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FirstEnergy Solutions is looking to recent developments in New England to bolster its renewed argument that FERC take emergency action to financially support “fuel-secure” resources to promote resilience of the nation’s electricity grid.
ISO-NE’s request to prop up Exelon’s Mystic gas-fired plant shows FERC’s “failure … to ensure the continued operation of critical nuclear and coal-fired generators while a long-term solution is developed” when it declined to implement the emergency price supports envisioned by the Department of Energy’s Notice of Proposed Rulemaking earlier this year, FES argued in comments filed on Friday in FERC’s resilience docket (AD18-7).
Mystic Generating Station
“On multiple occasions in the past several years, the commission was asked to undertake decisive action to preserve grid resilience but failed to do so,” FES wrote, calling on FERC to implement “the same relief requested by ISO-NE but applied at a level sufficient to protect the resilience of the nation’s electric grid.”
“If the commission acts now to preserve nuclear and coal-fired generators, it will have more options to address resilience problems in the future,” the company said. “These options will not exist if the commission waits years or even months to act.”
‘Things to Come’
FES argued that ISO-NE’s Tariff waiver request to keep Mystic running despite Exelon’s plans to retire the facility (ER18-1509) “foreshadows things to come if the commission does not undertake swift and decisive action to preserve fuel-secure generating resources” and “is the consequence of commission inaction and, particularly, its failure to ensure that RTO/ISO markets contain just and reasonable rules that provide adequate compensation for needed generation.”
ISO-NE’s request inspired a Section 206 complaint from the New England Power Generators Association on the issue (EL18-154), along with dissent from other stakeholders. (See Mystic Waiver Request Spurs Strong Opposition.)
Such individual reliability-must-run agreements “are merely Band-Aids,” and without action “at once and on a national level … the commission soon will face a flood of similar requests … that do nothing to address the underlying problems that necessitate such requests,” FES said.
FES filed for bankruptcy on March 31, just a day after announcing the closure of its three nuclear plants and two days after asking Energy Secretary Rick Perry to issue an emergency order under Section 202c of the Federal Power Act directing PJM to compensate coal-fired and nuclear power plants that have 25 days of on-site fuel. Parent company FirstEnergy has since developed a plan to extricate itself from the woes of its merchant subsidiaries. (See FirstEnergy Announces Mixed Earnings, Plan for FES Bankruptcy.)
FES’ pleas to Perry came less than 90 days after FERC rejected his call for cost-of-service payments to coal and nuclear generators (RM18-1) and opened a new docket (AD18-7) to consider grid resilience. (See DOE NOPR Rejected, ‘Resilience’ Debate Turns to RTOs, States.)
The company’s comments were filed in the new docket — along with the Mystic RMR and NEPGA complaint dockets — calling on FERC to reconsider the company’s proposal in the docket initiated by Perry’s request.
FES frames the current resilience docket as a chance for FERC to rectify past mistakes, laying out what it believes are previous opportunities to address issues the commission missed. They include Maryland’s attempt to subsidize construction of a gas-fired generator in 2009, Ohio’s requests for power purchase agreements in 2016, DOE’s NOPR in 2017 and its 202c emergency relief request.
No Real Markets
The filing also takes on repeated claims by RTOs/ISOs that they have the situation under control.
“ISO-NE’s request represents a breach in the dam. Without immediate and meaningful action on a broad scale, the commission will soon be faced with a flood of requests for waivers. Even that may not even be enough to address the threat to the grid’s resilience if RTOs and ISOs continue to ‘hear no evil, see no evil, speak no evil,’” the company said. “The record also makes clear that the commission can no longer rely on assurances from RTOs and ISOs that ‘all is well’ and that they have the problem in hand.”
The company argues two views that radically diverge from sentiment in much of the industry.
First, even though most electricity outages are caused by disruptions at transmission and distribution facilities, resilience isn’t resolved by adding more redundancy on those networks because “threats to the electric grid’s resilience stem first and foremost from problems with the nation’s fuel supply mix,” the company said. However, the filing doesn’t define the threats.
Second, the company argues that providing supports to nuclear and coal-fired units won’t “blow up” markets because they don’t really exist. The idea “that we have truly efficient markets today, where competition among suppliers actually sets prices” is “fundamentally flawed.”
The company included in its filing a 20-page report done by D.C. law firm Wilkinson Barker Knauer in May that FES said “demonstrates that continued deification of these so-called markets is misplaced.” The paper argues competitive energy markets are “in tatters,” having been “trampled” by out-of-market payments to generators, such as renewable energy credits or RMR contracts.
“An overreliance on natural gas in New England has produced a loss of fuel security and diversity so extreme that the retirement of a single natural gas-fired station that does not rely on pipeline gas will expose ISO-NE’s electric grid to rolling blackouts in the coming years,” FES said, noting that CAISO has recently had to confer RMR contracts on three gas-fired plants. (See FERC Approves CAISO-Calpine RMR Settlements.)
WESTBOROUGH, Mass. — Offshore wind development, energy efficiency and engaging electricity users were the topics at ISO-NE’s Consumer Liaison Group meeting on Thursday. Here’s some highlights.
“Offshore wind is happening a lot faster than people thought it would,” observed Edward Anthes-Washburn, executive director of the New Bedford Port Authority. Within the past month, Connecticut, Massachusetts and Rhode Island selected a combined 1,400 MW of offshore wind contracts, New York is set to procure 800 MW later this year, and New Jersey set a target of 3,500 MW by 2030.
Massachusetts officials hope to develop supply chains for the nascent offshore wind industry in New Bedford because of “the existence of trained welders, mechanics, etc., since workforce training is a big expense in starting a new industry,” Anthes-Washburn said.
But the new ocean development must coexist with the Atlantic fishing industry that preceded it, Anthes-Washburn said. The port supports about 13,000 jobs and generates nearly $10 billion in economic activity each year.
“Since we are the No. 1 fishing port in the U.S., I look at [OSW development] through the lens of the commercial fishing industry because that is by far my No. 1 stakeholder,” he said. “We really want to make sure that as the offshore wind industry develops, it does so in a way that integrates with the commercial fishing industry. It’s really critical that we do that now, with the first project.” (See Competition, Cooperation and Costs the Talk at OSW Conference.)
Between the shipping transit lanes, the fishing grounds and the wind energy areas, “there is a lot going on on the continental shelf,” Anthes-Washburn said. “The sooner we can de-conflict a certain area and understand who’s going to be impacted by offshore wind, the faster we can start having a conversation with the commercial fishing industry, with the recreational boaters, with the commercial marine operators.”
Because of New Bedford’s outsized role in the fishing industry, the Port Authority’s Fisheries Advisory Committee on Offshore Wind represents about 30% of all U.S. commercial fishing, he said.
States are vying to get the early-entrant advantage in establishing supply chain centers for the industry.
Last week, the Department of Energy awarded a $18.5 million grant to the New York State Energy Research and Development Authority to lead a nationwide research and development consortium for the offshore wind industry.
Mike Jacobs from the Union of Concerned Scientists noted that ISO-NE “has a fuel security analysis circulating, and they’re basing their policies on the idea that there’s not an offshore wind industry coming along … so this [forum] is a helpful thing for educating ISO New England.” (See Report: Fuel Security Key Risk for New England Grid.)
However, Anne George, ISO-NE vice president for external affairs, said one scenario in the fuel security analysis assumed 2,000 MW of offshore wind. “We wanted to show the range so that we could have this conversation,” she said.
Emphasizing the Consumer
The CLG holds quarterly meetings around the region to provide a chance for residents, state officials and energy experts to learn more about the grid operator.
CLG Chair Rebecca Tepper, chief of the energy and telecommunications division in the Massachusetts attorney general’s office, emphasized the “consumer” in the name of the group. CLG Steering Committee member Bob Espindola echoed Tepper’s remarks.
“Our primary focus is to think about what you can do as an end user to impact your own electric and gas bills, and knowing what’s coming in the future, to be in a better position to do that,” said Espindola, energy systems program manager at Acushnet, the maker of Titleist golf balls.
Sue Coakley, executive director of Northeast Energy Efficiency Partnerships, spoke of energy efficiency’s affordability, reliability and contribution to reducing carbon emissions. “Just in the last three years, the current portfolio of efficiency programs in Massachusetts is saving $4 billion for consumers,” she said. “That’s just a tremendous resource.”
Wendy O’Malley, manager of the Property Assessed Clean Energy (PACE) program at MassDevelopment, explained how her organization uses tax assessments to enable property owners to obtain low-cost, long-term financing for EE projects and more.
“End users have all these solutions, but if they don’t have a way to finance them, or buy a new technology, they’re really left with no solution,” O’Malley said.
PACE assessments are similar to those used to collect the cost of public infrastructure that benefit specific properties such as sidewalks or sewers. The program finances EE projects at up to 100% and for terms of 20 years or more. Property owners pay for the improvements as part of their property tax payments, and the local government remits the PACE portion to the lenders.
Andy Haun, microgrid chief technology officer at Schneider Electric, said the rapid increase in the digitization of electricity “is usually an IT solution, and it’s not really helping us directly.”
“What is helping us is we’re also digitizing the control of that electron, so the devices — the actual appliances that use the electricity, the appliances that produce the electricity — these are under very smart control systems, which by themselves and aggregated are able to then act on the energy equation,” Haun said.
“This Internet of Things-enabled data infrastructure is allowing new ways for us to do more effective use of our energy and, in particular, electrical energy,” he said, adding that decarbonizing the grid and decentralizing it “go hand in hand.”
Brett Feldman, research analyst with Navigant Research, spoke about engaging customers through demand-side management.
The old way of obtaining customers was going door to door, but the “new way is to lasso the entire customer base and give them the chance to opt out of the savings opportunities rather than having to sign up people one by one,” Feldman said.
Another new trend is utility/vendor marketplaces, especially for millennials, who increasingly make their purchases online, he said.
Edward Woll Jr., a partner with Sullivan & Worcester, asked whether microgrids could help both shave the peak load for New England and be “cheaper than the power that you get from the grid.”
Haun responded that “in most all cases — except when someone put the microgrid in specifically for resilience needs — you’d be doing it because it’s going to save you cost from the tariff rate.”
“The distributed energy resources reduce costs because they’re being packaged, they’re being manufactured in locations that enable them to be very easily deployed,” Haun said. “These systems are going to put pressure on the cost of the energy against what you wouldn’t be buying from the grid, absolutely.”
Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees on Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be in Wilmington, Del., covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
2. PJM Manuals (9:10-9:30)
Members will be asked to endorse the following proposed manual changes:
B. Manual 20: PJM Resource Adequacy Analysis. Revisions developed to modify how winter peak weeks are calculated to address concerns that the current “theoretical” approach used in PJM’s PRISM modeling software to estimate RTO-wide generator outage levels during the winter peak does not reflect historical outage levels. (See “Winter Modeling Changes,” PJM PC/TEAC Briefs: May 3, 2018.)
Members will be asked to endorse proposed revisions to the Tariff, Operating Agreement and Reliability Assurance Agreement to clarify cross references.
Members will be asked to endorse proposed changes to the long-term FTR auction construct to correct current processes that allow participants to obtain the rights to congestion on transmission paths before the owners of the underlying auction revenue rights. (See “Long-term FTRs Undercut Annual FTRs,” PJM Market Implementation Committee Briefs: June 6, 2018.)
Members will be asked to endorse proposed changes to allow including maintenance costs in cost-based energy offers as part of variable operations and maintenance (VOM); however, stakeholders will also likely discuss a proposal from the Independent Market Monitor that would eliminate those costs from such energy offers. (See “Accounting for Maintenance Costs in Cost-Based Offers,” PJM Market Implementation Committee Briefs: June 6, 2018.)
Members Committee
Consent Agenda (1:05-1:10)
Members will be asked to approve:
B. Revisions to the confidentiality provisions of the OA to specify that PJM may share member confidential information with reliability entities in addition to NERC. (See “Stakeholders Approve Changes to Manuals, Operations,” PJM Markets and Reliability Committee Briefs: May 24, 2018.)
Members will be asked to endorse proposed OA revisions related to Order 1000 competitive transmission project cost containment provisions. The revisions were developed collaboratively by LS Power, several state consumer advocates and the Monitor, and were resoundingly endorsed at last month’s MRC, despite strong opposition from transmission owners. PJM CEO Andy Ott will address members on the issue prior to the vote. (See Cost Containment Coming to PJM Transmission Bids.)
Members will be asked to endorse proposed revisions to the Tariff, OA and RAA to clarify cross references. (See MRC item 3 above).
3. Long-term FTR Auction (2:20-2:40)
Members will be asked to endorse proposed changes to the long-term FTR auction construct to correct current processes that allow participants to obtain the rights to congestion on transmission paths before the owners of the underlying ARRs. (See MRC item 5 above).
COOPERSTOWN, N.Y. — As it wrestles with the increasing penetration of distributed energy resources and growing efforts to decarbonize the grid, FERC is closely watching New York’s efforts to price carbon into its wholesale electricity market.
“New York is working on carbon pricing, which is an attempt to reflect and achieve and reconcile state policy goals in the market, through the market, rather than just accommodate them as in New England and PJM,” Becky Robinson, deputy director of FERC’s Division of Economic and Technical Analysis, told NYISO’s Management Committee on Tuesday. “So the commission is watching very closely.” (See NYISO Favors Cost Levelizing on Carbon Charge.)
Staff from FERC’s Office of Energy Policy and Innovation also attended the meeting June 12 and answered questions from stakeholders.
ISO-NE’s Competitive Auctions with Sponsored Policy Resources construct “is what we term more of an accommodate approach, where the goals are to allow state-supported resources to participate in the capacity market, but put a structure in place that maintains competitive markets,” Robinson said. (See Split FERC Approves ISO-NE CASPR Plan.)
PJM has also filed two competing proposals dealing with state-sponsored resources that the commission must rule on by June 29, she said.
“The first PJM proposal, capacity repricing, is a different type of accommodate solution, and the second is what they call MOPR-Ex, which expands” PJM’s existing minimum offer price rule to bar subsidized resources from receiving a capacity commitment, Robinson explained. (See PJM Urges FERC to Act on ‘Jump Ball’ Despite Criticism.)
DERs Feedback
Speaking about the commission’s April 10-11 technical conference on distributed energy resources, Robinson said “one key takeaway is that states want flexibility. You still need to flesh out what is the role of the distributing utility relative to that of the aggregator.” (See Ready to Act on DERs, FERC Tells Congress.)
Asked about the key areas the commission is examining in market rules for DERs, Robinson said, “Coordination is a big one … and double-counting is an issue. We think there are ways — there are tools you can use — to avoid that. And jurisdiction, that has been contentious in the docket: Who does what and where?”
“Some people think it means we should be creating rules to recognize the differences in those technologies from more traditional types of generation resources, and other folks have assumed that we should be trying to create the same rules as much as possible between new technologies and traditional resources,” Lang said.
He asked whether an energy storage project should have to meet the same market rules as a 500-MW combined cycle unit.
“I think we tried to indicate some flexibility on that,” Robinson said. “Commission staff look for ways to rationalize the participation model. … On the DER space, I don’t think we proposed a participation model for DER aggregation.”
Adequate Summer Capacity Forecast
NYISO Vice President of Operations Wes Yeomans told the committee the ISO is prepared to meet peak demand this summer, with a total of 42,169 MW of resources available to cover an expected peak of 32,904 MW, which is 2.9% above the long-term average.
Yeomans said his report was identical to that presented to the Operations Committee and the press on May 30, except for a note explaining that that the Market Monitoring Analysis Group (MMA) had visited 22 generator sites to check their reliability readiness. (See NYISO Ready to Meet Summer Demand.)
The MMA reviewed planned maintenance outages and practices in order to reduce forced outages, and also checked that generators had adequate supplies of backup fuel storage.
2018 Master Plan Focuses on Grid Evolution
NYISO is this year preparing a Master Plan with three key themes: resource flexibility, grid resilience and price formation.
Michael DeSocio, the ISO’s senior manager for market design, told the committee that ISO staff are working on a comprehensive five-year plan to prepare for anticipated changes to the bulk power system, with a focus on projects that help prepare for the evolution of the grid.
“The addition of renewable resources expected as a result of the [state’s] Clean Energy Standard will create a more dynamic grid, where supply is heavily influenced by the weather,” the draft plan said. “This necessitates a look at the incentives for flexible resources that will be needed to balance intermittent renewables, as well as alternative market designs that preserve revenue adequacy for generators needed for reliability.”
NYISO is examining how to incentivize development of flexible resources needed to balance the growth of intermittent renewables on its grid. | DOE
“Some grid operators are concerned about fuel security, but we feel pretty comfortable about fuel energy security,” DeSocio said.
Nonetheless, future changes to New York’s fuel supply mix, as well as increased demands for natural gas, may stress the grid, and the ISO recommends that it conduct a 10-year fuel security study in 2019 and, if necessary, implement market design changes in 2021.
“On carbon pricing, we got a lot of feedback,” DeSocio said, noting that stakeholders have commented that the ISO should accelerate the proposed timeline for implementing carbon pricing.
The ISO is also thinking about how to implement the market design, which they expect to have complete by Q2 2019, DeSocio said.
The revised Master Plan timeline accommodates carbon pricing implementation in 2021, which could be advanced to 2020 if stakeholders want to make it their top priority, he said.
Mark Younger of Hudson Energy Economics said he supported pricing carbon as quickly as possible, but shared the Market Monitoring Unit’s concerns about why so many of the other initiatives in the plan are listed as taking four years.
For example, transmission clearance prices: “It’s unclear why that should be hard to implement,” Younger said.
The deadline for stakeholders to submit replies to a Master Plan project prioritization survey is June 26.
MEXICO CITY — So what drove a nice kid from Chicago — a “regular American” with a minimal knowledge of the Spanish language — to move to Mexico and not only make his home there, but help design the country’s deregulated electricity markets?
“I really had no link to Mexico,” said Jeff Pavlovic, the nice-kid-turned-40. “After looking at the whole world, I figured electricity is a very important industry, and I could make a very big impact. If you can make electricity cheaper, you can change the economy.
“I saw Mexico as a great opportunity, as a place that hadn’t embraced market principles in the electric industry,” he said in a recent interview. “It was a long shot. You’re making a big bet on major change. If I could help change the electric markets in Mexico, I thought that could have as big an impact on the world as anything. I just thought about it and came to Mexico.”
Simple as that. Pavlovic obviously has an analytical mind. The son of a teacher, he also has the academic pedigree to match his entrepreneurial spirit. He picked up economics and math degrees from Duke, an MBA from Stanford and, after moving to Mexico in 2008, a master’s in economics from the Centro de Investigacion y Docencia Economicas (Center for Economic Research and Teaching).
Pavlovic, who spent a few months studying Spanish before moving to Mexico, is now fully bilingual. “I thought my Spanish was good enough, but it took three or four years before I could really communicate,” he said.
Fortunately, Pavlovic found himself in the right place at the right time. He was in Mexico, where the state-run electric monopoly doesn’t have “51 state governments deciding the rules.”
And though he admits it was a longshot, Pavlovic’s expertise in unbundling electric utilities as a financial consultant and in generation control and dispatch for Xcel Energy landed him several different positions with the Ministry of Energy (SENER) and the Federal Electricity Commission (CFE), Mexico’s national utility. In 2011, he took a position as general director of generation, conduction and energy transformation with SENER, just as the push for electric reform, driven by the need for more efficient generation and lower prices, began in 2012.
“Very good timing. I thought it would happen six years later than it did,” Pavlovic said, referring to Mexico’s single, six-year presidential terms. “When I was dreaming of this, I didn’t think I’d be in government writing the rules. I thought I’d be on the sidelines, maybe in some private company sending suggestions that would mostly be ignored. Being in the middle of the process was better than anything I dreamed of.”
Big Designs, Slow Progress
Anxious to make the sector “more efficient and reduce costs,” Pavlovic said he and the market-design team borrowed textbook principles and elements from RTOs in the U.S. “We wanted a Day 2 settlements market at least. We wanted nodal prices,” he said. “We followed MISO and PJM in letting the system operators make the commitment decisions.”
Mexico began its incremental rollout of market reforms in 2014, but progress has been slow and halting. The financial transmission rights market has been delayed until 2019, frustrating participants who have complained about a lack of liquidity. The first midterm capacity auction in February cleared only one transaction, Enel’s 50-MW purchase from Spain’s Global Power Generation, leading one observer to say, “Whenever a bilateral agreement is signed, [the market] has a party.”
Market participants have complained about the market’s lack of transparency, exemplified by the confusion around transmission retail rates that led to a new, transitory methodology. Rate increases will be phased in through 2018 while a permanent solution is developed.
Some market participants have given themselves six months to see how the market shakes out and “grows legs,” as one player said during the recent Gulf Coast Power Association market conference in Mexico City, before jumping headlong into the market.
Asked about his reaction to how the market has developed, Pavlovic said he believes the market design “was mostly efficient.”
“A perfectionist can always find things that could have been done better, but in the big picture, I was happy,” he said. “The way the powers were separated among the government authorities was right. The implementation has had some very good early successes with the short-term market, the auctions, the capacity market. I was pretty satisfied, but always conscious of things not going as well as I had hoped.”
| Bravos Energia
Pavlovic pointed out that several market pieces — FTRs, virtual trading and a fully functional real-time market — still need to be implemented.
“Most of the [market’s] weaknesses are caused by the environment the market operates in,” he said. “How many participants are there? What kind of positions do those participants need to take?”
Pavlovic said many market participants can’t take large positions because of the lack of private generation assets in operation and uncertainty over regulated transmission rates.
“A lot of auction projects are under construction, but the market suffers from the lack of a dynamic retail market,” he said. “It’s a chain of cause and effect. With no retail market, the speed of investments is slowed down.”
A New Wave
When Pavlovic rejoined the private sector, his biggest worry was whether the market reform’s unbundling of CFE’s generation, distribution and retail businesses would hold. It hasn’t. During his GCPA keynote, he said the former monopoly continues to combine the financial accounting for its several subsidiaries.
“It’s not turning out to be as strong a separation as we had hoped for,” Pavlovic said. “They are the big player in the market, but I don’t think they have built the systems or generated the knowledge to be able to use the market as a tool to hedge their risks. If they were using those markets, then there would be a lot more liquidity, a lot more price discovery, and that would bring in a lot more participation from private companies.”
Complicating matters is the country’s July 1 presidential election. With presidents and their administrations limited to a single-six year term, governmental work naturally slows to a crawl in the months before the election. This year, populist Andres Manuel Lopez Obrador holds a 26-point lead over his two opponents from the traditional ruling parties.
Obrador’s energy platform includes increasing hydroelectric generation and preventing the retirement of 16 GW of thermal generation, without allowing their modernization, repowering or conversion to cheaper fuels. He is also calling for a million small renewable plants for residential users and the services sector.
“It’s dangerous, because those [hydro and thermal] investments could crowd out more productive and efficient investment from the private sector,” Pavlovic said. “The rest of his proposals are not going to have a big impact on the market. He’s not talking about undoing the power market, he’s not talking about the states taking over private assets. It doesn’t look like there’s a very big downside to be worried about.”
Pavlovic’s greater worry is about the industry’s regulation. The Energy Regulatory Commission (CRE) consists of seven commissioners serving staggered seven-year terms. Every New Year’s Day, a new commissioner joins.
“The big risk is whether they will nominate competent technical leaders to regulate the electrical sector,” Pavlovic said. “There’s still a lot of work to be done, in the regulation and implementation of the market. You need competent technocrats and technical leaders in the power sector.”
Still, Pavlovic draws hope from the growing number of participants in the market’s capacity auction.
“There is a new wave that will come in,” he said during the GCPA conference. “I think the market will continue to get deeper and help us exercise influence over the policy.”
Electric reliability in New York state declined last year compared to 2016 because of a severe wind storm in March, Department of Public Service staff told the Public Service Commission on Thursday.
Excluding weather-related outages, overall interruption frequency — the main metric DPS staff use — improved slightly, according to their annual report on reliability. However, some service areas saw longer interruptions, and others saw an uptick in tree-related outages compared to other causes (18-E-0153).
A severe wind storm in early March 2017 downed distribution lines in Rochester, N.Y. | NY PSC
But while it led to record wind generation in NYISO, the March storm, with gusts up to 70 mph, easily downed distribution lines in upstate New York. (See “NYISO Sets Wind Energy Record in March,” NYISO Management Committee Briefs.)
The three upstate utilities — National Grid, Rochester Gas & Electric and New York State Electric and Gas — collectively reported about 284,000 outages in their service territories as a result of the storm. A DPS investigation found that RG&E and NYSEG did not follow their emergency response plans, leading to longer outage times, and the utilities have filed a joint proposal with the PSC to settle staff’s alleged violations for $3.9 million.
Staff expect reliability to only worsen because of severe weather. “The weather events dominating the headlines recently indicate weather patterns are producing more frequent and powerful events,” they said. “As a result, this reliability category is expected to decline given the number of significant weather events that have occurred in 2018.”
New York has already experienced several unusually powerful storms this year, including January’s bomb cyclone, a series of March nor’easters, a spate of severe thunderstorms on May 15 and a tornado on May 3.
Pipeline Safety Efforts Improve
Meanwhile, pipeline safety improved overall last year, as local distribution companies improved their damage prevention, emergency response and leak management efforts (18-G-0260). The number of reported damages to natural gas pipelines in the state decreased slightly, from 1,565 to 1,562.
The DPS measures LDCs’ damage prevention by tallying up damages resulting from certain actions, such as mismarking areas or contractors failing to notify LDCs of excavation activities. By this standard, damage prevention improved by 22.5%.
The LDCs’ ability to respond to emergencies within 30, 60 and 90 minutes all improved, staff said. Additionally, the utilities reduced their backlog of leaks by 2,354, or 13.4%.
Staff also presented reports on electricity safety (18-E-0279) and customer service (18-M-0267).
Separately, as part of its consent agenda, the PSC approved a $1.98 million settlement by National Grid for a 2015 pipeline explosion on Long Island that destroyed a house and severely injured two people inside (15-G-0298). A staff investigation found the company failed to disconnect gas service to the house after a resident request.
Central Hudson Rate Increase Lowered; Burman Dissents
The PSC voted 3-1 to approve a $36.4 million electric and gas rate increase for Central Hudson Gas & Electric, 57% below what the utility initially requested (17-E-0459, 17-G-0460).
Empire State Plaza, where the New York PSC meets
Under a joint proposal with DPS staff, Central Hudson agreed to increase its rates over three years, instead of all at once. Eligible low-income customers will also see a 65% rate decrease under the plan.
“The progressive plan that was adopted — endorsed with complete stakeholder support by environmental groups, large business customers and the largest municipality in the region — includes a nation-leading affordability policy that substantially lowers bills for most low-income customers,” Chair John B. Rhodes said in a statement.
Commissioner Diane Burman spoke for more than half an hour explaining the many reasons for her “clear ‘no’ vote.” But she said the single issue that tipped the scales for her was a $264 credit to customers who install geothermal HVAC systems, which the commission says are more energy efficient and emit less carbon.
“We always say that we’re fuel-neutral [and] technology-neutral … here, we would not be,” Burman said. “And there’s no explanation to me why except that it was agreed to in the joint proposal.”
CARMEL, Ind. — MISO has called off a proposal to rely on data from its load-serving entities to compile its own long-term load forecast, stakeholders learned last week.
The RTO will instead continue to use independent load forecasts (ILFs) prepared by Purdue University’s State Utility Forecasting Group but with a twist: It will now order four versions of the forecast, each tailored to one of the futures used to inform MISO’s annual Transmission Expansion Plan.
“After careful consideration of the comments and proposals by stakeholders, MISO will begin to use the independent load forecasts to develop futures-specific load and energy forecasts for MTEP 20 and beyond,” John Lawhorn, MISO senior director of policy and economic studies, told stakeholders at a June 13 Planning Advisory Committee meeting.
Lawhorn said “consistency and clarity, not necessarily increased precision,” prompted the decision, and he stressed that MISO will continue to use LSE forecasts to plan for resource adequacy.
The expanded independent forecast is “for transmission planning purposes only,” Lawhorn said.
“I know we’ve been talking about the ILF for the past five years, with more discussion in the past eight months,” he said.
The change to an LSE-based forecast would have required MISO’s 140-plus LSEs to annually assemble four different 20-year load forecasts to fit with each of the MTEP futures, an unpopular proposition with many stakeholders. (See Advisory Committee Steps up Criticism of MISO Forecast Plan.)
The LSEs themselves were mixed over whether they would be able produce their own 20-year forecasts. An April survey generating responses from one-third of LSEs representing about two-thirds of load showed that LSEs estimated the costs of putting together forecasts would be anywhere from “minimal” to a few hundred thousand dollars, Lawhorn said.
“Costs were all over the map from that perspective, whether they already had a load forecasting group or not,” Lawhorn said in April.
Stakeholders at last week’s meeting asked whether MISO has a plan to monitor its ILFs and compare them with actual loads after the fact.
Lawhorn said although it’s difficult for MISO to line up all variables to compare forecasted load to actual load, Purdue’s own analysis has shown its forecasts “trend well” with actual load in the long term.
Other stakeholders expressed concerns that MISO had no specific plan to hold the ILF to a standard of accuracy.
WPPI Energy’s Steve Leovy said he would have liked MISO to hold more discussion with stakeholders before deciding on the ILF, adding that a single survey of LSEs was inadequate to collect opinions. Organization of MISO States Executive Director Tanya Paslawski said she was likewise concerned about MISO’s short comment period and scant communication about its decision. She noted she would take her concerns to her Board of Directors.
‘Post-capacity’ Planning
MISO said it makes sense for the ILF to be tailored to MTEP futures because energy usage is increasingly driving transmission planning, shifting away from capacity-based planning that relies on an annual system peak. The RTO says it will increasingly experience peaks that can occur during any hour of the year.
“It’s a shift that we’re seeing from a capacity-planning paradigm to an energy-planning paradigm … as we move to more facilities that are small and local. Energy delivery is becoming the driver of a robust transmission system. Moving energy around the system becomes more important as the resource mix changes,” Lawhorn said, pointing to MISO’s 93-GW interconnection queue, which includes 80 GW of potential renewable sources. “This is portending to be a major shift in our system.”
MILFORD, Mass. — ISO-NE forecasts a net installed capacity requirement (ICR) value of 34,000 MW for capacity commitment period 2023/24, a 275-MW increase from the 33,725 used in February’s Forward Capacity Auction 12 for 2021/22, officials told the Planning Advisory Committee on Wednesday.
| ISO-NE
The net ICR is forecast to rise by 200-MW increments each period to 34,800 MW for 2027/28 with capacity margins dropping to 15% from 16.7% for 2021/22.
The forecast uses the same capacity and transmission transfer capability assumptions used to develop ICR values for FCA 12 but with the 2018–2027 Forecast Report of Capacity, Energy, Loads and Transmission (2018 CELT) load forecast. The FCA 12 values were based on the 2017 CELT, system planning engineer Manasa Kotha told the PAC. (See ISO-NE Capacity Prices Hit 5-Year Low.)
The RTO modeled three capacity zones for FCA 12: the Southeast New England (SENE) import-constrained capacity zone comprising Northeast Massachusetts (NEMA)/Boston, Southeast Massachusetts (SEMA) and Rhode Island; the Northern New England (NNE) export-constrained capacity zone comprising Maine, New Hampshire and Vermont; and the Rest-of-Pool capacity zone comprising Connecticut and Western/Central Massachusetts.
Comparisons of the 2018 and 2017 CELT load forecasts show that while overall New England load decreased, load in the SENE sub-areas has increased, as it did last year, Kotha said.
Comparison of 2017 and 2018 Net ICR Forecasts (MW) | ISO-NE
The increase is attributable to the Massachusetts economy continuing to grow faster relative to the other New England states, she said.
As part of its review of ICR assumptions for Operating Procedure No. 4 conditions (action during a capacity deficiency), the RTO has proposed using 700 MW of minimum operating reserves in the ICR model, an increase of 500 MW over the long-term assumption of 200 MW previously used. The new 700-MW assumption will be used in FCA 13 ICR calculations, Kotha said.
Future Locational Reserve Needs
ISO-NE foresees reserve needs in NEMA/Boston to be in the range of 250 to 700 MW for summer 2019 and 250 to 400 MW for winter 2019, Fei Zeng, technical manager for resource adequacy, told the PAC.
The RTO developed future representative operating reserve needs for the current reserve zones in NEMA/Boston, Southwest Connecticut (SWCT) and Greater Connecticut for summer and winter for study period 2018-2022. The actual requirements reported for 2018 are based on historical data of the last two years.
Investment of New England transmission reliability projects by status through 2022 (numbers represent project quantities) | ISO-NE
The forecasts did not consider the impacts of Footprint Power’s new 674-MW combined cycle power plant in Salem, Mass., “which when it goes into service by the end of the year is expected to have an impact on the following year’s calculations,” Zeng said.
Together with upgrades in the greater Boston area, the new Salem Harbor Station will help eliminate the local reserve needs for the study period, Zeng said.
In SWCT, the grid operator expects Competitive Power Ventures’ Towantic Energy Center, which began generating last month, to help reduce local reserve needs to a minimum level for summer 2019. With the assumed addition of Bridgeport Harbor 5, and the SWCT transmission upgrades, forward reserve requirements are expected to be zero for the remainder of the study period. (See related story, CPV: Subsidies — not Gas Shortages — Challenge for New Plants.)
CEII Presentations Describe Aging Infrastructure
The PAC heard five presentations on regional transmission infrastructure, which collectively described the rust in New England’s rustbelt. All five presentations were classified as containing critical energy/electric infrastructure information (CEII).
However, one stakeholder pointed out that much of what the classified material detailed would be visible to any interested commuter in the region. The needed replacements range from vintage control room equipment to brown glass insulators to replacing rusting towers.
Pradip Vijayan, ISO-NE senior engineer for transmission planning, updated the PAC on results from the SWCT 2027 needs assessment, as well as one project related to an older needs assessment for Greater Hartford/Central Connecticut.
Christopher Malone, Avangrid manager for Connecticut transmission planning, presented railroad corridor transmission line asset conditions. Maintenance of century-old catenary structures over the railroad is complicated by railroad control of 22-kV feeder/signal conductors.
Eversource Energy system planning manager Shaun Moran presented on challenges with the infrastructure in Eastern Massachusetts that carries much of the load for Cape Cod.
Kelly Csizmesia presented on behalf of National Grid’s New England Power unit, which operates transmission facilities in every regional state except Connecticut.
Transmission Projects and Asset Condition Update
Jon Breard, ISO-NE associate engineer for transmission planning, presented an update on the Regional System Plan regarding transmission projects and asset conditions, noting that seven new transmission projects totaling $146.8 million have been placed in service since the last update in March.
The RTO estimates about $1.74 billion in active reliability projects are underway now, compared to $1.9 billion in March.
Regarding asset conditions, the RTO reported one new project (the $6.3 million replacement of the Montville 16X transformer in Connecticut), and three projects placed in service since the last update in March, including: the installation of two 40-MVAR reactors on the Scobie 115-kV bus in New Hampshire ($4.7 million); replacement of the Salem Harbor Substation 115-kV oil circuit breaker ($4.6 million); and the 1231/1242 structure replacement project in Massachusetts ($8 million).
MILFORD, Mass. — Only six of 32 interconnection requests studied by ISO-NE in its initial test of its new queue clustering methodology have moved on to the next stage of the process, all of them in western Maine.
The six interconnection requests, totaling 691 MW, will be included in the RTO’s first cluster system impact study (SIS), Al McBride, director of transmission strategy and services, told the Planning Advisory Committee last week.
ISO-NE implemented the clustering methodology to address the queue backlog in Maine, where more than 5,800 MW of proposed resources, mostly wind, want to connect to the grid.
Bingham Wind Project | NovatusEnergy
The process allows for two or more interconnection requests in the same area to be analyzed together and to share costs for required transmission upgrades when none of the requests can interconnect without the use of common new infrastructure rated at 115 kV AC or HVDC.
The first Maine Resource Integration Study (MRIS) concluded that the RTO could connect nine Northern Maine requests totaling 1,118 MW and 23 western Maine requests totaling 777 MW with about $1.83 billion in transmission upgrades. The upgrades included a second 345-kV Coopers Mill-Maine Yankee 392 line — which both clusters required — at a cost of $108 million.
With constraints on the system, “we found ourselves hitting a ceiling of around 1,800 MW” in interconnection requests able to be accommodated, “which is a significant addition to the Maine transmission system,” McBride said.
ISO-NE Maine Study | ISO-NE
Projects had 30 days after posting of the MRIS on March 12 to inform ISO-NE of their intention to move on to the clustered SIS process.
None of the Northern cluster projects — whose upgrades would have totaled $1.36 billion, including the second 392 line — agreed to proceed.
Seven of the 23 western Maine requesters sought to be included in the cluster SIS, but one, for 1,200 MW, was not permitted because it exceeded the capacity of the “cluster-enabling transmission upgrades.” It will be studied separately.
Costs of the upgrades for the western projects, including the second 392 line, were estimated at $575.5 million. The other upgrades include a new 345-kV line from a new substation near Johnson Mountain to the existing 345-kV substation at Larrabee Road.
Second Study Planned
The RTO is planning a second MRIS to evaluate upgrades needed to accommodate an additional 22 interconnection requests, including about 1,350 MW in Somerset and Franklin counties and about 2,300 MW in Aroostook and Penobscot counties.
McBride said the study will consider new HVDC transmission connecting to the southern part of the RTO’s system, connecting either radially to proposed generation or to the existing network.
The RTO asked stakeholders to email feedback on the proposed study scope to PACmatters@iso-ne.com by July 13.
It hopes to complete the study within 12 months.
“We would be very reluctant to study major transmission proposals, from $500 million to $1 billion, that provide only minimal interconnection capability,” McBride said.
