trial, Montali said.
In the end, the judge put off a decision, giving FERC time to file its written arguments. The next hearing in the matter is scheduled for Feb. 27.
ERCOT is “much more likely” to deal with “emergency-alert type conditions” this summer given the system’s 7.4% reserve margin, CEO Bill Magness told his Board of Directors and the Texas Public Utility Commission last week.
“With the lower reserve margin, you’re just increasing your risk that any kind of circumstances — low wind, generation outages, extreme weather — could cause challenges on the system this summer,” Magness said during the board’s Feb. 12 bimonthly meeting. “That means bringing on resources we have available and the tools for dealing with that.”
ERCOT CEO Bill Magness (right) details preparations being made for the summer months.
Magness said the city of Garland’s December decision to indefinitely mothball the 470-MW coal-fired Gibbons Creek Generating Station has “effectively reduced” ERCOT’s reserve margin from 8.1%. The grid operator, which has a target planning reserve margin of 13.75%, avoided taking emergency measures last summer despite extreme heat and an 11% reserve margin.
The board took the news calmly as Magness detailed preparations being made for the summer months. Chief among those is the creation of a Gas-Electric Working Group, designed to facilitate reliability coordination between the natural gas and electric industries and ensure clear communication.
GEWG Chair Chad Thompson, ERCOT’s senior manager of operations engineering and support, stressed during the group’s first meeting Feb. 15 that the grid operator doesn’t want to interfere with existing relationships.
“[We] don’t want to get in the middle of your business. ERCOT wants to be a facilitator,” Thompson said.
The GEWG stems from a November gathering that PUC Chair DeAnn Walker held with several trade associations, municipalities, and other members of the electric and gas sectors. The PUC encouraged owners of gas-fired generation facilities, gas pipelines and electric utilities that serve the pipelines to participate in the working group.
“If we do get into a load-shed event, we want a clear understanding of where the critical facilities are,” Thompson said.
Walker has also convened meetings with ERCOT market participants and other stakeholders, similar to what she did before last summer. During the commission’s Feb. 7 open meeting, she said she has received significant input, “Some of it the same as last year.”
ERCOT has gathered transmission owners to ask that any planned outages be limited to off-peak periods and that restoration times be shortened. It will release its final seasonal assessment of resource adequacy on March 5, providing a scenario-based analysis of its summer expectations.
Texas Competitive Power Advocates, a trade organization representing about 60% of Texas generation, has said its member companies are planning to invest $100 million in existing facilities in ERCOT to prepare their fleets for summer demand.
ERCOT’s load and demand projections through 2023 | ERCOT
Advanced Energy Economy and the Sustainable FERC Project last week petitioned FERC for a declaratory order regarding ISO-NE’s possible attempt to retroactively apply new performance standards that would affect the eligibility of energy efficiency resources participating in the RTO’s capacity market.
The petitioners also asked the commission to clarify the appropriate process for changing the terms of market eligibility for EE resources.
ISO-NE’s graph shows the value of energy efficiency resources. | ISO-NE
The Feb. 13 filing cited a series of recent phone calls made by ISO-NE staff to Forward Capacity Market participants with qualified EE capacity resources. During those calls, staff members said that the RTO intends to change how it measures the demand reduction value of EE resources for participation in the FCM.
“ISO-NE staff indicated that the ISO may potentially do so retroactively and without seeking commission approval for these changes, even though the contemplated changes could significantly change the quantity of the resources that have already qualified for, and cleared, the most recent Forward Capacity Auction, FCA 13,” the groups said.
The complaint specifically alleges that the changes may include new “net-to-gross” conversion factors to revalue EE resources, factors “never previously required of, nor imposed on, market participants,” nor defined or described in the RTO’s Tariff or manuals.
The petitioners pointed out those factors were not included in most market participants’ FCA 13 measurement and verification documents — “the qualification determinations which were filed with, and have been accepted by, the commission for participation in FCA 13.”
“ISO-NE has created uncertainty about the methodology it will use to calculate demand resource values going forward, and this is causing real and continuing harm to the capacity market,” the petitioners wrote.
The RTO says the discussed changes are not a settled matter.
“We raised the matter of measurement and verification with EE providers recently and intend to have a more full and complete discussion before any changes would be made,” ISO-NE spokesman Matthew Kakley said.
But one key environmental group is skeptical of the RTO’s intent.
“New England’s grid operator is proposing to change the rules midstream and out of the public eye, without explaining what the new rules would be,” said Bruce Ho, a senior advocate at the Natural Resources Defense Council. “This is absurd. Federal regulators need to step in and ensure that energy efficiency resources get a chance to compete fairly in the capacity market. Any changes to the established market rules must be subject to careful consideration and review.”
The two complainants said they filed the petition to “provide greater certainty” to New England EE resources in the near future.
“The measurement and verification changes proposed by ISO-NE in its phone calls would substantially impact the energy efficiency market in New England, reducing the value of energy efficiency resources in the FCM, driving up prices and ultimately forcing ratepayers to pay higher prices,” they said. “Petitioners and our members and partners hope to work cooperatively to address these issues with ISO-NE in the stakeholder process moving forward.”
ERCOT CEO Bill Magness said last week that the grid operator will use favorable budget variances to fund the addition of real-time co-optimization (RTC), as it has been directed to do by the Texas Public Utility Commission.
ERCOT’s Board of Directors gathers for its February meeting.
In delivering his CEO report to the ERCOT Board of Directors during its regular bimonthly meeting Feb. 12, Magness said staff have identified $43.7 million in favorable variances that would cover the project’s estimated $40 million cost. Much of the variance is because of aggressive interest rate assumptions set in 2017, Magness said.
The PUC last month directed ERCOT to proceed with RTC’s implementation. Commission Chair DeAnn Walker has said that RTC would bring economic and operational benefits to the market. (See Texas PUC Responds to Shrinking Reserve Margin.)
Staff have said it will take four to five years to implement RTC, the process of procuring energy and ancillary services simultaneously in the real-time market every five minutes to find the most cost-effective solution for both requirements.
Magness said he would provide a clearer picture during the board’s April meeting, following a financial audit that determines the final variances.
“As we know from past projects, until we get the protocols written and we know what we’re building, it’s hard to get a much better estimate than the one we’ve provided,” he said.
As for the interest assumptions, Magness said, “We’ll be reupping those and changing those to where we accurately believe we are in 2020 and 2021.”
Staff Present Transmission Planning Report
Jeff Billo, ERCOT’s senior manager of transmission planning, briefed the board on the grid operator’s transmission planning practices, assuring them that staff carefully match projects and needs.
“We take our job very seriously, and we only build what needs to be built,” he said.
Annual transmission costs — charged to consumers to pay for ERCOT’s system — have steadily risen from about $1.3 billion in 2008 to nearly $3.5 billion in 2017. Billo said the rise can be attributed to the Competitive Renewable Energy Zone (CREZ) project, natural load growth and Far West Texas load growth.
According to NERC’s 2018 long-term reliability assessment, ERCOT’s 1.76% 10-year forecasted growth rate trails only that of the Western Electricity Coordinating Council’s Rocky Mountain Reserve Group subregion (1.8%).
“A strong economy leads to load growth,” Billo said.
ERCOT’s Jeff Billo explains the grid operator’s transmission planning processes.
Much of the CREZ project, a 345-kV infrastructure build connecting wind-rich West Texas with urban centers, went into service in 2013. Almost $5 billion was invested that year alone, resulting in a $700 million one-time bump in transmission costs, he said. However, CREZ has also provided a strong 345-kV backbone as ERCOT works to meet the growing petroleum-fueled load growth in the Permian Basin, where peak demand has doubled since 2009.
“Without CREZ, we would have seen a significant amount of transmission needed for far West Texas,” Billo said. “It’s been a challenge keeping up with that growth.”
He said transmission upgrades incorporate double-circuit capability and higher-voltage lines to be able to meet even higher loads in the future. ERCOT has conducted special assessments to try and get ahead of that higher growth.
“Based on 2018 forecasts and studies, our plan is sufficient,” Billo said.
A wave of wind and solar projects in West Texas — “There’s more wind and solar existing or planned than CREZ’s capacity,” Billo said — and increased LNG activity on the Gulf Coast will result in more load growth and congestion. ERCOT has already approved the Freeport Master Plan Project to address LNG growth, and the work to integrate Lubbock Power & Light’s load is expected to relieve constraints in that region. (See “Regulators Grant Preliminary Approval to Sharyland-LP&L Projects,” Texas Public Utility Commission Briefs: Feb. 7, 2019.)
Board Approves Leadership for 2019
Magness introduced Jeyant Tamby to the directors as an ERCOT senior vice president and its first chief administrative officer. Tamby, who was among the officers ratified by the board for one-year terms, served as former CEO H.B. “Trip” Doggett’s (2010-2016) chief of staff. He will bring together many of ERCOT’s corporate functions into a more efficient structure, Magness said.
Magness, who was elected to another one-year term as CEO, also announced the retirement of Human Resources Vice President Diane Williams, who joined ERCOT in 2014.
“I’ve seen pictures of her grandchild,” he joked. “I can’t convince her to stay.”
Craven Crowell and Judy Walsh were re-elected to the board as chair and vice chair, respectively. However, Walsh has stepped down as chair of the Finance and Audit Committee and will be replaced by unaffiliated director Terry Bulger.
The board also confirmed ENGIE’s Bob Helton and the Office of Public Utility Counsel’s Diana Coleman as chair and vice chair, respectively, of the Technical Advisory Committee.
ERCOT, SPP, MISO Hammer out Coordination Plans
ERCOT Assistant General Counsel Nathan Bigbee said staff have revised a coordination plan with SPP and, pending final direction from the board and additional comments, will negotiate the final revisions with its neighbor.
ERCOT has been working on a new bilateral agreement with SPP since 2016 as a result of its switchable generation resource (SWGR) policy review. ERCOT began similar discussions with MISO last year. The three grid operators met to jointly discuss coordination principles and develop updated agreements and are currently taking their coordination plans through their respective stakeholder processes.
Bigbee said the plans offer greater detail around switchable-unit operations during emergency situations. The biggest change authorizes the requesting grid operator to issue directives upon receiving notification of an SWGR’s release. The controlling grid operator is required to notify the resource’s operator that the unit is needed to address an emergency condition in the neighboring region.
The release can be denied should the SWGR’s release “cause or exacerbate” an emergency condition. In the unlikely event of a simultaneous emergency scenario, primary control is assigned to the grid operator when the SWGR’s capacity has been nominated to satisfy that operator’s supply adequacy or capacity planning requirements.
“You may be asking, ‘We don’t even have a capacity market in the ERCOT region. How can we ever be primary?’” Bigbee said. “If the capacity has been nominated to satisfy supply adequacy requirements in the region, then it’s considered to be our capacity. We presume that capacity is going to be available on peak, unless you’ve submitted a notification under the protocols that says the capacity is obligated elsewhere by a contractual obligation during peak-load season.”
ERCOT will post the plans’ final executed versions on its website.
Board Approves Ancillary Service Changes
The board approved the TAC’s recommendation to tweak ERCOT’s ancillary service offerings, which predate the switch from a zonal to a nodal market in 2010. (See “TAC Endorses Granularity to Ancillary Services Products,” ERCOT Technical Advisory Committee Briefs: Jan. 30, 2019.)
The Nodal Protocol revision request (NPRR863) creates a new ERCOT contingency reserve service (ECRS) and modifies responsive reserve service to become primarily a fast frequency response (FFR) service. The changes are designed to provide the grid operator with more “granular tools” to resolve low inertia levels caused by the changing resource mix, and to allow resources to earn compensation for providing primary frequency response.
ERCOT’s ancillary services design has remained the same, as wind, solar and battery resources increase their market presence.
ExxonMobil Power and Gas Services’ Glen Lyons, representing the consumer market segment’s industrial sub-segment, abstained from the vote. Lyons noted the four opposing votes cast during the TAC meeting by industry consumer groups, which opposed the implementation timeline.
FFR will be implemented in 2020 and ECRS no earlier than Jan. 1, 2022.
The board approved eight other NPRRs and two Other Binding Documents revision requests (OBDRRs) on its consent agenda:
NPRR850: Lays out principles for ERCOT and market participants to follow during a market suspension and restart, and how activities will be settled during those events.
NPRR871: Gives ERCOT a mechanism to conduct a reliability review through its normal study process of customer- or resource-funded transmission projects, but without providing a recommendation.
NPRR886: Requires ERCOT, to the extent possible, to provide notice and allow time for comments before executing any new or amended agreement with another control area operator.
NPRR905: Provides resettlement to reflect the proper distribution of the congestion revenue rights balancing account.
NPRR907: Replaces the M1a component of the total potential exposure calculation with a value that can vary based on non-banking business days and ERCOT holidays following the specific operating day. The M1a component sets a time period reflecting the number of days between an operating day and the beginning of a mass transition of the market participant’s electric service identifiers.
NPRR910: Codifies eligibility, pricing and settlement for a resource that has been awarded a three-part supply offer in the day-ahead market but decides not to operate in the real-time market, and subsequently receives a reliability unit commitment instruction.
NPRR911: Reinstates previous language in the applicable protocol sections for determining the real-time LMPs of logical resource nodes for online combined cycle generation resources (CCGRs), following NPRR890’s approval. The LMPs will now be based on their weighted average at the resource node for each of the generation resources in the online CCGRs, using their real-time telemetered outputs to calculate the weight factor.
NPRR915: Defines batteries and other limited-duration resources and clarifies how their qualified scheduling entities should indicate to ERCOT their unwillingness to be deployed in real time, thus reserving the capacity for expected values above the energy offer curve.
OBDRR010: Codifies that the high sustained limit for a resource will continue to be included in the online capacity considered in operating reserve demand curve (ORDC) pricing even when that resource has been awarded a three-part supply offer in the day-ahead market but decides not to operate in the real-time market and subsequently receives a RUC instruction. Related to NPRR910.
OBDRR011: Shifts the ORDC’s loss-of-load probability curve by 0.25 standard deviations in 2019 and by the same measure in 2020, resulting in a single blended ORDC curve.
CARMEL, Ind. — MISO will this year draw on three sets of contributors to create its load forecast for 2020 transmission planning.
The RTO said last week it has moved ahead with a proposal to have Purdue University’s State Utility Forecasting Group (SUFG) and consulting firm Applied Energy Group (AEG) work with 20-year forecasts provided by load-serving entities.
By June, MISO will have its first load forecast based on the four 15-year future scenarios it uses annually in its Transmission Expansion Plan. Throughout last year the RTO had been examining how it could coordinate its annual load forecasting with its annual transmission planning.
Until the compromise was struck late last year, MISO had put a temporary hold on ordering more independent load forecasts from the SUFG. LSEs will now develop 20-year base load forecasts that include monthly predictions for energy and non-coincident peaks, which the SUFG will use in its state-by-state forecast.
The LSEs will also compile demand-side data separately for AEG, which will use the figures to develop demand-side management potential used in RTO planning. (See MISO Presents Load Forecasting Compromise.) MISO plans to compile and check forecast data and serve as a liaison between all parties.
“The original goal of this merged proposal is to provide more clarity, consistency and efficiency to load forecasting,” MISO adviser Ling Hua said at a Feb. 13 Planning Advisory Committee meeting.
MISO will begin building models in May for resource forecasting as part of MTEP 2020.
MISO’s 140-plus LSEs received load forecast surveys in mid-January and were expected to respond by Feb. 15. The RTO said it will next month check the submitted data for completeness.
Veriquest Group’s David Harlan said he still didn’t see how MISO’s new process will translate into new load shapes.
Hua said the RTO isn’t aiming for new load shapes for 2020’s MTEP, just a more detailed forecast.
“We’re envisioning that this is going to be an incremental step. For this time around, we’re going to implement more granular load data, but updated load shapes will be for the next time around,” she said.
MISO to Process Hybrid Interconnections Under 1 Form
MISO plans to allow generating facilities using more than one fuel source — or hybrid resources — to submit a single request to join the interconnection queue, pending FERC approval.
The current Tariff prohibits customers from designating two fuel types on an interconnection request, but MISO’s proposal will allow them to submit a hybrid generating interconnection on a single application.
MISO transmission | MISO
The revised interconnection request form will allow interconnection customers to “check all that apply” for fuel sources, including a line for storage, a change that will ease an “administrative burden,” MISO said. Hybrid interconnection requests are technically already permitted by the RTO, just under separate applications.
“It’s the same policy, just a practice change,” Resource Interconnection Planning Manager Neil Shah said.
MISO plans to file the proposal by the end of the month.
The RTO also plans to make a similar interconnection Tariff filing this month, clarifying that it allows two facilities to share a single point of interconnection, provided it, both facility owners and the transmission owner sign an agreement. (See MISO Queues up Interconnection Options.)
Draft Rules Discourage Weak Grid Interconnections
In an effort to ward off inverter-based instability, MISO is firming up rules requiring inverter-based generators seeking to enter the interconnection queue to provide a specific set of calculations and documentation.
The RTO has already drafted new Business Practices Manual language, although stakeholders at a Feb. 12 Planning Subcommittee meeting urged it to take a more active role in calculations before finalizing rule changes. (See MISO Moving to Head off Inverter-based Instability.)
Under current practice, interconnection customers must submit short-circuit ratios (SCRs) to MISO before the close of the first decision point in the interconnection queue, while TOs must calculate and report fault megavolt-ampere values to those customers. In addition, the customers must also either submit manufacturer documentation showing that their generation can steadily operate or an Electromagnetic Transients Program-based study report showing stable operation for the inverter-based resource.
Clean Grid Alliance’s Rhonda Peters argued that the RTO isn’t allowing interconnection customers enough time in the queue to pull together all the required documentation.
“It’s not cheap to hire a consultant to put together a model,” Peters added.
She also suggested that MISO calculate the SCRs for customers, given the lack of a standard method for calculating. All interconnection customers should be working from the same set of assumptions, she said.
Other stakeholders urged MISO to take the reins in crafting SCR values at the beginning of the definitive planning phase of the queue.
Shah said MISO can examine taking a more involved role in calculating the SCR values, adding that the SCR is a simple calculation, if customers are working off accurate grid information.
“To my understanding, calculation of the SCR takes no more than 20 minutes if you have the right models in place,” Shah said.
The RTO asked for more stakeholder feedback on the draft rules through Feb. 26.
MISO expects current policy and economic trends to persist from 2020 to 2035, suggesting only slight changes to the four futures that guide the planning behind the MTEP.
“MISO believes there has been minimal changes since the MTEP 19 futures, and we’re in the same place trend-wise where we were last year,” Planning Manager Tony Hunziker said during the Feb. 13 meeting.
The RTO in 2017 began developing 15-year futures meant to be reused over multiple annual planning cycles after staff noticed little year-to-year change in forecasted trends. (See MISO to Recycle Tx Planning Scenarios for 2019.)
MISO’s four 15-year futures include a base case/limited fleet change scenario, continued fleet change future, an accelerated fleet change future, and a future in which distributed and emerging technologies become more widely used in the RTO’s footprint.
For MTEP 2020, MISO plans a simple refresh of its underlying data, including new capital cost data, demand forecasts, fuel forecasts, generation retirement projections, renewable targets and updated statistics on the interconnection queue, Hunziker said. The futures will be discussed again in April and finalized in June.
Veriquest’s Harlan said he wanted MISO to discuss the possibility of an additional future during the workshop, asking for a fifth future that illustrates an increasing reliance on imports in local resource zones and the closing physical gap between generation and load as gas and coal units retire. Other stakeholders asked that the RTO start including findings from its ongoing renewable integration impact assessment in MTEP futures. (See Study: MISO Grid Needs Work at 40% Renewables.)
MISO has said it may consider working on completely new future scenarios for MTEP 2021.
