MISO last week proposed bringing the three major players in its load forecasting together to coordinate on predictions for long-term transmission planning in the footprint.
MISO’s proposal would have both Purdue University’s State Utility Forecasting Group (SUFG) and consulting firm Applied Energy Group working with 20-year forecasts provided by load-serving entities. The RTO uses Applied Energy for distributed resource data predictions in its annual Transmission Expansion Plan.
The idea came in part from the Coalition of Utilities with an Obligation to Serve in MISO (CUOS), an ad hoc group of utilities and regulators, which proposed to require LSEs develop a 20-year base load forecast that includes monthly predictions for energy and non-coincident peaks. (See MISO Utilities Float New Load Forecasting Approach.)
The RTO put a temporary hold on ordering more independent load forecasts from the SUFG while it explored other stakeholder-proposed forecasting options. (See MISO Looks to Members for Load Forecasting Ideas.) It had received stakeholder criticism for its plan to order four versions of the Purdue forecast, each tailored to one of the futures used to inform its annual transmission plan, beginning with MTEP 20.
Speaking during an Oct. 12 special conference call, MISO planning manager Tony Hunziker said the RTO’s new approach draws from the CUOS proposal in incorporating the LSEs’ 20-year forecasts.
MISO would send LSE-originated demand and energy forecasts to the SUFG, which would compile and analyze them to inform its state-by-state forecast. The RTO also envisions the SUFG using LSE data to produce a complete 20-year demand and energy forecast for each of the 140-plus LSEs, which will influence the four MTEP futures. The SUFG uses its state-by-state forecast to corroborate what share of a state’s load is located within MISO territory.
The LSEs’ gross forecasts would not include energy efficiency or other demand-side factors, such as distributed resources and electric vehicle programs. MISO staff said the RTO will ask LSEs to submit demand-side data separately to AEG, which would use them to develop the demand-side management potentials in the futures.
But some stakeholders are unconvinced that LSEs can simply change their forecast methods in under two years to detach energy efficiency totals from their forecasts.
Hunziker said LSEs, MISO staff and the SUFG will be able to communicate throughout the forecasting process.
“As [the SUFG] is looking at the data and they see an irregularity, there’s a feedback loop. They can get ahold of the LSE that made the forecast and discuss and hash [it] out,” Hunziker said.
Stakeholders were also concerned about how the SUFG would adjust LSEs’ original forecasts to make the final LSE-specific forecasts used in the MTEP.
Hunziker said the SUFG will use its independent load data to fill in any missing gaps.
“There may be entities that don’t provide some information, and we want to fill in those gaps. That’s always been a concern for MISO,” Executive Director of System Planning Aubrey Johnson said. “We still need to fill in for LSEs that don’t provide forecasts or submit incomplete data.”
He promised stakeholders that LSE data would be the “foundational piece” of the load forecast and said MISO will provide more detail on how and under what conditions the SUFG will modify LSE forecasts.
Johnson said MISO will present a firmed-up proposal at the Nov. 14 Planning Advisory Committee meeting. He asked for stakeholders to send written input on the proposal by Oct. 31.
VALLEY FORGE, Pa. — A proposal to revise PJM’s credit requirements for financial transmission rights in response to the historic GreenHat Energy default will be delayed a month but should still be on track for April implementation, PJM’s Lisa Drauschak told attendees at last week’s Market Implementation Committee meeting. RTO staff had previously planned to bring a problem statement and issue charge to the meeting for consideration.
“We think it’s important to take a breath,” Drauschak said, explaining that the RTO’s Credit Subcommittee has decided to further vet the proposals before it.
“We still feel we can get a filing to FERC in January” to be effective April 1, she said.
Dayton Power and Light’s John Horstmann asked that staff consider alternatives to the current market design to eliminate the structural credit flaws that allowed the default and to the usual stakeholder process that develops the credit requirements for the risky and sophisticated long-term FTR product. Attorney Steve Huntoon asked why the list of “lessons learned” from GreenHat didn’t address PJM’s efforts to increase GreenHat’s collateral. [Editor’s Note: Huntoon is a columnist for RTO Insider and is representing it in its effort to open meetings of the New England Power Pool to the press and public.]
Staff said it will prevent the situation from occurring again by revising the credit policy to give the RTO increased authority to make collateral calls.
“That agreement did not come out of a collateral call. It came out of something else,” Drauschak said.
“If we had the authority to do a collateral call, we would have done that,” PJM counsel Jen Tribulski said.
Despite the revisions, staff were careful to avoid suggesting the FTR market has no risk of defaults.
“Nothing is 100% absolute,” Drauschak said.
However, stakeholders pressed PJM to take more responsibility for the market’s security.
“We agree that you can’t prevent defaults — those things will happen — but we depend on PJM to protect us,” Rockland Electric Co.’s Brian Wilkie said.
DC Energy’s Bruce Bleiweis questioned whether the lessons learned fully encapsulated the advice PJM received during the closed-door workshop that precipitated the document. He said he was told by one of the participants that they weren’t given an opportunity to review a draft of the RTO’s takeaways.
“These items did come out of the workshop. … I’m not sure why someone would say that, but these items did come out of the workshop,” Drauschak said, defending staff’s work.
Independent Market Monitor Joe Bowring, who attended the workshop, concurred that the document accurately reflected the results of the meeting.
Must-offer Exception
Stakeholders deferred a vote on revising exceptions to capacity providers’ must-offer requirement after PJM changed its proposal from the last time it was presented to the MIC. Staff revised the proposal to give resources receiving an exception three years before being required to change their status from a capacity resource to energy-only. Capacity resources must offer any uncommitted capability into all capacity auctions unless they have been granted an exception.
PJM’s Pat Bruno explained that, after three consecutive years of exceptions, a unit would be modeled as energy-only in the capacity model, so its capacity megawatts would be reduced to zero and its owner would have 12 months to nominate its capacity interconnection rights (CIRs) elsewhere. The nominated generator wouldn’t have to be operational if it’s in the interconnection queue, he said. CIRs, which grant access to inject generation into the transmission system, have value and can be sold. (See PJM, Generators Debate Injection Rights for Exempted Capacity.)
The proposal, which has undergone several iterations, was satisfactory for some stakeholders.
“I feel pretty confident in this,” said Carl Johnson, who represents the PJM Public Power Coalition.
Bowring, however, objected to the changes.
“We’re not confident at all that this will prevent exercising market power,” he said, noting that resources could potentially delay reallocation of the CIRs for perhaps six years. “This is a very long time period. It’s not consistent with maintaining open access to the grid.”
Exelon’s Sharon Midgley said that while her company — which requested the rule changes — would like to vote, she was willing to wait another month.
Surety Bond Use
Stakeholders endorsed two competing proposals to allow use of surety bonds as credit in PJM’s markets, despite concerns raised by Bowring and others. The proposals will receive consideration at the Markets and Reliability Committee.
A proposal developed by the PJM Credit Subcommittee that would allow surety bonds as credit for all activity except FTR portfolios received 61% in favor in a sector-weighted vote, easily surpassing the necessary 50% threshold. The proposal would also set a $10 million cap per issuer for each member and a $50 million aggregate cap per issuer.
Exelon’s proposal, which would allow using surety bonds for all credit requirements with a $20 million cap per issuer for each member and a $100 million aggregate cap per issuer, received 58% in favor. Stakeholders also indicated their interest in making a change, voting 66% in favor of not keeping the status quo.
Bowring repeatedly asked PJM and Exelon, which proposed the change, to verify that surety bonds are as secure as letters of credit (LOCs), which the RTO currently accepts.
“We believe they are legally as strong,” PJM’s Hal Loomis said.
“They’re a weaker form of credit,” Bowring said. “That’s why they’re cheaper.” He asked PJM whether it had requested the opinion of the same expert panel it used for a review of FTR credit issues on the advisability of using surety bonds and whether it has determined whether exchanges permit the use of surety bonds in place of LOCs.
Midgley countered that surety bonds are cheaper than LOCs because of Basel III and a more robust underwriting process. Since 2008, banks must now realize LOCs as a liability on their balance sheet, which affects their capital ratios for regulatory purposes.
“We don’t share your view that this is an inferior product. … We would not be seeking to [get them approved] unless they were comparable,” she said. “What you have before you is a proposal that would reduce cost for market participants, provide diversification for PJM and, at the end of the day, benefit customers.”
Other stakeholders were concerned about comparing PJM’s markets to those of NYISO and ERCOT, where surety bonds are already accepted for credit needs.
“It’s extremely smaller than the amount of dollars we’re talking about in PJM,” Direct Energy’s Marji Philips said. “Now I am mindful of a huge default happening [again like GreenHat], so now I’m seeking detail.”
PJM staff’s proposal to modify the FTR forfeiture calculation rules to include loop flow impacts doesn’t go far enough for some stakeholders. Staff proposed incorporating loop flows when determining whether virtual transactions in the day-ahead market have a 10% or greater impact on coordinated market-to-market flowgates.
Chris Carpenter of VECO Power Trading would also like to see the FTR impact test relaxed so that a virtual trade that creates a very small contribution to an FTR’s settlement wouldn’t trigger forfeiture of the FTR profit. Exelon and NextEra Energy supported VECO, which proposed three alternatives to mitigate that situation:
Forfeit the portion contributed by the “triggered” constraint instead of the entire FTR settlement value;
Require the FTR to have a 0.1 distribution factor (DFAX) on the triggered constraint; or
Require the triggered constraint to be “substantially linked” and contribute a “significant dollar share of the FTR settlement value.”
The current FTR impact test, which has been in effect only since last year, triggers forfeiture if the DFAX multiplied by the shadow price is greater than or equal to $0.01. The previous test triggered forfeiture if the DFAX was greater than or equal to 0.1.
“There is a pretty significant impact from that change,” Carpenter said. “From our perspective, this forfeiture amount doesn’t really line up with the impact of the activity.”
“One penny manipulation is manipulation,” the Monitor’s Howard Haas said. “What we have seen, under the current rule, is a dramatic reduction in forfeitures because of changes in behavior.”
Carpenter acknowledged the reduction but attributed it to market participants “not feeling the risk tradeoff is worth” attempting the virtual trades.
“My firm has stopped doing [increment offers] and [decrement bids] because we’re concerned about this rule,” Midgley said. “In the FERC proceeding, PJM raised concerns that the new rule would restrict legitimate market activity that promotes market convergence and increases market efficiency. I’m here today to say this is happening. … I think it’s a really beneficial conversation to have.”
Gabel Associates’ Michael Borgatti, representing NextEra, said the rule should be very selective in not penalizing unforeseen impacts and only punishing manipulative behavior.
“We agree that we think the PJM package takes a meaningful step forward. … Having a rule that serves as a [deterrent] to that activity is healthy,” he said. “It’s an oversimplification at best to say that a penny change in the FTR is tantamount to manipulation.”
Carpenter argued that the first alternative proposed is like CAISO’s forfeiture rule in that “the concept of forfeiting by constraint is something that has been done.”
Haas countered that CAISO’s definition of an FTR is different from PJM’s. “You have to rethink the FTR product itself,” he said.
BOSTON — “We Are Still In” said the button Anne Kelly wore Wednesday as New England’s clean tech community gathered here, three days after a dire report by the U.N.’s Intergovernmental Panel on Climate Change.
For Kelly, senior director of CERES’ Business for Innovative Climate and Energy Policy (BICEP) Network, the button was a rebuke to President Trump’s plan to pull the U.S. from the Paris Agreement on climate change.
The IPCC report — which warned that preventing catastrophic effects from climate change will require unprecedented global cooperation — had a sobering effect on the Horizon 18 conference, where New England clean tech companies looking to make sales and forge partnerships met with other stakeholders. (See IPCC: Urgent Action Needed to Avoid Climate Trigger.) But there was no hint of defeatism in the crowd.
“The need to move to action is more and more compelling,” said Patricia Fuller, Canada’s ambassador for climate change.
Keeping temperatures from rising more than 1.5 degrees Celsius (2.7 degrees Fahrenheit) from 1850-1900 levels will require carbon pricing, maximizing renewable energy and energy efficiency, and incorporating carbon capture and storage, Fuller said. “There is no silver bullet. Really, as someone put it recently, you need silver scattershot. You need all the tools.”
Fuller cited a September report by the Global Commission on the Economy and Climate that recently concluded that “bold action” on climate could produce economic gains of $26 trillion through 2030 and create 65 million jobs compared with business as usual. “So, this is also an opportunity,” Fuller said.
Canada is passing legislation for a federal carbon pricing system, reducing methane emissions and emissions from heavy duty vehicles, and accelerating the phaseout of coal-fired electricity. All federal buildings will run on clean power by 2025.
Because the Trump administration and Congress have failed to take similar action in the U.S., it is the states that “are in charge of progressive energy policy,” said Ed Krapels, CEO of Anbaric Development Partners.
Krapels said proposed offshore wind projects in New England represent “probably the largest single investment opportunity in clean energy in the country.” Citibank has estimated as much as $100 billion of capital spending is needed to develop 20 GW of offshore wind on the East Coast.
“While I can see why some people would be a little pessimistic about where we are with respect to the latest U.N. report, there really is an enormous amount of stuff that is very positive and very constructive that is happening. The money is here; it’s available. And I think the challenge is to create a set of policies and market structures that enable that market structure to be deployed,” Krapels said.
Transmission’s Role
Among the policy challenges, Krapels said, are how the offshore transmission infrastructure is developed and the role of energy storage. (See Anbaric Pushes Offshore Grid Plans.)
“Every transmission line should look at … the role that storage can play in increasing the capacity factor of renewable resources. I think the RTOs are very open to this idea. There is a lot to be done because they’re reactive organizations. They need to have developers put forward innovative new ideas.”
Gregory Wetstone, CEO of the American Council on Renewable Energy (ACORE), said renewable generation will never reach its potential without the ability to site transmission in areas like New England. “We need to be able to have transmission to renewable resource areas and so we’ve got to get beyond the NIMBY issues,” he said.
Wetstone called the lack of carbon pricing “the biggest externality in the history of economics.”
“If you care about these issues, vote,” he told the audience.
Matthew Nicholls, managing director of distributed energy solutions for General Electric, said his optimism comes from his prior career as a semiconductor engineer, where — per Moore’s law — computers’ processing power doubled about every two years. “Everybody lowered their heads, worked with partners, worked with capital and made it happen, year after year,” he said. “We see a similar type of transformation happening in the energy industry now.”
Researchers haven’t been as successful in cracking challenges such as carbon capture, despite billions in investments. But Rolf Nordstrom, CEO of the Great Plains Institute, said he was optimistic about the success of the “carbon capture coalition,” which won a federal tax credit for the technology in February. “We had the most liberal and the most conservative members of Congress voting for that — which probably deserves the Nobel Prize,” he joked.
Patrick Woodcock, Massachusetts’ assistant energy secretary, noted that the rise of natural gas and renewable generation has reduced U.S. power sector emissions below that of the transportation sector.
In contrast to the “unprecedented transition” in the electric sector, there has been only “incremental progress in transportation,” he said. “I see components of that disruption occurring in transportation. We have those fundamentals of cost curves coming down in batteries; disruptive companies receiving billions of dollars in investment to be at the vanguard of a new transportation system.”
Carol Grant, Rhode Island’s commissioner of energy resources, said progress also has been slower in converting the heating of buildings.
“We really have to work on transportation and on heating. Those are two areas that we have not made the same kind of progress in. … This is hugely important in heavy transport, in marine transport, in air transport. It’s not just about all of us getting electric vehicles.”
Jed Dorsheimer, managing director for financial services firm Cannaccord Genuity, also sees transportation as ripe for disruption, noting that personal vehicles sit unused about 95% of the time.
“Greed always trumps green,” he said. “I do believe most decisions — while we like to take an altruistic view of things — the economics play a heavy role. I do think this area is ripe for economics to drive decisions to change the transport industry.”
Cities and Universities
In addition to states, cities and universities are also providing climate leadership, speakers said.
Jon F. Mitchell, mayor of New Bedford, Mass., and head of the United States Conference of Mayors’ Energy Committee, boasted his city of 100,000 has the largest EV fleet of any city in the state, with 30% of its vehicles electrified. The city also has won recognition for its high per capita municipal solar capacity. The largest fishing port on the East Coast, New Bedford also is hoping to become a hub of the offshore wind industry.
Mitchell said the city’s efforts were motivated by climate change and cost savings “but also because, as an older industrial city, we saw that it’s pretty good for our brand. Instead of being seen as older and gritty and sort of struggling, we’re emerging as a place that’s seen as progressive, forward thinking and creative. And that’s what we want to be.”
Rosalie Kerr, director of sustainability for Dartmouth College, said universities can be nimbler than states and cities because renewable investments can be made with approval of just a handful of decision-makers. “There are 4,200 universities around the country. We control something like 3% of GDP. So it’s not a tiny market,” she said.
Lance Pierce, president of CDP North America, a nonprofit that runs a global disclosure system for investors concerned with companies’ environmental impacts, said utilities “sit at the hinge” of the old and new energy models. “In that regard they can be catalytic, I think, in helping make some of the changes.”
Although “utilities have been spotty” in disclosing their emissions and other environmental metrics, he said, Southern Co. and Dominion Energy began providing his company with data in the last year.
Marcy Reed, executive vice president of U.S. policy and social impact for National Grid, said her company no longer refers to itself as a utility. “We consider ourselves a clean energy transition company. And that is because … we deem it our obligation, and indeed our privilege, to help think through some of these challenges.”
New York and the New England states have pledged to reduce carbon emissions by 80% below 1990 levels by 2050. That will require 10 million EVs in New England, with all light-duty sales to be EVs by 2030, Reed said.
“That just calls for a massive shift,” she acknowledged. “People think it can’t happen. Well actually it can. That’s a decade from now.”
BP, which dropped its “beyond petroleum” marketing slogan several years ago following losing bets on solar power manufacturing, is seeking to get back into the sustainability game, said David Gilmour, vice president of business development.
Gilmour said the company’s sustainability goals and investments in the Oil and Gas Climate Initiative were prompted by customers’ demand for more environmentally friendly products and the company’s need to attract new talent. “I think we really do need to be inspiring our workforce to be working for a company that actually works for real positive benefits for society. … For BP to be around in 100 years, we need to be part of the energy transition. … Given that most of these technologies are highly disruptive to our existing business, we want to be part of and actually shape the future through the work we do.”
Jarett Carson, managing director of venture firm EnerTech Capital, said although U.S. venture capital investments are likely to set a record of more than $100 billion this year, investments in clean technology and energy will be below $6 billion, down from $7.5 billion in 2011. “That seems to be a direct dichotomy with the challenge issued by the IPCC, talking about the $2.4 trillion being needed to be invested almost every year,” he said.
But Daniel Goldman, co-founder and managing director of Clean Energy Venture Management, another VC firm, said a lot of investments before 2011 were in very capital-intensive technologies. “Today we’re involved in companies that aren’t capital intensive. Our fund will only invest in a company where you don’t need more than $30 [million] or $40 million to get to cash flow break even and have a product that can scale.”
Adam E. Bergman, Wells Fargo’s senior vice president for clean tech banking, also was less troubled by the availability of capital, citing the increasing involvement of corporate venture funds and “family office” investors, who tend to have longer time horizons and lower hurdle rates than Silicon Valley VC funds. He also noted that many of the big technology bets of the past, such as solar and wind, have reached maturity.
Emily Reichert, CEO of Greentown Labs, which claims to be the largest clean tech startup incubator in the U.S., said there are also more strategic investors now, such as BP, that can provide expertise to help new companies grow. “Ten years ago, there was definitely a green bubble. There were a lot of people that were investing in clean technology that perhaps didn’t necessarily have the knowledge or information they needed. They were not experts in energy,” she said. “I think it’s a lot more positive now.”
ALBANY, N.Y. — Carbon pricing, siting challenges for new renewables and new funding for energy storage initiatives all topped the discussion at the annual fall conference of the Alliance for Clean Energy New York on Oct. 9-10, which opened in the wake of a renewed warnings about global warming.
State University of New York Chancellor Kristina Johnson pointed to the newly released report by the U.N.’s Intergovernmental Panel on Climate Change that said catastrophic effects will likely occur sooner than previously thought and that preventing them will require unprecedented global cooperation. (See IPCC: Urgent Action Needed to Avoid Climate Trigger.)
Johnson, a former U.S. undersecretary of energy, said some people believe that any construct that would reduce greenhouse gas emissions enough to stop the planet from getting warmer would cost too much, but SUNY analysis conducted with the Boston Consulting Group determined it would “cost $1 trillion invested over 25 years.”
That works out to $40 billion a year to decarbonize the electric sector, electrify personal vehicles, modernize the grid and ramp energy efficiency, she said, “so that’s basically a grande latte per household per week. Who in their right mind wouldn’t do that?”
New York State Energy Research and Development Authority CEO Alicia Barton said her organization is “very close” to being able to issue the first request for offshore wind proposals, and it announced $40 million in energy storage funding incentives through the NY-Sun initiative.
“We’re not only serious about setting the targets but serious about getting the projects built,” Barton said.
Sunrun Chief Policy Officer Anne Hoskins, a former member of the Maryland Public Service Commission, shared her experience going to Puerto Rico to help with recovery from last year’s hurricane.
“We are partnering with three local installers … and the amazing thing is how everybody I talked to — the cab driver, the governor — all want distributed solar,” Hoskins said. “It’s because they realize they need to do something different.”
Pricing Carbon
Participants also discussed New York’s effort to price carbon into its electricity market. The state’s Integrating Public Policy Task Force (IPPTF) has been meeting almost weekly this year to model the impact of carbon pricing on emissions and prices in New York and neighboring regions. (See ‘Negative Leakage’ from NY Carbon Charge, Study Shows.)
“A lot depends on the assumptions being used … low gas price projections may not be realized, and if natural gas prices spike, then the dollar value of the environmental benefits rises, too,” said former NYSERDA head Frank Murray, now with the Natural Resources Defense Council.
Couch White attorney Michael Mager, who represents a coalition of large industrial, commercial and institutional energy customers, said, “The past six months have seen many new state initiatives and mandates on things like storage … and we haven’t had time to digest the analyses released over the past month or so by Brattle [Group], [Resources for the Future] and Daymark [Energy Advisors].”
Mager characterized a carbon charge as potentially the biggest market design change since NYISO was formed in 1999 and said his clients have two main concerns: What are the likely consumer impacts, and what are the environmental benefits?
“We’re also concerned about how the Public Service Commission sets the social cost of carbon and how they update it, and how often,” Mager said. “And we’re concerned about the potential for double cost recovery.”
In addition, he said that two out of three recent analyses indicate emissions would increase in New York state and drop in the region as a result of implementing a carbon charge.
“We’re undecided, not yet opposing, and may never oppose,” Mager said.
Christopher LaRoe of Brookfield Renewable Energy Group said a carbon adder may be the best way to achieve the state’s aggressive policy goals. He said his company provides the environmental benefits sought by the state but does not get compensated for it.
The state “recognizes the value of maintaining existing baseline resources, and yet you go incremental to that to achieve your 50[% renewables] by [20]30 goals,” LaRoe said, referring to the state’s Clean Energy Standard target. The PSC didn’t see fit to provide a revenue stream for Tier II resources, outside of a maintenance tier, which is “basically a nightmare,” he said.
Brookfield has lobbied to value Tier II resources at 75% of the Tier I price: “Not quite a made-up number, but it was meant to provide a discount off of the Tier I price,” LaRoe said.
That effort failed at the last minute in the legislative session this year, but FERC would like to see progress by the states and grid operators putting their policies and markets together, so hopefully New York “can get there voluntarily and not through coercion,” LaRoe said.
Clean Energy Progress
Anne Reynolds, executive director of ACE NY, highlighted progress over the past year, including new offshore wind targets, energy storage programs and energy efficiency targets.
“NYSERDA completed their first Tier I procurement, awarding contracts for 3.2 million more megawatts than they set out to do, and they issued the second Tier I procurement on schedule, delivering the much-needed certainty and regularity in the Clean Energy Standard procurement process,” Reynolds said.
In addition, Gov. Andrew Cuomo announced an ambitious energy efficiency goal of 185 billion Btu of savings by 2025, she said.
“Energy efficiency was a missing piece of the puzzle last year, not just because it can save ratepayers money and it’s good for the environment, but because under the CES, when they determined the Tier I, they assumed a lot more energy efficiency than New York was then achieving,” Reynolds said.
However, “developers still need efficient and predictable processes for permitting large-scale wind and solar under Article 10,” she said, referring to the state law governing the siting of generating facilities.
“Since last October, there’s been real progress with the queue itself, with one project certified, four projects deemed complete [and] one additional application. But in that same year, 21 new projects embarked on the process,” Reynolds said. “The process in itself in the last year hasn’t gotten faster or more predictable.”
Peter Olmsted, assistant secretary for energy to Cuomo, said, “We need to double down on collaborating with each other,” and that Article 10 process improvements should be coming faster now with the appointment of Sarah Osgood, director of policy implementation at the Department of Public Service, to speed implementation.
Siting Challenges
Osgood said there are currently 34 active projects in the Article 10 pipeline, 31 of them renewable energy projects.
“Overall we have over 6,300 MW of generation capacity proposed, three-quarters of it renewable energy,” Osgood said. “The projects are split pretty evenly between wind and solar, but we are noticing that the projects that came into Article 10 earlier tend to be more large-scale wind. We’re starting to see a little bit of a shift to have more solar entering the pipeline.”
David Gahl, director of Northeast state affairs at the Solar Energy Industries Association, said that some shortcuts have been taken on value of distributed energy resources (VDER) compensation.
“Right now, the VDER provides compensation for the avoided pollution, and that’s great, but I think some decisions were made in determining what that value should be that essentially shortchange what a number of solar projects or DER projects should receive,” Gahl said.
“There are little changes on the margins that have reduced that compensation, and ultimately that’s probably not the direction the state wants to go if it wants to put more DER on the system,” Gahl said. “We shouldn’t take shortcuts, shouldn’t shave off value.”
Jeff Bishop, CEO of storage developer Key Capture Energy, said there are several frameworks to consider and that “as we move to the energy future, there’s a role for all the new technologies.”
VDER doesn’t include hydro, biomass, small wind or PV, he said, “but there is a role for storage … we have to be sure that technologies get paid for all their attributes.”
Dan Hendrick, head of external relations for Clearway Energy, said New York is heading in the right direction, but with considerable gaps.
“There’s a talk of devaluing in a five-year timeline, but some of these facilities generate for 30 years,” Hendrick said. “Con Edison has only 8 MW of community-distributed generation in the pipeline around New York City.”
Michael Gerrard of Columbia Law School reviewed some of the legal history around siting requirement waivers and the tug of war between state and municipal officials.
“The main difference between the old version of Article 10 and the new is that the former had the phrase ‘unreasonably restrictive,’ which has been supplanted by the phrase ‘unreasonably burdensome,’” Gerrard said. “There’s no clear explanation anywhere of why that change was made or what it amounts to. My own view is that it probably means that economic considerations can certainly be a factor in addition to everything else that used to be considered.”
BOSTON — Municipal aggregation is becoming a potent tool for cutting electric prices and greenhouse gas emissions, while some believe retail choice has failed to live up to its promise for residential customers, speakers told Raab Associates’ New England Electricity Restructuring Roundtable on Friday.
The roundtable featured a panel of state regulators on grid modernization and a second on the future of residential retail choice, where Rebecca Tepper, chief of the Massachusetts attorney general’s Energy and Telecommunications Division, reiterated the AG’s call for a ban on competitive suppliers signing up new individual residential customers. The AG’s office initially made the proposal in March, when it released a report concluding that electric retailers were overcharging residential customers and preying on the poor.
Tepper said the AG estimates retailers overcharged Massachusetts residential consumers $253 million in the three years ending June 2018. The study found that low-income customers were twice as likely as others to choose a competitive supplier and that they paid a half-cent more per kilowatt-hour on average than other competitive shoppers.
This is not a case of a “few bad apples,” Tepper said, citing findings that 10 retailers, who held 63% of residential accounts, were responsible for 75% of the overcharges.
About 55% of households in the state receive basic (default) service from their electric distribution company, while 20% purchase from a competitive supplier and 24% via municipal aggregation — up from 19% a year earlier. The aggregation numbers are likely to grow further as the state’s two largest cities, Boston and Worcester, consider joining in.
Credibility Problem
Tepper said residential customers are being exploited because of their lack of knowledge and inability to negotiate contract terms. The state does not believe it can fix the problem through less severe rule changes, she said. Connecticut consumers overpaid by $46 million even after banning variable rates, she said, and efforts in Pennsylvania and New York to tighten rules resulted in three years of litigation.
“Restructuring has worked for lots of entities. It’s worked for commercial and industrial customers; it’s worked for municipal aggregation. It’s working to lower wholesale prices. But after 20 years of restructuring, now is the time to look back and say where is it working and where is it not working. And this — that 20% [purchasing direct from competitive suppliers] — is where it’s not working.
Chris Kallaher, senior director of government and regulatory affairs for retailer Direct Energy, acknowledged, “We admit that [competitive suppliers] have a credibility problem.”
But Kallaher said the AG’s office is using the wrong yardstick in measuring what residential customers are paying competitive suppliers against default service, which he said is below market because of cross subsidies. Kallaher said default service has no customer acquisition costs because new and moving customers are assigned to it automatically unless they opt for a competitor. Direct Energy said the AG’s pricing comparison did not account “for all of the types of products offered by the competitive supplier” versus the plain-vanilla standard offer.
“There’s a ton of retail costs that are not in the default service rate,” he said. “Costs which should be subject to competitive pressures: billing, customer service, collections, facilities. Everything else — everything we have to pay for — remains embedded in distribution rates and not subject to competitive pressures.”
Direct Energy was one of 12 suppliers identified by the Connecticut Office of Consumer Counsel (OCC) as charging at least 20% of their customers 50% or more than the standard offer. The OCC said the company overcharged almost 38% of its Eversource Energy customers and 42% of its United Illuminating customers.
Kallaher said he was unable to explain why the AG’s office found low-income customers paying more than others for competitive service. “We need to find out what’s going on. If suppliers are discriminating on the basis of low-income status, that clearly needs to stop,” he said. “All these other things are easily addressed.”
He said the state should remove remaining barriers to customers switching and get the distribution utilities out of electricity sales altogether.
Janet Gail Besser, executive vice president of the Northeast Clean Energy Council (NECEC), suggested low-income customers are more likely to be lured by competitive suppliers’ promised savings because the electric bill is a larger share of their household budget.
She also opposed the AG’s call for eliminating residential choice. “Yank the licenses of these suppliers [preying on the poor]. Make the penalty really drastic if they are doing this kind of thing. But don’t throw the baby out with the bathwater,” she said.
She disagreed with Tepper’s contention that residential retail competition had produced no innovation, citing community solar and residential solar leases for those unable to purchase solar panels. “That access to residential customers is absolutely critical to providing these services and to continue to have companies thinking of new ways to deliver services.”
Paul Gromer, CEO of Peregrine Energy Group, also supported a more targeted response, calling abuses of low-income customers “a discrete problem that can probably be addressed on its own.”
But he also touted municipal aggregation, which he said provides the benefits of competition while avoiding many of the risks because the municipality vets retailers’ savings and environmental claims. About 125 communities are participating in municipal aggregation in the state, some of them using it to provide funding for local renewable energy projects.
“It’s probably the most powerful tool a community has to meet its climate goals,” Gromer said. “A lot of communities in the state have very ambitious goals. As communities, they want to do more than the federal government is doing. They want to do more than the state is doing. But they’ve got limited tools with which to accomplish those goals. They don’t regulate the power plants. They don’t regulate the utilities. They don’t run the [Massachusetts Bay Transportation Authority]. They can’t tell people what kind of a car to drive. They can put solar on municipal rooftops and they can run programs like Solarize — all of which are great but have a small impact. Aggregation, on the other hand, can have a very big impact.”
Lexington, Mass., for example, is reducing community-wide GHG emissions from electricity by 20%. “Communities have no other tool that has that kind of impact,” he said. “Lexington decides to launch a program; 10,000 households and businesses are on a green-power product overnight. Cambridge launches its program: Another 40,000 are on green power.”
Tepper said if the Massachusetts legislature doesn’t ban residential retail choice, her office would like to see smaller fixes addressing low-income residents, auto-renewal practices and fixed teaser rates followed by higher variable rates.
Kallaher disagreed with all but the need for protections for low-income customers. Banning variable prices and auto-renewals and subsidizing default service “are things we think are just killing the market without actually addressing the underlying problems,” he said.
New Technologies
Besser said it is “tremendously ironic that we’re having this discussion about ending residential retail choice just as new technologies are becoming available to make it work better.”
She cited Sense, a monitor that can be connected to a home’s electrical panel to track energy use by individual devices.
“If Massachusetts and the New England states don’t figure out how to have the utilities deploying advanced metering, then we may see the utilities jumped over, because the competitive market will figure out ways to provide a shadow service or virtually the same service,” Besser said.
Advanced metering and other aspects of grid modernization were the subjects of the first panel of Friday’s roundtable, where Connecticut Public Utilities Regulatory Authority Chair Katie Dykes also endorsed Sense. “It’s great data for marital disputes,” she joked.
The session also featured Angela M. O’Connor, chair of the Massachusetts Department of Public Utilities; Martin Honigberg, chair of the New Hampshire Public Utilities Commission; and Rhode Island Public Utilities Commissioner Abigail Anthony.
O’Connor explained Massachusetts regulators’ approval of $220 million in spending for three electric distribution companies’ grid modernization investments. The investments include distribution management systems with advanced sensing and load flow analytics to improve EDCs’ visibility of the grid; volt-var optimization and distribution automation; and spending to help EDCs integrate distributed energy resources.
The Massachusetts DPU, however, rejected utility proposals for smart meter deployments, saying the customer benefits were uncertain and could result in high stranded costs if existing interval automatic meter reading (AMR) meters are replaced prematurely. Advanced meters will not optimize system demand without time-varying rates, O’Connor said.
Dykes outlined PURA’s initiatives in EDCs’ distribution system planning, distributed generation tariffs and pilot programs for grid-side system enhancements.
Honigberg said the New Hampshire commission’s staff will be issuing a report soon with recommendations for future actions, based on stakeholder suggestions and its research of other states’ efforts.
Anthony said the Rhode Island commission’s August approval of a modified settlement with National Grid included funding for a system data portal, upgrades to the company’s geographic information system and a program to separate distribution remote terminal units (RTUs) from transmission RTUs for the first year of the three-year rate plan. It also directed the utility and stakeholders to develop a long-term grid modernization plan and a business case for advanced metering functionality.
In addressing last week’s annual meeting of the Northwest & Intermountain Power Producers Coalition (NIPPC), PJM CEO Andy Ott made clear his RTO is still in the running to provide wholesale market services to the Western Interconnection, despite the dissolution of its partnership with Peak Reliability. (See related story, Western Regionalization ‘No-brainer,’ PJM CEO Says.)
After his speech before attendees, Ott sat down with RTO Insider for the second time this year to discuss PJM’s perspective on a Western market, this time in the aftermath of Peak’s decision to wind down its operations next year. (See PJM Chief Confident on Western Market Proposal.)
The interview has been edited for clarity.
RTO Insider: In a press conference last month, NERC CEO Jim Robb said he had heard Peak Reliability’s effort to develop a Western market characterized as a kind of a Hail Mary pass intended to maintain their financial viability. Would you agree with that assessment?
Ott: From what I understood from my conversations [with Peak CEO Marie Jordan], they were getting feedback that their costs for reliability services were above what others like [CAISO] or SPP felt they needed to charge. So I think Peak’s approach was if they were going to provide high-quality reliability services, they had to find a better way to pay for the other infrastructure needed to provide those services. Their constituency was saying if you would like to provide market services like others do, you may be a viable alternative. So [Jordan] was actually getting asked that question.
They were facing a cost structure that people were telling them was unsustainable, so their answer could’ve been, ‘We either fold the tent and more or less do the wind-down, or do something else.’ From a [different] point of view, some people thought it was a Hail Mary pass because it came so late in the discussion. The notion of bringing in someone like us who does markets, it was certainly doable, but for them, they couldn’t sustain that project for any length of time because they were facing cost pressures.
How unexpected was it that things fell apart as rapidly as they did after Peak made the announcement to pursue a market? Did that take you by surprise?
No. From our perspective, they’re going to have regional markets in the West. It’s just a matter of time and how they evolve. The thing we didn’t have in the West was the relationships with people, and we also didn’t have a real-time model that could be stood up fairly quickly. Peak brought both. We had the market expertise, but we didn’t have that, so it was a pretty easy decision for us to pair up with them. That said, once [Peak] introduced us, we were able to build our own relationships. And then the real-time model, based on my understanding, is going to become available to everybody, so I don’t see that as being a real challenge.
If all you provide is reliability services, there’s a certain overhead that’s required to do market operations, grid operations and reliability services. That infrastructure needs to be in place to do any of those three. If you build the infrastructure to do more than one of the three, then the costs for each one of those services per unit goes down. So what we’re saying is that we can’t be competitive in providing just reliability services, but if we could provide RC [reliability coordinator] services plus grid operations plus markets or some combination of those so that lowers the rate — because that’s essentially what [CAISO] is doing.
Does the balkanization of RC services in the West complicate things for PJM?
If you’ve talked to Jim Robb, I’m sure he’s told you this: Most folks on the reliability side preferred a single RC in the West. But it was obvious 18 months ago that Peak was saying, ‘I’ve got California and I’ve got Mountain West both telling us it’s too expensive,’ it was already going to be balkanized. I think the attitude in the West is that it’s too expensive to maintain the West-wide [RC] model because other folks want to do their own thing, so as you pull larger regions of the West out, the costs for everybody else goes up. So I think it’s inevitable that it becomes more regionalized. So for us, I don’t think it’s something we’re causing, we’re just observing it’s going to happen. It’s a fait accompli at this point. It obviously helps us because if people want to look at alternatives, then they will look at us.
You mentioned in your [NIPPC] speech that there’s interest [regarding PJM] in the Southwest, not so much in the Northwest. What entities in the Northwest have you approached?
If I’ve had conversations with folks, I’d rather not talk about that. I don’t feel comfortable. Suffice it to say, there weren’t many people in the Northwest that wanted to have conversations because they thought they already had a path forward. Hopefully that will change.
Compared with CAISO, most RTOs appear to have a different model of stakeholder engagement, with CAISO probably being the most staff-driven, and MISO and PJM, for example, being more stakeholder-driven. What advantages do you see in the latter model?
I think certainly in a Western context … who better to decide what the rules of the road should be than the actual stakeholders of the market? And I am a bit biased because that’s where I come from, but my people aren’t wise enough to drive. I mean we can provide services, we can consult, we can give them the analytics, but at the end of the day, the RTO is more or less a service provider, an information provider to stakeholders who make decisions with that independent information. I just think it’s a better model because it’s more transparent.
Occasionally we have to step in and do something controversial because our mandate is to have nondiscriminatory results, but I think 90% of the issues are resolved through that consensus, and I think it’s more healthy. And out here [in the West], if people feel they’re not being fairly treated and they don’t have any other option, how sustainable is that?
You talked in your speech about the relationship [between a new market] and the Energy Imbalance Market. What kind of complications would there be in having an overlay with that market?
This goes back to the mindset of folks saying, ‘Either I do EIM or I have to do this regional market, and I have to choose between them.’ And that was my point [in the NIPPC speech] — you don’t.
I mean, the only difference is whether you are participating in the EIM as a group or individually. If you’re participating as a group, then maybe you’ll have a say in how prices are formed, where today you don’t have a say.
If the California legislature won’t give up control [of CAISO’s governance], well then you’re having a peer-to-peer discussion and that goes to FERC. So the point is, if [CAISO] won’t change its price formation, then the entities outside will say, ‘We got together and we decided we’re going to price ramping this way, and we’re going to price hydro this way,’ and then you have to make those interact at the border. And so when we’re selling to you, you’ll pay our price, and when you’re selling to us, we’ll pay your price, and that’s interregional coordination.
The whole point is that market-to-market coordination creates huge efficiencies. In fact, you’d have higher levels of trade than you would with the EIM, because EIM is individual, so if one person creates a constraint on another person’s system, you have to stop. If you combine them together and say we’ll manage constraints together, we’ll have more throughput. So the whole notion out here that they have to make this choice between EIM or not is just fiction.
I hope they’ll go back and think about this notion of participating as a team or a group, banding together and then participating in the EIM, and then you can have a conversation about, ‘Well it doesn’t matter what California says about price formation, we have an opinion too. And if there’s a conflict, we’ll resolve it at FERC.’ And I know that scares some people, but my point is, who [is CAISO] going to trade with?
So it would be something like a joint operating agreement? That would be the relationship?
Yeah, it’s a market-to-market coordination joint operating agreement. There would be an agreement approved by FERC. This is not unheard of. This is the way everybody else does it. We have them with New York, MISO, [the Tennessee Valley Authority], with Duke [Energy], so it’s pretty standard.
I’ve talked with some in the Northwest who say the idea of applying the standard market design is outdated and not really applicable to the region. What do you think about that?
This is key: The market design has to adapt to the region, not the region to the design. So the whole mindset back in the day that you have a standard market design and we have to adapt to it was never going to work. In fact, we don’t even have that. There’s differences between MISO’s design and PJM’s design because of the regional structure.
But for the West, we’re not saying you have to take our design. Now there’s stuff we’ve learned where every place in the world there are certain key things — like economic dispatch — that are always going to work. But as far as hydro coordination out here, it’s a huge deal, so the market side has to adapt and let hydro coordination be a primary design criteria.
Is there a timeline you’re operating on in the West?
No, it really depends on the folks here. There originally was a timeline because Peak had a certain burn and had to have an answer by a certain date. But once Peak and PJM dissolved their relationship, there’s no timeline on our side. It’s what the region wants. And this is why we considerably slowed down and we’re talking to people at a more casual pace. My opinion is, the quicker the better for them.
UNION, Wash. — The California State Assembly bill intended to set CAISO’s regionalization in motion may have died in committee this past summer, but talk of an organized market for the broader Western Interconnection lived on last week during the annual meeting of the Northwest & Intermountain Power Producers Coalition (NIPPC).
“For the moment, it appears to me regionalization in the West is dead, at least from the CAISO perspective,” said Steve Rodgers, director of FERC’s Division of Electric Power Regulation-West.
“There’s not going to be regionalization anytime soon, it appears. Some states perceive that California has a desire to export its policies to other states. I’m sure nothing like that would ever happen,” Rodgers joked.
Rodgers noted that some California groups opposed to regionalization fear it will allow “free riders” in the rest of the West to take advantage of infrastructure paid for by California ratepayers, while some in other parts of the West worry about increased costs for their ratepayers.
“I had one experience back in the spring where in consecutive weeks I had two of these diverse groups come to meet with my staff to express their concerns,” he said. “I felt like saying, ‘You guys should get together, because some of these fears are not adding up.’”
Rodgers said that while FERC was closely monitoring developments around regionalization, it would not put pressure on any of the region’s players because “that surely would be the kiss of death” for the effort.
FERC Commissioner Richard Glick said that some California opponents of regionalization have argued that an “evil FERC is going to come in and they’re going to reverse California’s greenhouse gas emissions program.”
“First of all, at least with regard to the California ISO, we already do have a significant amount of authority. If we wanted to engage or use certain words that could inhibit California policy, I think we could do that, but I’m not saying we’re going to do that and we certainly shouldn’t do that,” Glick said. “And secondly, I think the evidence is out there already if you look at the other regions with RTOs that the commission is generally pretty deferential in terms of regional preferences.”
“We need a big bipartisan win, and I don’t think we’ll get it on carbon tax in the short term, but I’ll tell you a place where we can get it. We can get it on enhanced regional grid integration,” said Ralph Cavanagh, co-director of the energy program at the Natural Resources Defense Council.
Cavanagh recounted this summer sitting before the California Senate Judiciary Committee (which was pondering the regionalization bill), bracketed by the “extreme” left and right.
“I’m trying to get them to vote for a fully independent board for the California ISO, and there were howls of anguish from the extreme left in California on this because of a perception this was going to turn California over to the tender mercies of what is called the Trump FERC, without recognizing that the California ISO is fully regulated by the Trump FERC today,” Cavanagh said.
Cavanagh noted the bill passed the committee with Republican votes, which would have been key to passing it if it had gone to the State Senate floor.
“And I really hope to see that. I really hope to see Democratic and Republican majorities on a tough issue. It’s been controversial, and collectively the will of this room must be ‘We will not give up on this,’” Cavanagh said, addressing his NIPPC audience.
“I tend to agree that that is ideally a place where bipartisan agreement will emerge,” said Montana Public Service Commission Vice Chair Travis Kavulla, who noted he sits on the Western Energy Imbalance Market Governing Body.
“Even in the absence of a kind of fully packaged regionalization of an ISO, which would be ideal, I think you can incrementally build on the regional efforts that are currently underway,” Kavulla said. “Right now, you’ve kind of got a toolbox with only a Phillips-head screwdriver in it, but it would be nice to add some additional tools into the Western regional market.”
Kavulla said he was disappointed to see the tenor of the California debate over regionalization, but that it was “hilarious” to see the NRDC’s Cavanagh associated with regionalization proponent PacifiCorp.
“But, fundamentally, as a non-California Westerner, it’s simply inconceivable that you’d have a workable and productive market for electricity in this region in the absence of a jurisdiction that has half of its load,” Kavulla said.
Lauren McCloy, senior policy adviser to Washington Gov. Jay Inslee, noted the governor supported passage of California’s failed regionalization bill and understands that CAISO and regional stakeholders continue to work on enhancements to the EIM that “could pave the way for a more dynamic regional market in the future.”
“The governor also continues to advocate for resolutions to the two biggest issues for Washington stakeholders participating in these discussions: governance and fair valuation for hydroelectricity,” McCloy said. “In order for Northwest entities to join the regional market, they will have to have a decision-making role in how that market is run.”
McCloy reminded conference participants that Washington produces about a quarter of U.S. hydropower. In establishing a fair value for the resource, a market operator would need to recognize that hydropower “is not only emissions-free, but it’s also flexible and can be coordinated to complement other variable renewable resources such as solar and wind.”
FERC’s Rodgers said the EIM has been a “great success so far.”
“First of all, there’s been great benefits to date of over $400 million. Not only is that a large number, but that number is getting larger all the time as more and more entities join the EIM. The boundaries of the EIM are growing each year,” he said.
Rodgers also pointed out that the possible extension of CAISO’s day-ahead market could increase the benefits of the EIM, but that some observers are concerned it could prevent full regionalization.
NIPPC Executive Director Robert Kahn wrapped up the meeting with a healthy dose of skepticism on the issue: “NIPPC has been working to create an RTO/ISO since 2000, and we will continue to do so, but we’re not holding our breath.”
NYISO and PJM last month jointly filed a request with FERC for a waiver of their joint operating agreement (ER18-2442), Rana Mukerji, ISO senior vice president for market structures, told the Business Issues Committee on Wednesday while presenting the monthly Broader Regional Markets report.
The waiver would permit the two grid operators to add the East Towanda-Hillside tie line as a market-to-market (M2M) flowgate. If granted, it will enable PJM to conduct redispatch operations to control flows to the more restrictive rating on the New York side of the line without violating the PJM Tariff for a limited time while the RTO and NYISO work to develop a permanent solution.
NYISO and PJM have jointly filed a request with FERC to waive a portion of their JOA to allow the East Towanda-Hillside tie line to be added as a market flowgate. | NYISO
Mukerji also highlighted efforts to clarify the minimum deliverability requirements for external capacity from PJM into NYISO’s Installed Capacity (ICAP) market. The ISO will continue discussions of this topic with stakeholders at the Installed Capacity/Market Issues Working Group meeting this month, he said.
In August, the ISO briefed the BIC on proposed market design changes to improve the supplemental resource evaluation process for external capacity resources.
Improving Public Policy Tx Planning
The BIC approved revisions to improve the efficiency of the Comprehensive System Planning Process in the short term, including eliminating the requirement that the New York Public Service Commission issue an order before NYISO begins evaluating transmission solutions. Under the proposal, the PSC retains the ability to cancel or modify identified public policy transmission needs (PPTNs) prior to the ISO’s selection of the more efficient or cost-effective solution, which would halt the evaluation or result in an out-of-cycle process to address the modified need.
In one case, NYISO had to wait about five months before evaluating and selecting Western New York PPTNs, according to a report by Yachi Lin, senior transmission planning manager. Under the new process, the ISO would begin the process following completion of a viability and sufficiency assessment and if developers meet the necessary requirements to proceed.
NYISO has proposed related Tariff amendments and will seek approval from the Operating and Management committees this month before seeking board approval in November.
In addition, the ISO will clarify in the Tariff that the project description in the transmission interconnection application or interconnection request must match the description in the PPTN proposal or face rejection.
Technical Details
Within 60 days after a formal solicitation from NYISO, interested developers must submit both redacted and unredacted versions of their complete project proposal to satisfy the PPTN, submit identical proposals in the interconnection process and provide a nonrefundable $10,000 deposit and a $100,000 study deposit for each project.
NYISO will then post a brief description of the project proposals within five business days after the solicitation window closes.
The ISO will file the final viability and sufficiency report at the PSC, and within 15 days of the filing, each developer must confirm that it intends to proceed and agree to a system impact study.
Long Term
NYISO will present a long-term process design concept to stakeholders by the end of 2018 to improve its Local Transmission Owner Planning Process (LTPP); Reliability Planning Process (RPP); Congestion Assessment and Resource Integration Studies (CARIS); and Public Policy Transmission Planning Process (PPTPP).
Under the proposal, prior to issuing a formal solicitation, the ISO will hold a technical conference to get input from developers and interested parties on the application of selection metrics to the PPTN.
LBMPs Up 31% Year-on-Year
NYISO locational-based marginal prices averaged $38.70/MWh in September, down from $42.56/MWh in August but up 31% from the same month a year ago, driven by four days in early September in which the peak load topped 28 GW compared with no such days in September 2017, Mukerji said in his monthly operations report.
Year-to-date monthly energy prices averaged $45.75/MWh in September, a 29% increase from a year ago. September’s average sendout was 458 GWh/day, lower than 537 GWh/day in August and 437 GWh/day a year earlier.
Transco Z6 hub natural gas prices averaged $2.75/MMBtu, down about 8.3% from August and up 21.5% from a year earlier. Distillate prices climbed slightly compared to the previous month but were up 23.3% year-over-year. Jet Kerosene Gulf Coast and Ultra Low Sulfur No. 2 Diesel NY Harbor averaged $16.21/MMBtu and $16.08/MMBtu, respectively.
Total uplift costs and uplift per megawatt-hour came in lower than August, with the ISO’s 37-cent/MWh local reliability share in September down from 59 cents the previous month, while the statewide share climbed from -61 cents/MWh to -48 cents. Uplift, excluding the ISO’s cost of operations, was -11 cents/MWh, lower than -2 cents in August.
The Thunderstorm Alert (TSA) cost in New York City was 33 cents/MWh, more than double the 14 cents in August.
CARMEL, Ind. — MISO’s Independent Market Monitor last week pointed to other RTOs to illustrate the ineffectiveness of the coordinated transaction scheduling (CTS) between MISO and PJM.
Monitor David Patton told the Market Subcommittee on Thursday that the CTS between ISO-NE and NYISO includes an explicit waiver of uplift and transmission charges between them. As a result, the process last year yielded bids and offers of 700 MW in one direction and 400 MW in the other.
Patton has recommended that MISO remove transmission charges from CTS with PJM. MISO currently applies transmission charges to these transactions when they are offered, not just when they are scheduled, which the Monitor said discourage CTS offers and subsequent savings. (See 7 New Recommendations from MISO IMM.)
Patton admitted that the New England numbers weren’t as high as he’d like, but that it’s important that the coordination is used.
“CTS has basically completely failed between PJM and MISO. Quantities have fallen to essentially zero,” Patton said.
MISO and PJM launched CTS a year ago to allow market participants to schedule economic transmission transactions based on forecasted energy prices in the two RTOs. While CTS should have lowered the cost of serving load in both regions, it has not been used since mid-February because of the double transmission charges.
MISO will respond to the recommendation later this month, when it releases its formal response to the Monitor’s State of the Market Report.
Dynamic Line Ratings
The Monitor is also renewing calls for MISO to adopt dynamic line ratings that are adjusted based on weather conditions, opening up transmission lines for more capacity when temperatures are cooler.
“The hotter the temperature, the less electricity you want through the conductor,” Patton said. “Transmission owners have long recognized that there are benefits to different ratings. … Every additional megawatt you can flow over the line can help you ramp down a higher-cost generator and ramp up a lower-cost generator.”
Transmission lines are rated based on seasonal ambient temperature and wind speeds. Patton said that of MISO’s TOs, “almost none” submit upratings beyond seasonal limits.
Customized Energy Solutions’ Ginger Hodge asked the Monitor how MISO might incentivize TOs to offer dynamic ratings. “I think there are few that offer dynamic ratings because they introduce risk to their system,” she said.
Patton said TOs themselves can benefit from higher ratings. “This capability is valuable, and they should see an economic value from providing it,” he said.
NYISO on Thursday recommended steps to prevent certain wholesale market suppliers, designated as carbon-free in the New York Clean Energy Standard (CES), from collecting double payments for carbon-emission reductions that have already been captured by renewable energy credit contracts.
“The idea is to prevent these resources from benefiting from a change in [locational-based marginal prices] resulting from a carbon price,” said Michael DeSocio, the ISO’s senior manager for market design. DeSocio presented a report on the treatment of REC contracts to the state’s Integrating Public Policy Task Force (IPPTF), which met by teleconference.
NYISO proposes applying a carbon charge to wholesale market suppliers with active, fixed-price REC contracts with the New York State Energy Research and Development Authority that are based on a REC solicitation that began or was completed prior to the carbon pricing rules taking effect.
“I want to remind everybody that NYISO is not a party to any of these agreements, and we’re aware of resources only because NYSERDA has made us aware of them,” DeSocio said.
The proposal is limited to NYSERDA contracts because the ISO believes it has no authority to put conditions on out-of-state REC contracts, DeSocio said.
Wholesale market suppliers with such NYSERDA REC contracts are initially settled at the LBMP, including the carbon component. NYISO will then deduct the carbon charge from the supplier’s settlement based on the social cost of carbon and the real-time marginal emission rate for the supplier’s zone.
Marginal emissions rate by month for Load Zones F, G, J and K. | NYISO
“This carbon charge will be applied to the actual output of the resource based on the proportion of the REC contract to the nameplate capacity,” DeSocio said.
Generators designated as carbon-free under the CES, and whose NYSERDA REC contract has expired, will settle at the LBMP including the carbon component — and not be subject to a carbon charge. Zero-emission credits and offshore wind RECs are not included, as they have an option to adjust to changes in market conditions, he said.
‘Hard Squeeze’
Seth Kaplan of EDP Renewables said, “NYSERDA has entered into REC contracts for virtually all of the output of the facilities they contract with — that’s just what they do.” He suggested that NYISO check with NYSERDA about how much of the output it buys from projects.
Kaplan said the ISO “is assuming that RECs are carbon payments and that therefore there is a problem to be solved.” He referred to an updated Brattle Group analysis showing a minimal effect of carbon pricing on pre-2020 RECs, with actual customer costs of 4 cents/MWh in 2020 and 2 cents/MWh in both 2025 and 2030.
“It raises a very serious question of whether the hard squeeze that you’re putting on companies that have taken risk and moved forward under REC contracts is worth the juice that comes out of the bottom of the orange, [and] of whether this is an enormous effort that would produce, as I believe [Brattle’s Sam] Newell said, nearly invisible impact, and whether this is really worth the trouble,” Kaplan said.
Kathy Slusher, director of energy procurement and utility regulatory affairs for the State University of New York, said the university system has a campus that will put a bid request out for 150,000 RECs, representing 150,000 MWh of energy in a “ready commodity market.”
“However this is going in NYISO would interrupt that market and would really throw everything for renewables in New York up in the air because none of us could sign a [power purchase agreement] because we don’t know if we’re going to get RECs, what value they would have, or if they’d be able to be sold,” Slusher said. “Sorry … but I think NYSERDA punted this over to [NYISO] and it doesn’t belong in your court.”
To the extent that there’s a secondary market for RECS, the ISO doesn’t know about it or seek to administer some clawback, DeSocio said.
Weird Dynamic
Anne Reynolds, executive director of the Alliance for Clean Energy New York, said that not considering REC sales elsewhere “does raise a weird dynamic.”
“If you’re saying the generators can’t sell their RECs to NYSERDA and still realize the carbon charge revenue increment, but they can sell them to someone else … there’s no logical reason for that, and it illustrates again that a REC payment and a social cost of carbon are not the same thing,” she said.
Reynolds also spoke of the perception among some industry participants that the Public Service Commission addressed the grid operator’s responsibility regarding RECs in a state proceeding, “but the fact is that petition [Case No. 15-E-0302] has never been answered by the commission; it’s an open petition. In the offshore wind order [Case No. 18-E-0071], there was discussion of the issue, and one sentence that said, ‘it might be more appropriate for the ISO to take on this issue’ or something like that, but there was no ordering clause from the commission telling the ISO to solve this problem.”
She also said the utilities are acquiring RECs through value of distributed energy resources (VDER) payments and that VDER projects are getting LBMPs that include the carbon charge increment. She noted that some VDERs qualify as Tier I renewables (for example, a community solar project getting the value stack and exporting to the grid) and utilities can use those RECs to meet their Tier I obligations.
Warren Myers, Department of Public Service director of market and regulatory economics, said the utilities can use such RECs for compliance: “They’re not tradeable RECs, but they can use them to satisfy their Tier I REC requirements.”
ICAP Demand Curve and Net EAS Revenues
Ryan Patterson, NYISO associate for capacity market design, presented a report recommending that any carbon charge in the wholesale market should be rolled into net energy and ancillary services (EAS) revenue estimates through the existing annual update process.
Carbon pricing impacts the capacity market through the ICAP demand curves. | NYISO
The ISO analyzed the impacts of carbon pricing on the installed capacity (ICAP) demand curves to illustrate how the annual update process could affect future capacity market clearing prices, finding that net EAS revenue will be impacted by a carbon charge.
Increasing carbon prices and LBMPs will likely impact both cost and revenue, Patterson said. The net EAS revenue offset values and the reference point have an inverse relationship: as net EAS revenue increases, the reference point decreases, and vice versa.
In the last ICAP demand curve reset process, the ISO moved to a historic model that averages projected net EAS revenue over a three-year period preceding the new ICAP demand curves taking effect. The study period ran from Sept. 1 of Year 1 through Aug. 31 of Year 3, using actual historic data such as LBMPs and fuel and emission costs.
The 2017/18 ICAP demand curves used net EAS revenue offset values measured from Sept. 1, 2013, to Aug. 31, 2016, and the ISO implemented an annual update process that allows for specific variables used in calculating the reference point to be recalculated each year between the quadrennial resets.
Changes to the reset process implemented in 2016 were intended to allow for the ICAP demand curves to capture changes in market conditions over time, including the impacts of changes to market rules. Adjustments to the net EAS model to allow for incorporation of a carbon charge will be evaluated as part of the upcoming reset process, Patterson said.
Two datasets were used to run several scenarios, Patterson continued. The first was 2015 and 2016 marginal emissions rates (MER) prepared by Brattle, under which the LBMP was increased by $50/MWh and, to account for the carbon price change, the Regional Greenhouse Gas Initiative price was increased by $50 for hours that LBMPs were adjusted for carbon pricing.
The second dataset was derived from modeling and pricing software (MAPS) runs for 2020, 2025 and 2030, in which LBMPs were output for carbon and no carbon base cases, and then fed into the net EAS model along with projected fuel costs used in each respective MAPS run. As with the previous dataset, the RGGI price was increased by $50 for the carbon cases.
No stakeholder asked questions about the net EAS revenue impact analysis, but Brett Kruse of Calpine said he would like to make a presentation to the IPPTF on Oct. 22 on the issue of how a carbon charge might affect hedges on transmission congestion contracts.
IPPTF Chair Nicole Bouchez, the ISO’s principal economist, shared a revised schedule that foresees the task force meeting on the remaining Mondays this month, collecting stakeholder feedback in November and presenting a formal proposal on carbon pricing Dec. 17.
RTO Insider will have coverage later this week of the task force’s Monday meeting at NYISO headquarters.
