A public advocacy group is urging the Commodity Futures Trading Commission to start overseeing PJM’s embattled financial transmission rights market after a massive default that could saddle stakeholders with more than $180 million in costs.
Public Citizen Energy Program Director Tyson Slocum made the request both in a letter to CFTC Chairman J. Christopher Giancarlo and a filing in the docket of a DC Energy complaint before FERC seeking immediate changes to PJM’s credit requirement (EL18-170).
In the complaint, DC Energy seeks to fast-track changes to PJM’s FTR credit policy to forestall what has become a historic portfolio default by GreenHat Energy, causing substantial tension between the RTO and its stakeholders and prompting an investigation by its Board of Managers. (See “GreenHat Default Update,” PJM Market Implementation Committee Briefs: Nov. 7, 2018.)
On Sept. 25, FERC accepted a PJM filing to impose a 10-cent/MWh minimum monthly requirement on FTR portfolios (ER18-2090) and established a paper hearing in the complaint “to determine whether the Tariff is unjust and unreasonable even with PJM’s new Tariff revision in place.” Comments on the hearing were due Nov. 9.
CFTC Exemption
Slocum argues that CFTC’s 2013 decision to exempt FTRs from its jurisdiction was made on the condition that it could “suspend, terminate or otherwise modify or restrict” its order as conditions warranted. GreenHat’s default coupled with PJM’s subsequent handling and FERC’s inaction means CFTC must get involved, according to Slocum.
“It appears PJM’s catastrophic failure to properly oversee its FTR market, combined with PJM’s misrepresentation of key facts in its [request for the CFTC exemption], should result in the CFTC suspending the exemption it granted,” he wrote. “Furthermore, FERC’s refusal to take minimum steps to assert regulatory control over the situation forces Public Citizen to conclude that only the CFTC is in a position to protect consumers from abuses in FTR markets going forward.”
Calling PJM’s staff “incompetent” and “clearly unprepared and overmatched” to handle FTRs, Slocum said any FERC effort to revise credit requirements “will be meaningless” under PJM’s “lax” oversight, which is “by design.” He noted several examples of what critics have seen as PJM’s mishandling of the situation, including failing to increase credit requirements and apparent bungling attempts to seek additional collateral from GreenHat.
Slocum said the conditions of the CFTC exemption appear to have been broken on several counts. First, Public Citizen could find no clear evidence that PJM’s Independent Market Monitor was “directly involved” in the negotiations seeking additional collateral as CFTC’s order requires. Additionally, GreenHat was purely a financial trader that could not be categorized as among the “commercial participants that are in the business of generating, transmitting and distributing electric energy” that the exemption allows.
No Transparency
Slocum also pointed out that while companies seeking to participate in PJM’s competitive energy markets must seek FERC approval to do so and subject themselves to public scrutiny and comment, FTR market participants need only register with the RTO.
“PJM does not offer public notice and comment of FTR applications, and it does not condition their approval by first offering the public an opportunity to inspect the applications,” he wrote. “Had Greenhat been required to submit its ownership structure to public notice and comment at FERC, then groups like Public Citizen would have had an opportunity to raise serious concerns about a firm owned by two former JP Morgan traders directly implicated in one of the most brazen market manipulation schemes in history obtaining authorization to trade FTRs.” (See GreenHat: (Some of) the Rest of the Story.)
Slocum noted that another former trader in PJM’s FTR markets, Tokamak Energy Partners, was founded by the head of power trading for Deutsche Bank during the period the company was caught manipulating the California power market.
“Who knows how many frauds and market manipulators have set up shop to trade FTRs. FERC doesn’t know, because FERC effectively has ceded regulatory jurisdiction to PJM, and PJM operates its FTR market with little to no public transparency,” he wrote.
A PJM spokesperson confirmed that the RTO will be filing a response to the Public Citizen complaint, but the content of that response has not been finalized.
TORONTO — The Association of Power Producers of Ontario’s annual conference attracted about 300 people last week, a sharp drop from past years, when more than 500 attended.
But things are looking up, APPrO President Dave Butters told the gathering. After “a couple of difficult years” in which the group cut its office space in half to save $50,000 annually, he said the group collected a record $830,000 in membership revenue in 2018.
Butters said the group may consider a name change under a business plan it will unveil in about a month to broaden its membership. “We want to be an organization that is broader and wider than just centralized generation,” he said. “We see [distributed energy resources], storage — all these things are potentially opportunities.”
Here are some of the highlights of what we heard.
Alberta also Adding Capacity Market
The Alberta Electric System Operator (AESO) plans to add a capacity auction to its energy-only market in late 2019, with the market operational by 2021. AESO said it is making the change to improve reliability, increase price stability, give generators greater revenue certainty and allow market forces to drive innovation and cost discipline.
AESO has proposed a one-year term for its capacity market, although that could change, said Evan Bahry, executive director of the Independent Power Producers Society of Alberta (IPPSA).
Bahry said Alberta’s market is being challenged by the province’s plan to eliminate coal-fired generation and add 5,000 MW of renewables by 2030. “We’re a thermal market, reliant on coal and natural gas historically; very little hydro,” he said.
The industry also must deal with “a lot of agencies in our marketplace, all of which have their own independent mandates,” he said.
“We in our business make 20-, 30-year investments. Billions of dollars are required to replace retiring assets and to meet future load growth. This requires coherence, requires stability,” Bahry said. “We’re [seeing] greater change … now than we’ve seen in the last 20 years. That’s a lot for investors to digest.”
Harsh Critique from TransAlta Boss
Dawn Farrell, CEO of Calgary-based TransAlta, offered a harsh critique of policymakers and customers.
Of consumers: “They want electricity to be cheap. They don’t want it to be affordable, and they don’t want it to be reasonably priced. They want it cheap. They’ll pay a lot of money for cable, they’ll pay a lot of money for their phones and data streaming and for movies.
Of Alberta’s market: “The new market in Alberta has 500 rules. That’s not a market. Markets don’t have 500 rules.”
She said policymakers should take a lesson from the large regional transmission grids in the U.S. “Electricity flows wherever it wants to flow, and you get the benefits of the economies of scale there. And they get the benefits of the different resources in the different jurisdictions. You think about Canada and for some reason there’s these invisible lines in between the provinces, which are just political constructs.”
She said the failure to take advantage of transmission dooms innovative ideas, such as the proposed pump storage project at TransAlta’s 355-MW Brazeau hydroelectric plant. “It’s too big for Alberta. … It would be great for Alberta and Saskatchewan.”
“As a country,” she lamented, “we do not have our best interests at heart. We do not think about competitiveness.”
New England Faces Another Tight Winter
Robert Ethier, vice president of market operations for ISO-NE, discussed the RTO’s challenges with insufficient winter gas supplies and states’ reluctance to allow new pipelines or transmission. Asked about a proposed transmission line from Quebec’s hydro resources, he said, “We’d love to have it.”
He noted the RTO is seeking a reliability-must-run designation for Exelon’s Mystic generating station, which has access to LNG storage. The proposal, which is pending before FERC, “has not gone over very well in New England,” he said. “It’s going to be very expensive.” (See FERC Advances Mystic Cost-of-Service Agreement.)
He said the RTO is “trying to strike a balance” in shifting to renewables, noting that solar generation, with a capacity factor of less than 5%, “doesn’t help at all” in meeting winter needs.
“Our system is not ready to have these old coal and oil units retire,” he said.
Dan Dolan, president of the New England Power Generators Association, said that although gas prices spiked during last January’s deep freeze, the “system … worked.”
“In the face of the longest, deepest cold snap in over 100 years, with tremendous outages due to transmission line failures, we didn’t have a single reliability shortfall. And we saw tremendous responses in investment and performance from the generators on the system optimizing the fuel infrastructure that does exist,” Dolan said.
He said he was concerned about the market providing enough revenue to prevent the retirement of coal and oil generators needed during winter peaks. He said state-contracted resources are projected to grow from the current 17% of the market today to 60% within a decade.
“The question is, is the existing market design sufficient to maintain this half-pregnant status of a tremendous portion of the market being merchant with the rest of the market … made up of resources that are indifferent to that market price? And I would argue that the answer is no, on both the energy and capacity end.”
Storage vs. Peakers
It’s a question that comes up often at energy conferences: When will storage be versatile and cheap enough to compete with natural gas peakers?
Not soon in the frozen north, speakers said. Despite declining prices, solar/storage combinations cannot help New England in winter, Dolan said. “It’s awfully hard for solar to perform when it’s under a foot and a half of snow,” he said, adding that current battery storage can only fill gaps for hours, not days.
Bahry said storage will struggle to compete as long as natural gas prices remain cheap. “If we’re dealing with gas a buck a [gigajoule], nothing competes … with dispatchable peakers in that pricing environment,” he said.
Nuclear Refurbishments
Jeffrey Lyash, CEO of Ontario Power Generation, gave an update on the status of his company’s $12.8 billion ($9.7 billion USD) refurbishment of the Darlington nuclear plant, calling it “Canada’s largest clean energy program.”
Darlington is a CANDU (Canada deuterium uranium) pressurized heavy-water reactor that has been producing about 20% of the province’s electricity since the early 1990s. Unit 2 was taken offline in 2016, beginning what is expected to be a 10-year project involving all four units. The refurbishment — which Lyash said is far more extensive than projects to extend the lives of U.S. pressurized water reactors and boiling water reactors — is expected to allow the plant to run until 2055.
He said he feels the “weight of responsibility” to deliver the project on time and on budget because Unit 2 is the first of 10 reactors, including six at the Bruce Power plant, scheduled for retrofits. OPG, which is owned by the province, is sharing best practices on the renovations with privately owned Bruce Power, which plans to spend $13 billion.
“The future of the nuclear industry hinges on the success of this project,” Lyash said.
The Future of LDCs
Gordon Kaiser, CEO of Alberta’s Market Surveillance Administrator and former vice chair of the Ontario Energy Board, had a provocative answer in a panel on what local distribution companies will look like in 2025.
“They won’t exist,” he said. Instead they will morph into larger, integrated utilities with generation assets, he predicted. Municipal ownership of LDCs will decline because of the need for professional boards of directors to manage the investments. They will replace boards of municipal “councilors looking for hockey tickets,” he said.
Kaiser’s vision was not shared by other panelists.
Moderator David McFadden, chair of Toronto Hydro, said municipal utilities are not ready to sell yet.
Toronto Hydro CEO Anthony Haines said LDCs will be even more important in the future.
Former FERC Chair Joseph T. Kelliher, executive vice president of NextEra Energy, said he didn’t see such a shift happening in the U.S. either because of the large number of municipal utilities and political obstacles to mergers. He acknowledged, however, that some munis are selling their transmission to escape liability for NERC reliability standards.
Kelliher said many U.S. utilities remain inattentive to controlling costs despite earnings pressure and flat energy demand. Cost-of-service regulation is of limited use, he said. “I’ve always thought it was misnamed, because cost-of-service regulation really is profit-level regulation, because it’s the rate of return that’s regulated, not really the cost,” he said. “Cost-of-service regulation is very ineffective in weeding out routine excessive costs.”
“Competition hasn’t really fully affected LDCs,” he continued. “It’s remarkable how many utilities are not attentive to controlling costs.”
Complexity
Jason Chee-Aloy, managing director at consulting firm Power Advisory, said he senses stakeholder fatigue after more than a decade of competition and repeated changes in market design.
“I do think that stakeholders in general — we’re a firm that’s all over North America — are starting to throw their hands up in the sense that this stuff is getting really, really complicated,” he said.
Possible Penalty for External Resources Failing in SRE
NYISO is considering penalizing external resources that fail to perform when dispatched following a supplemental resource evaluation (SRE), Rana Mukerji, senior vice president for market structures, told the Business Issues Committee on Wednesday.
The ISO presented the proposal — part of an effort to clarify the minimum deliverability requirements for external capacity from PJM — at the joint Oct. 18 meeting of the ICAP and Market Issues working groups.
It would penalize an external capacity resource selected for an SRE that fails to bid in a way that will get it scheduled, is not available and operating to provide the capacity sold for the duration of the SRE call, or is unable to deliver its energy from its control area to the New York Control Area border.
The penalty would be equal to 1.5 times the applicable spot price multiplied by the number of megawatts of shortfall and the percentage of the SRE call hours that a supplier fails to respond. It would not apply if the resource is in a forced outage during an SRE call; such an instance would instead impact its equivalent forced outage rate (EFORd).
Mukerji, who mentioned the issue during his monthly Broader Regional Market report, said the ISO will return to future working groups to continue stakeholder discussions.
He also updated the BIC on a complaint filed in July with FERC by the Independent Power Producers of New York seeking to bar the ISO from allowing PJM resources to sell installed capacity into Zone J using unforced capacity deliverability rights facilities (EL18-189).
NYISO filed an answer to IPPNY on Sept. 20, he said. The ISO argued that IPPNY mischaracterized its position and made inaccurate claims regarding alleged reliability threats.
Con Edison Newtown substation | Con Edison
Approves T&D Manual Updates
The BIC unanimously approved Transmission and Distribution Manual updates in conformance with FERC Order 831 on offer caps.
The changes replace “$1,000/MWh” with “$2,000/MWh” in two locations in the manual that refer to day-ahead and real-time exports not designated as a coordinated transaction scheduling interface bid, said Padam Singh, senior energy market business analyst.
Order 831 requires grid operators to cap a resource’s incremental energy offer at the higher of $1,000/MWh or its verified cost-based incremental energy offer, and cap verified cost-based incremental energy offers at $2,000/MWh. (See FERC Grants NYISO ‘Cold Snap’ Offer Cap Waiver.)
Automate ICAP Import Rights
The BIC unanimously approved changes to the Installed Capacity Manual for implementation beginning in the Summer 2019 Capability Period.
ICAP Market Operations Engineer Joe Nieminski said the manual changes include revised definitions, a request period for first come, first served (FCFS) import rights, and language regarding buyer confirmation and supporting documents.
Beginning with the summer 2019 capability period, NYISO plans to automate the FCFS import rights process to replace the fax process; replace market participants’ obligations to provide supporting bilateral contracts with an automated bilateral confirmation process; and automate steps now performed manually by ISO staff.
Day-ahead Demand Response Program Manual Updates
The BIC also approved updates to the day-ahead demand response program (DADRP) manual to comply with FERC Order 745, as presented by Sarthak Gupta, associate distributed resources operations engineer.
NYISO last updated the DADRP manual in 2003.
The changes represent an overall refresh, removing obsolete language and replacing redundant language with relevant Tariff and manual references, Gupta said.
NYSEG transmission | NYSEG
BIC Elects Chris Wentlent Vice Chair
The BIC elected Chris Wentlent to a one-year term as committee vice chair. Formerly Exelon’s director of state governmental affairs in New York until January 2018, Wentlent now represents the Municipal Electric Utilities Association of New York State (MEUA), which represents municipal utilities and rural electric cooperatives.
MEUA is a member of the Public Power and Environmental Sector.
LBMPs Down 7% in October
NYISO locational-based marginal prices averaged $35.85/MWh in October, down 7% from $38.70/MWh in September, but higher than $28.35/MWh in the same month a year ago, Mukerji said in his monthly operations report. Day-ahead and real-time, load-weighted LBMPs came in lower compared to September.
Year-to-date monthly energy prices averaged $45.03/MWh through October, a 29% increase from a year ago. October’s average sendout was 399 GWh/day in October, lower than 458 GWh/day in September 2018 and higher than 398 GWh/day in the same month last year.
Transco Z6 hub natural gas prices for the month averaged $2.91/MMBtu, up from $2.75/MMBtu in September and up 23.2% from a year ago.
Distillate prices climbed slightly compared to the previous month but were up 32.4% year-over-year. Jet Kerosene Gulf Coast and Ultra Low Sulfur No. 2 Diesel NY Harbor averaged $16.65/MMBtu and $16.66/MMBtu, respectively.
Total uplift costs and uplift per megawatt-hour came in lower than September, with the ISO’s 27-cent/MWh local reliability share in October down from 37 cents the previous month, while the statewide share dropped from -48 cents to -56 cents. Uplift, excluding the ISO’s cost of operations, was -30 cents/MWh, lower than -11 cents in September.
Thunderstorm alert costs in New York City were 75 cents/MWh, more than double the 33 cents in September.
MISO will need to take significant steps to reinforce its grid to handle 40% renewable penetration, according to RTO findings released last week.
At that share of renewables in its generation mix, MISO will experience a sharp increase in grid complexity in terms of resource adequacy, steady state operating reliability and hourly energy adequacy. The changes will require the RTO to roll out mitigating measures that could include buildout of new transmission, the study found.
“Interim results indicate integration complexity increasing sharply from 30% to 40% renewable penetration,” Policy Studies Manager Jordan Bakke said.
The findings are the latest in MISO’s yearslong renewable integration impact assessments, which seek to determine what volume of renewables it can incorporate into its footprint before the integration becomes “significantly” complex. The RTO is in phase two of the three-phase study.
In spring, MISO published study results showing that increased renewable integration, especially solar generation, will shift peak load to evening hours, with a spikier but shorter daily loss-of-load risk. (See MISO Renewable Study Predicts Later Peak, Narrower LOLE Risk.)
“We’re seeing that as renewable penetration increases, so do the operational complexities,” Bakke said.
The RTO now says that the variability swings resulting from 40% renewables could increase curtailment of renewables to about 18.2% of intervals. Bakke said various mitigating measures could halve curtailments.
MISO also said that, under current conditions, an overall capacity mix consisting of 40% renewable resources will translate into actual renewable penetration of just 34.7%, which could increase to 38.5% if the RTO introduces additional measures, including new transmission. Renewables at 40% could serve 41.7% of near-peak load, 67% of light load and 81.3% of load during peak conditions for renewables.
The MISO footprint at 10% and 40% renewable penetration | MISO
After studying about 11,300 new transmission project candidates, Bakke said MISO identified about 80 that would be cost-effective and allow it to “utilize the diverse variable resources.”
Veriquest’s David Harlan said MISO’s study did not demonstrate how capacity from gas and coal generation could help facilitate renewable expansion. He said the RTO may want to consider whether its markets are providing the right price incentives so coal and gas generation stay in the market.
But Bakke said the increasing variability resulting from a 40% renewable penetration can be addressed by ramping from its online conventional generators.
Bakke said MISO’s study shows the footprint will continue to need conventional generation. He said even though average ramping needs change slightly at a 40% renewable mix, the remaining conventional generators will have more pronounced requirements, needing to provide greater volumes of up and down ramping.
As MISO nears a mix with 50% renewables, he said, it will experience more renewable energy available than needed for load at certain times of the year, resulting in a “net negative” load.
MISO will hold a workshop on the assessment Nov. 28, where stakeholders will discuss the preliminary impacts of increasing levels of renewable penetration in more detail.
CARMEL, Ind. — MISO’s membership has elected to keep Directors Phyllis Currie and Mark Johnson while also approving the somewhat controversial installment of current Minnesota Public Utilities Commission Chair Nancy Lange.
MISO Senior Vice President and Board Secretary Stephen Kozey announced the Board of Directors elections results at a Nov. 15 Informational Forum. Voting opened Sept. 27 and concluded Nov. 2.
Each candidate received a majority of membership votes, the RTO revealed. Kozey said the eballot performed “soundly” with no outages from election vendor VoteNet.
“It was not hacked,” Kozey joked, a tongue-in-cheek reference to the recent fear of cyberattacks on the midterm elections.
Kozey said 96 of 139 members voted, well above the 35-member quorum required.
Members voted Lange to the board despite concern by some stakeholders over a sitting commissioner being appointed to the oversight body. Stakeholders said MISO should consider requiring the same one-year moratorium for regulators in the RTO’s states that it requires of directors coming from member companies. MISO’s bylaws require a yearlong cooling period for “directors, officers or employees of a member, user or an affiliate of a member or user.” (See MISO Members Uneasy over Board Nomination.)
This is the first time the RTO has elected either a sitting commissioner or a commissioner from one of the states in its footprint to the board.
Stakeholders noted that Lange made decisions about the grid on behalf of Minnesota customers and utilities up until her election.
Lange will fill the seat vacated by retiring Director Michael Curran, who has served on MISO’s board since 2007. The trio will begin their three-year terms on Jan. 1. Lange’s term at the Minnesota commission doesn’t expire until Jan. 7. Kozey has said Lange will avoid overlap by resigning her post at the regulatory agency early.
Kozey said MISO has requested that its board address whether the moratorium should apply to regulators.
“Because of the issue raised by stakeholders, we’ve asked the Corporate Governance and Strategic Planning Committee [of the Board of Directors] that the applicability of the stay-out be an item that they address,” Kozey said.
The RTO’s Advisory Committee will also discuss the issue at its Dec. 6 meeting during Board Week.
In a release, CEO John Bear said MISO is “fortunate to have an exceptional depth of experience across our Board of Directors.”
After reporting on election results, Kozey announced that he would be retiring from MISO by the end of the year.
“Thank you for putting up with me and my attempts at humor over the years,” Kozey said, choking up. Kozey was one of the RTO’s 21 original employees in 2000. (See “MISO Looks Back at 15,” MISO Changes to Queue, Auction, Cost Allocation to Dominate 2017.) Kozey founded the RTO’s legal department 18 years ago and served as chief legal officer until 2016.
“We have accomplished so much together, and we are now at a good point for me to transition to retirement. I will miss MISO, the people and working with all of our members, but after a fulfilling and satisfying career, it is time to think about the next stage of my life. I can leave the RTO without hesitation that we have the right leadership in place to take this organization into the future,” Kozey said later in a press release.
MISO said it has a succession plan in place and will announce Kozey’s successor later.
ORLANDO, Fla. — The National Association of Regulatory Utility Commissioners’ annual meeting attracted about 1,000 regulators, industry representatives, consumer advocates and other stakeholders.
Attendees participated in discussions on the energy-water nexus, physical and cyber challenges to the nation’s critical infrastructure and EPA’s Affordable Clean Energy Rule proposed in August.
PJM CEO Andy Ott referred to his RTO as a “referee,” balancing resource adequacy requirements with other states’ integrated resource plans.
“Somebody has to step up and say there’s a cost shift here, and unfortunately, now that seems to fall on us,” Ott said. “The big debate is when you start to have competitive states take action to preserve competitive generation or favor certain generation, the crowd on the other side says, ‘Hey, I’m putting my money at risk. It’s unfair.’
“One of the big disappointments of the past year was our proposal to accommodate states and still have competition and integrity in the market. Folks are taking that proposal as being against green, anti-environmental, which is absolutely not the case. We’ve got to create a balance and make sure states’ interests are accommodated or respected.”
“We’re policy takers, not policymakers,” MISO COO Clair Moeller said. “All of the states maintain their statutory obligation to resource adequacy.”
Moeller said MISO’s problems are different from PJM’s because MISO’s residual capacity market is less volatile.
“The economics are between the asset owner and the regulator, predominantly,” he said. “The policy of whether we retire this coal plant or don’t is policy-driven. The predictability of those retirements is better because of that regulatory compact. It’s less volatile on the capacity side because the states maintain that obligation. Our obligation is to maintain the assets people bring to the market.”
Kathleen Spees, a principal with The Brattle Group, said she saw another mission for grid operators: help the states achieve their policy objectives.
“First and foremost is a carbon-free policy. Every decision the markets make helps or doesn’t help the state meet those goals,” Spees said, referring to Moeller’s comment on RTOs being policy takers. “I didn’t hear a solution for how you guys can use the markets to achieve the states’ objectives. Markets have proven to be really effective in achieving reliability.”
“We had a successful tranche of transmission construction to accommodate renewable portfolio standards,” Moeller said. “No one should confuse the construction to achieve those standards with what got built. What got built was to achieve the economic goals of those states. We’re charged with doing things in the public interest. It’s not up to us to pick between generation owners and the states. It’s up to us to decide this is the best path forward in the consumers’ interest.”
“We’ve tried to ensure we’re not putting up barriers to what state policies are trying to achieve,” said Anne George, ISO-NE’s vice president of external affairs. “The states have seen a lot of their environmental policies achieve what they were hoping to achieve. Because they had success, now we’re looking at more aggressive targets. They’re taking actions to move forward. Our job is to look at the marketplace and see how we have the market facilitate what the states are looking to achieve, and to see that others’ part of that regulatory compact have the revenues to provide reliability to the region.”
In the end, Ott said, maintaining confidence in the markets is the best way to ensure open competition.
“If we can’t have a viable market, then Plan B is to flip back to something like competitive procurement, where it’s almost like a synthetic reregulation at a regional level,” he said.
Panel: Flexible Resources not Being Fully Used
Speaking on a panel on flexible resources, Grid Strategies Vice President Michael Goggin said grid operators are not benefiting from all the capabilities renewable energy and distributed generation offer. Were RTOs to remove barriers to full market participation, he said, flexible resources would be able to provide ancillary services and operating reserves.
“All U.S. ISOs have rules that are either directly or indirectly preventing wind and solar from providing services they never thought they were capable of doing,” Goggin said. “Capacity markets are not ideal for bringing out the best of these resources. They’re focused on megawatts, not procuring flexibility. Real-time incentives, through operating reserves and ancillary services and energy markets, provide a much better way of procuring that service when it’s needed. Self-scheduled resources aren’t fully participating in the centralized dispatch, an impediment to bringing about the full capability of these resources.”
David Nemtzow, director of the Department of Energy’s Building Technologies Office, suggested buildings provide another resource that can be tapped. He noted there are 124 million buildings, 118 million of which are homes, in the U.S. They account for 40% of the country’s energy usage, at a cost of $380 billion per year.
“Buildings are an integral part of the electric system. The challenge is to make them flexible without any degradation of the services they provide,” Nemtzow said. In addition to reducing demand through LED lighting and sophisticated sensors that adapt cooling/heating systems and lighting to the number of people present, buildings can be “interoperable, integrated systems … that are grid-responsive,” he said.
“Buildings can signal the utilities, so when the system is stressed or needs resources, a signal can be sent to the building owner or operator and they can make voluntary decisions and participate with the grid,” Nemtzow said.
Ric O’Connell, executive director of GridLab, said the two most significant trends he sees in the industry are the adoption of large, central renewable generation by utilities and policymakers, and the adoption of distributed energy resources by customers.
“The real question is, how do these two major changes interact?” he said. “Do they complement each other, or do they frustrate each other?”
Answering his own question, O’Connell cited a paper he recently published that found the two trends do complement each other. “Part of that is because DERs add flexibility to the grid and enable the addition of more renewables,” he said.
“On a utility-scale system, think of wind and solar as must-take. Sometimes, the rest of the system needs to be there for them. DERs are that thing your system operators are constantly grumbling about. This technology isn’t actually that new. We’re just allowing these resources to expose these characteristics.”
O’Connell referred to Minnesota, where he said modeling revealed that DERs’ flexibility is key to unlocking higher renewable penetrations, and that limiting DERs would dramatically increase the cost to decarbonize the system. “We have to start thinking about how we connect these new technologies,” he said.
Minnesota Public Utilities Commission Chair Nancy Lange, speaking on a separate panel, said the state is doing just that.
Quoting Wayne Gretzky’s strategy of skating to where the puck will be, not where it’s been, Lange said that in distribution planning, the commission thinks it knows where the puck is going.
“We have 4,500 [electric vehicles] in Minnesota. Are we going to have 10,000 in a year, or 7,000 in a year, or 20,000?” she asked. “Those are some of the skate-to-where-the-puck-is-going questions.”
Commissioners Share Their Market Concerns
During an Electricity Committee devoted to market issues, Western regulators shared with their peers the latest developments in the Western Interconnection: CAISO’s expansion of its real-time balancing market; CAISO’s and SPP’s offerings of reliability coordination services as Peak Reliability enters its last year of business; and SPP’s life-support effort to integrate some of the Mountain West Transmission Group.
Utah Public Service Commissioner David Clark quoted NERC CEO Jim Robb, the former Western Electricity Coordinating Council CEO: “The transition that will occur in reliability coordination services in the West is the single most important reliability coordination effort facing the U.S. in the next two years. We have our eye carefully on this transition process.”
Clark said Western states outside of California are concerned about CAISO’s “further extension” of market services.
“The principal challenge for many is the area of governance,” he said. “In Utah, we have a great desire to retain our self-determination, with respect to our energy policy. If we ever become involved in a market being served by vertically integrated utilities, we would want a voice in the government. We would want the operations of that market to be transparent.”
“There’s still skepticism with states and utilities in the West when it comes to take that step to join an RTO,” New Mexico Public Regulation Commissioner Cynthia Hall said. “There’s a growing concern relative to the problems created by seams issues. There’s a reticence to becoming a[n RTO] member. The reasons are multiple, not the least of which is if they have to pay to play — they would have to pay a greenhouse gas adder in California.”
Illinois Commerce Commissioner John Rosales discussed his problems with PJM’s capacity market construct, which he said has succeeded in lowering wholesale prices and the cost of operating reserves.
“What’s been somewhat contentious are the parts that don’t work well, which is pretty much everything else,” he said. “For me, it’s inherently flawed and extremely complex. The capacity construct is constantly being revised. … There have been well over 30 revisions, which becomes very frustrating for the states. We don’t call it a market, because there are so many features that are administratively determined … price caps, the cost of new energy fluctuates, performance requirements. Most of us agree that generally, this construct fails to send the proper price signals to ensure the proper fuel mix.”
Competitive markets have a supporter in Michigan Public Service Commission Chair Sally Talberg, who said, “Whether deregulated or fully regulated or something in between … at the end of the day, we want affordable, reliable service. We all have a common goal in fostering those competitive environments. I feel like we’re dancing around with a patchwork of dos and don’ts at the state level, and that creates uncertainty.”
Indiana Utility Regulatory Commissioner Sarah Freeman said her concern is with a rapidly changing fuel mix. She said her state expects four coal-fired units to retire by 2023, and she noted there are no new builds on the horizon.
“If it’s happening in Indiana, it’s happening bigger and faster somewhere else,” she said. “Once RTOs become involved, we need to maximize our cooperation and avoid any protectionist tendencies we have.”
Seams issues topped Illinois Commissioner Sadzi Oliva’s lists of concerns. She said market inefficiencies show up on the seam, “typically as a result of incompatible market rules.”
“This increases the ultimate cost to the ratepayers,” Oliva said. “The seam between MISO and SPP will be the concern for the majority of us. Illinois’ concern is receiving an unwarranted cost allocation.”
Amid an uptick in spending on transmission infrastructure that has attracted increased scrutiny from those paying the bills, customers and developers met Thursday for a workshop on how to get to the grid of the future.
The Department of Energy convened the daylong session at the National Rural Electric Cooperative Association’s conference center in Arlington, Va., to gather information for the department’s 2019 electric transmission congestion study.
Tatum wasn’t alone in his call for transparency. Traci Bone, an attorney with the California Public Utilities Commission, took issue with transmission projects that receive little or no RTO review. Known as supplemental projects in PJM, they are usually developed by incumbent transmission owners within their own zones to address their own planning criteria. (See FERC Upholds PJM TOs’ Supplemental Project Rules.)
She noted FERC’s rejection in September of a complaint by the CPUC and others who argued that Pacific Gas and Electric and Southern California Edison are violating Order 890’s transparency provisions because much of their transmission planning is done without stakeholder input or review. (See ‘Asset Management’ not Subject to Order 890, FERC Rules.)
It’s “very concerning” that FERC has taken “such divergent views” from ratepayers, she said.
During audience questions following Bone’s panel, Exelon’s David Weaver criticized it as “a very one-sided panel” and said the decision to spend on resilience and security upgrades is not as straightforward as addressing reliability criteria.
“I think it can be perceived that wrong investments are being made,” he said.
“Not so much that they’re making the wrong investments, but we don’t know what investments they’re making,” Bone responded. “We need to have a say in that.”
LS Power’s Sharon Segner, who was also on the panel, argued for increased competition for transmission projects. Following a stakeholder campaign led in part by Segner earlier this year, PJM has begun considering developers’ cost-containment guarantees as part of its analysis of competitive transmission proposals. (See Cost Containment Clears MC Vote Despite PJM Plea.)
Segner noted that eight states — North Dakota, South Dakota, Minnesota, Oklahoma, Nebraska, Alabama, North Carolina and Indiana — have passed right of first refusal laws “to thwart Order 1000” and FERC’s efforts to introduce competition. Order 1000 eliminated ROFRs from FERC-approved tariffs and agreements, but the commission says it is powerless to block states from enacting such laws to protect incumbents’ monopolies.
Public Engagement
The workshop also looked at the importance of public engagement in getting large interregional projects completed. Dan Belin, of engineering firm Ecology & Environment, compared the permitting processes of the Great Northern Transmission Line — to link Minnesota with Manitoba’s hydro resources — and Northern Pass, which would have delivered Quebec hydropower into New England.
Great Northern “had a very robust public-involvement program” that included engagement with the Minnesota Department of Commerce prior to submitting its application, Belin said. The project was approved within the state Public Utilities Commission’s statutory 15-month timeline.
Northern Pass held no meetings prior to submitting its application. The filing attracted 9,000 public comments, and the seven-year review eventually ended in rejection by New Hampshire.
“That significantly draws out the process,” Belin said. “The public involvement piece was a big differentiator between the two projects.”
“What we saw in Minnesota is not typical and it should be more typical,” said Rich Sedano, president of the Regulatory Assistance Project.
He described transmission development as “a public process that is largely shielded from the public” and advocated for improving transparency and public engagement. The process should also remain within state authority, and the industry should “accept the stress it’s going to cause,” he said.
Bess Gorman, assistant general counsel with National Grid, suggested involving the public in the tangible benefits of projects, such as finding ways to include them in benefiting from cost savings.
“As much as you can do,” she said of the need for public engagement. “That’s how you’re going to get the project through.”
Rob Gramlich, president of consulting firm Grid Strategies, credited transmission expansions such as MISO’s multi-value projects, highway/byway projects in SPP and ERCOT’s Competitive Renewable Energy Zones with precipitating the growth in renewables.
“I don’t think we would have half of the wind industry that we have without these plans in the middle of the country,” he said.
Culture Change
Others discussed difficulties winning approval for interregional projects. EDF Renewables’ Omar Martino described a “quadruple hurdle” for one project that required satisfying individual criteria of MISO and SPP and their mutual criteria in addition to securing local approval. The host utility vetoed the project, he said, because it preferred to use an operating guide.
“Something is just not right,” he said. “There’s a gap that needs to be fixed.”
He and others called for culture changes at decisional bodies throughout the process.
“You have to create these programs … inside utilities, inside the RTOs. You also have to have the right culture, the right leadership, the right guidance,” he said.
Gramlich said “the concepts are generally in Order 1000” for interregional planning, “but it didn’t get the job done,” and decisions since then have “weakened” it.
“Nobody wants to pay for something they don’t benefit from, so there’s a healthy skepticism in the RTO process,” he said.
On Nov. 9, the Governors’ Wind and Solar Energy Coalition wrote a letter to FERC advocating for unifying the Eastern, Western and Texas interconnections via ultra-high-voltage lines. The coalition, which includes 19 state governors, compared the proposal to creating the nation’s interstate highway system 60 years ago and the $315 billion grid China is building today.
The coalition cited a study by Iowa State University that estimated the impact of two transmission expansion scenarios: a $40 billion investment in transmission that could allow renewable penetration to rise to 40% nationwide, and an $80 billion investment that could push renewables to 50%.
Cost Allocation
Determining how much transmission is needed and who’s going to pay for it are also obstacles to such ambitious proposals.
In the first morning panel, PJM’s Ken Seiler said that reliability has vastly increased from earlier in his career when “we were hanging on by our fingertips” daily during late-afternoon summer peaks.
Tatum, who shared the panel with Seiler, agreed that there’s no clear measure to “know if we’re over- or under-building” the grid. But he said that it is clear that developers are now making up for a “dearth of investment” in previous years. He noted that PJM is on track to add $7 billion to its Regional Transmission Expansion Plan this year, which would be the biggest addition in the plan’s history.
And then there’s the question of who picks up what portion of the tab.
“Everything goes really, really well until you get in to the concept of cost allocation,” Seiler said. “Once you start talking about money … that’s when the discussion gets really, really tough.”
Participants and audience members cited several examples of cost allocation fights, notably the ongoing debate over the Artificial Island project, PJM’s first competitive project under Order 1000. (See Del. Group Seeks to Block Artificial Island Project.)
“It’s really all about the cost allocation, but if you can solve that, the rest of this stuff is easier,” Gramlich said.
He advocated for broad, beneficiary-pays allocations in which many stakeholders shoulder smaller portions of the bill. Still, that won’t solve everything.
“There is no perfect solution for cost allocation except [to] pay a lot of lawyers for a lot of litigation,” Exelon’s Steve Naumann said.
MISO will soon file a proposal with FERC to relieve its overfilled generation queue by implementing more stringent site control requirements and increasing the milestone payments imposed on project owners.
The proposal is down to a final review from the Planning Advisory Committee, stakeholders learned during the committee’s Nov. 14 meeting. MISO Resource Interconnection Planning Manager Neil Shah said the RTO will file the queue changes before the end of the year.
“Why is MISO revising its queue again when it just did a queue redesign two, three years ago? And the answer is, yes, the queue reform implemented in 2017 is working, but there are areas that we need to tweak because MISO’s queue is getting clogged with numerous projects,” Shah said.
Staff say the changes will encourage stalled projects to withdraw from the queue earlier in the process. (See “MISO to File Queue Changes,” MISO Queues up Interconnection Options.)
Shah said MISO currently conducts unnecessary definitive planning phase (DPP) studies because unready projects enter the first phase of the queue without first securing a location and are nevertheless studied. He said such projects often withdraw too late in the DPP process, affecting other projects and complicating their subsequent studies. The RTO wants to make the queue easier for projects that have site control, are viable “and have done their homework.”
MISO will now define site control as 50 acres/MW for wind generation, 5 acres/MW for solar generation, 0.1 acre/MW for battery storage and 10 acres for other resource types. An interconnection customer that wants to secure less land than required will now have to hire consultants to prove their project does not require the full amount of space.
Documentation of exclusive site control will now be due 90 days before MISO begins queue studies. The RTO will also no longer accept a $100,000 cash fee in lieu of site control. Shah said 75% of the projects entering in the April 2018 cycle and 62% of the projects entering in the August 2017 cycle elected to pay the $100,000 fee instead of demonstrating site control.
However, MISO will still allow interconnection customers experiencing regulatory holdups to submit a refundable, $10,000/MW fee along with detailed documentation and affidavits demonstrating the restrictions. It will also change the first milestone payment from a $4,000/MW fee to 10% of the average network upgrade cost from the RTO’s last three DPP cycles. The second and third milestone fees will remain unchanged at 10% and 20% of network upgrades costs found in system impact studies, respectively.
MISO will now withdraw a project before the queue’s second decision point if the customer fails to demonstrate exclusive site control.
The proposal also alters MISO’s current practice of refunding 100% of the first and second milestone payments at the two decision point “off ramps” embedded in the queue, where projects can drop off without risking the most recent fees. The RTO will now only refund 50% of the first milestone payment at the first decision point and 75% of the second milestone payment if a project withdraws at the second decision point.
Shah said MISO is expecting another heavy round of queue entrants in the first quarter of 2019 and that the changes will help in the long term to limit the number of projects that enter and trigger multiple studies. The queue currently contains nearly 80 GW worth of generator projects.
Multiple stakeholders thanked MISO for researching and proposing the queue changes.
“I really appreciate MISO making these changes to progress the queue and not allowing it to reach a stalemate. I really hope this will make things better so we can do our job at the state level,” Minnesota Public Utilities Commission staff member Hwikwon Ham said.
Additional work on the queue will continue in 2019. The Interconnection Process Task Force (IPTF) will work early next year to propose rules that allow hybrid generation interconnections and two generators to share one point of interconnection.
The IPTF may also begin work on several stakeholder suggestions currently on hold. They include:
Reducing phase one of the DPP by 30 days;
Cutting down the generation interconnection agreement timeline from 150 to 90 days;
Putting a megawatt limit on the total number of projects that can enter a queue cycle; and
Reviewing how many projects submit cash versus a letter of credit for milestone fees, possibly opening the credit practice to changes.
Freshly Minted Interconnection Working Group
MISO will also be providing the IPTF with a facelift after agreeing to convert the task force into a more permanent working group.
The IPTF was set to sunset in January. In MISO’s stakeholder structure, working groups are more permanent than task forces, which have an expected sunset date.
The Steering Committee approved the move by general consent on Nov. 15, adopting the October consensus from the PAC. MISO’s eight voting stakeholder sectors voted 5.33 in favor, with 0.67 opposed and two abstentions, to convert the task force into a working group. (See MISO Stakeholders Rally to Save Interconnection Group.) MISO sectors are allowed to split their votes based on differing organization and company opinions within a sector.
Seeing the “overwhelming” vote in favor of the move, MISO Director of Planning Jeff Webb said the RTO will now support the move, despite initially opposing the change. MISO had initially recommended the IPTF merge into the Planning Subcommittee, because both deal with technical issues of modeling and study processes used in its annual Transmission Expansion Plan.
Webb said the RTO believed that a group merger was “pretty consistent with … MISO’s stakeholder redesign,” which discourages duplicate discussions across stakeholder groups. However, he said MISO will be able to continue to provide staff, liaisons and meeting space for an Interconnection Process Working Group.
PAC Chair Cynthia Crane said it was important for MISO to recognize the strong stakeholder consensus to preserve a working group.
Additionally, the Steering Committee adopted additions to the Stakeholder Governance Guide that clarify rules around sunset dates for MISO groups. The committee added language that parent committees and the Steering Committee “should be diligent in the review and manage of entity sunset dates” of task teams and task forces. The language also specifies that motions for retirement should originate in the groups in question, with the Steering Committee “charged to review and manage sunset dates if applicable.”
Parent entities will be responsible for bringing retirement recommendations before the Steering Committee. The revisions also specify that the Advisory Committee can vote to “uphold or modify” Steering Committee retirement recommendations, particularly if the Steering Committee, the group in question or the parent entity disagree on whether to retire the group.
MARLBOROUGH, Mass. — ISO-NE last week kicked off its formal annual review of the transmission system to delineate zones for Forward Capacity Auction 14, which will be held in February 2020 to cover the 2023/24 capacity commitment period.
Al McBride, the RTO’s director of transmission strategy and services, told the Planning Advisory Committee that “we’re coming out of a significant backlog of interconnection requests in Maine.” He noted that FERC’s approval last year of clustering has enabled the queue to move forward. (See FERC Approves ISO-NE Queue Clustering.)
Potential capacity zone construct for FCA 14. | ISO-NE
The first cluster of more than 600 MW is proceeding through the system impact study process, as is an external elective transmission upgrade of 1,200 MW, which are collectively driving the creation of a Maine capacity zone, he said. The RTO is not proposing a Northern Maine capacity zone because the deliverability standard requires new resources in the state to be deliverable throughout the Maine load zone.
“That’s a significant number of new resource additions,” McBride said. “Maine used to be export-constrained, particularly from north to south, but after the Maine Power Reliability Program upgrades, there has been headroom. This headroom would more than be used up by the projects moving forward in the system impact study process.”
The trigger to model an export-constrained zone is based on the quantity of existing and proposed new resources compared with the maximum capacity capability in the zone.
Zone formation is a two-step process: First, identify the potential zonal boundaries and associated transfer limits to be tested for modeling in the Forward Capacity Market; then use objective criteria to determine whether or not the zone meets the trigger to be modeled for the capacity commitment period.
To form capacity zone boundaries, the RTO considers significant changes over the past year, including new transmission upgrades, resource retirements and new capacity resources.
Boundary Specifics
ISO-NE does not expect transmission upgrades in the Southeastern Massachusetts and Rhode Island (SEMA/RI) area to change the boundaries of that area or the Southeast New England zones, McBride said.
Most of the SEMA/RI Reliability Project upgrades have not yet been certified for use in the FCM, and certifications for FCA 14 will be known in January 2019. However, if the SEMA/RI Reliability Project upgrades are certified, planners will assume they will be in place for the 2023/24 period.
| ISO-NE
Mystic 7 will be retiring with the start of the 2022/23 period. The RTO has previously analyzed different potential future retirement scenarios, including the loss of Mystic 7 and other units, and did not expect such retirements to drive a change in capacity zone boundaries.
Capacity interconnection requests as of Nov. 1 are more than 700 MW from West/Central Massachusetts, with the rest, all nameplate, being more than 4,100 MW from New Hampshire/Vermont; more than 6,200 MW from Maine; more than 7,700 MW from SEMA/RI; and more than 2,700 MW from Connecticut.
SEMA/RI 2028 Needs Assessment
ISO-NE’s SEMA/RI 2028 Needs Assessment Scope of Work study assumes the complete retirement of the 2,274-MW Mystic plant and includes analysis assuming that Vineyard Wind and the New England Clean Energy Connect (NECEC) projects will be in service, according to Kannan Sreenivasachar, ISO-NE’s transmission planning technical manager.
Sreenivasachar told the PAC on Thursday that the study for the 10-year horizon will be using data from the 2018 Capacity, Energy, Loads and Transmission (CELT) report to determine the forecasts for the peak load levels evaluated.
All transmission and generation facilities operating as of June 1, 2018, are included in the base cases, and the 34,092-MW 90/10 summer peak load includes 5.5% transmission and distribution losses.
The study evaluates reliability performance and identifies reliability-based needs in the SEMA/RI study area for the year 2028 while considering future load distribution, resource changes based on FCA 12 results, and the 2018 solar and energy efficiency forecasts, Sreenivasachar said.
The study assumes that resources without an obligation (typically through the FCM) cannot be relied upon to resolve a reliability need and are therefore not considered in the steady state analysis. However, they do contribute to the available short-circuit current, as they may be in service as part of the energy dispatch of the system, he said.
The study bases its short-circuit base case on the expected topology in the 2023 compliance steady state base case. No significant project is expected in the 2023-2028 time frame, and hence the 2023 case was considered acceptable, Sreenivasachar said.
Asked about future generation selected in state solicitations, Director of Transmission Planning Brent Oberlin said there were two options.
He said if the RTO finishes the study ahead of final approval of those projects, the identified needs will be based on conditions without the generation in place. Upon approval of the generation, the needs will be changed to those associated with the scenarios that included the generation. If the generation is approved prior to the completion of the study, the needs associated with scenarios that do not model the generation can be ignored.
Stakeholders should submit comments on the study to pacmatters@iso-ne.com by Dec. 2. The RTO plans to post the draft study and intermediate study files in the first quarter of next year before completing the study area 2028 Needs Assessment and presenting it to the PAC by Q2 2019.
The RTO’s next steps will be to review transmission certifications for FCA 14 with the Reliability Committee in January, and to further discuss the potential capacity zone boundary construct at the PAC in the first quarter of 2019.
Moody’s Sees Region in Good Economic Shape, for Now
Moody’s Analytics Director Ed Friedman told the PAC that New England is leading the Northeast in economic development, particularly job growth, which is not typically the case, as that occurs more frequently earlier in an economic expansion or business cycle.
“That’s been a good development over the past year, but probably not sustainable over the long term,” Friedman said.
Massachusetts and New Hampshire have led the region in new hiring since last October, both outpacing the national average, with Rhode Island very close to the U.S. figure of about 1.7% in employment growth.
“The drivers are the booming tech sector in Boston … and in and around the Seaport district,” he said.
New England leads the Northeast in employment, according to Moody’s Analytics.
New England is unfortunately hampered by a generally weak and aging demographic outside places like Massachusetts, which holds back labor force growth, he said. “Very good job growth just cannot go on forever” without a growing population to feed the labor force.
The better than 3% wage gains posted in most of the region’s six states over the past year — only Connecticut and Rhode Island fell below that level — will likely continue over the coming year, but consumer confidence in New England is lower than in any other part of the U.S., Friedman said.
FERC ruled last week that an existing Montana wind farm awaiting a new interconnection is exempt from a recent commission order requiring all new generators to be capable of providing primary frequency response.
The commission’s Nov. 15 ruling said Order 842 does not apply to NaturEner’s Glacier Wind Farm II, which has been in the queue for Enbridge’s Montana-Alberta Tie-Line (MATL) since 2013 and currently the only resource to request to join the 214-mile, 230-kV AC line extending from Lethbridge, Alberta, to Great Falls, Mont. (ER18-1788). The wind farm began operating in SPP in 2009.
Order 842 requires all new generators to be capable of providing primary frequency response as a condition of interconnection. The rule has been in effect since May.
MATL | Enbridge
Enbridge’s U.S. operating subsidiary for the line, MATL LLP, asked the commission to clarify that Order 842 does not apply to the pending interconnection request, saying the wind farm applied for interconnection and was studied before the rule was issued. The company said requiring frequency response service would “cause significant equipment installations and system restudies that would cause unduly burdensome delays and expenditures.” MATL estimated that restudies would cost anywhere from $15,000 to $20,000 and take three to six months.
FERC assured the company that the rule does not apply to the existing generator. The commission pointed out that MATL’s pending request involves a generator that has already been in operation under another interconnection agreement for about nine years and has been lined up for interconnection for five years, well before the issuance of the final rule. FERC also said the wind farm has not taken “any action that requires the submission of a new interconnection request.”
MATL noted that its has nearly completed the associated interconnection studies with NaturEner and expects to proceed with the negotiation of an interconnection agreement in the near future.
