FERC on Monday placed an Iowa wind farm’s method for calculating reactive power rates into question, although it declined to initiate a blanket probe into similar NextEra Energy rate filings.
The commission said NextEra Energy Resources’ Crystal Lake II wind farm in north-central Iowa may be improperly including operations and maintenance costs and transmission-related expenses in its reactive power rate schedule. It set the facility’s rates for hearing and settlement proceedings (ER20-2543).
Crystal Lake II said it now requires slightly more than $1 million per year in reactive power revenue. The facility is designed to provide reactive power, and its turbines have been churning since 2012.
Nearby Interstate Power and Light (IPL), an Alliant subsidiary, raised objections to Crystal Lake II’s rate schedule, arguing that it is unacceptable for asynchronous generators to use the reactive power rate methodology FERC established in 1999 for synchronous generators. IPL said the filing was “one of a series of filings by subsidiaries of NextEra to establish charges for reactive service.” The utility asked the commission to consolidate and investigate all similar filings by NextEra subsidiaries.
FERC said a preliminary analysis of Crystal Lake II’s proposed rates showed they could be unjust and unreasonable. The commission said a consolidation of other NextEra filings was beyond the scope of the proceeding but said that IPL “may raise its concerns regarding how the proposed revenue requirement has been calculated in the hearing and settlement judge procedures.”
Crystal Lake wind farm | NextEra Energy
For its reactive power charges, Crystal Lake II included the costs of low-voltage collection system feeders and low-voltage transformers, which aggregate the output of individual wind turbines. The collection system costs include some substation costs.
IPL argued that collection system costs aren’t necessary for synchronous generators’ production of reactive power and therefore aren’t contemplated by FERC’s 1999 methodology. The utility also said the equipment costs can’t be completely dedicated to reactive power production.
“The allocation of accessory electric equipment costs to the production of reactive power has not been shown to be just and reasonable and appears excessive,” IPL said.
The company also charged that Crystal Lake II was expecting to be compensated for transmission-related system losses, though FERC’s methodology only allows traditional generation’s heating losses to be recovered. “Wind-powered generators do not experience significant heat-related losses in the production of reactive power,” it said.
The utility said FERC should “consider balancing the requirement to provide reactive power with the need for reactive power in a particular locale or region.” It said that FERC “should not simply assume that, because a generator is able and willing to provide reactive power, that this reactive power is needed for reliable and efficient operation of the electric system.”
NERC’s Standards Committee is accepting nominations through Oct. 15 to replace nine members who will depart at the end of the year, as well as to fill three spots that are currently vacant.
The Standards Committee comprises the chair and vice chair, along with two representatives from each of 10 industry segments, with memberships staggered so that half of the representatives are replaced each year. This year’s departing members are:
Segment 1, transmission owners: Sean Bodkin, Dominion Energy;
Segment 2, RTOs and ISOs: Charles Yeung, SPP;
Segment 3, load-serving entities: Linn Oelker, LG&E and KU;
Segment 4, transmission-dependent utilities: Barry Lawson, National Rural Electric Cooperative Association;
Segment 5, electric generators: William Winters, Consolidated Edison;
Segment 7, large electricity end users: Venona Greaff, Occidental Chemical;
Segment 8, small electricity users: David Kiguel, independent; and
Segment 10, regional reliability organizations and regional entities: Steven Rueckert, WECC.
In addition, the committee is looking to fill vacancies for the term that ends December 2021 in segments 4 and 7, so nominations will be accepted for these spots as well. In the election, the candidates in those segments with the most votes will be given their choice of terms, with the other term going to the runners-up.
Nominations are also being accepted for Segment 9 (Federal, state and provincial regulatory or other government entities). Currently the segment is only represented by Ajinkya Rohankar of Public Service Commission of Wisconsin, whose term ends in December 2021.
The committee is required to have at least two members from Canada — currently Kiguel and Robert Blohm of Keen Resources, who will leave at the end of 2021. If the regular election does not result in the seating of another Canadian representative, then the Canadian candidate who receives the most votes in their segment will be named as an additional member.
Nominees may be submitted by anyone, with the election to be conducted “shortly after the nomination period is closed.” Industry segments that intend to use a special procedure to elect their representatives must inform the committee by Oct. 15.
Special Election to Fill RSTC Seat
The Reliability and Security Technical Committee is also holding a special election to fill a vacancy in Sector 8 (Large end-use electricity customers). The nominating period ran from Aug. 28 to Sept. 18, with Travis Fisher, president and CEO of the Electricity Consumers Resource Council (ELCON), and Thomas Siegrist, a consulting engineer with Stone Mattheis Xenopoulos & Brew, making the final ballot. Voting began on Sept. 21 and will end at midnight Oct. 5.
Like the Standards Committee’s, members on the RSTC serve staggered two-year terms. Occidental’s Greaff (2020-2022) and former ELCON CEO John P. Hughes (2020-2023) were elected to represent Sector 8 in January; NERC has not identified which is leaving. (See Nominations Close for At-Large RSTC Members.) The winner of the special election will serve out the departing member’s remaining term.
Stronger federal leadership and changes to wholesale electricity market rules are needed to supplement New England’s decarbonization efforts, Massachusetts Secretary of Energy and Environmental Affairs Kathleen Theoharides and Katie Dykes, commissioner of Connecticut’s Department of Energy and Environmental Protection, told Raab Associates’ New England Electricity Restructuring Roundtable.
Theoharides and Dykes were the keynote speakers at the virtual event Friday, which drew an audience of more than 450 people.
There has been “no hint of politics in the way we approach this work,” Theoharides said about Massachusetts, whose Republican Gov. Charlie Baker committed the state to a target of net-zero emissions by 2050.
Theoharides said one approach to meeting that goal is the Transportation and Climate Initiative (TCI), a collaboration of 12 Northeast and Mid-Atlantic states and D.C.
TCI would set a limit on carbon dioxide emissions from diesel and gasoline vehicles and allow states to invest proceeds from the sale of carbon allowances to support the goals of the program, such as electric vehicle chargers and electric buses.
The initiative estimates a cap that cut emissions 25% from 2022 levels by 2032 would produce $10 billion in public health benefits (2017$) while covering almost three times the Regional Greenhouse Gas Initiative cap, which includes the New England states, New York and more recently New Jersey and Virginia. Transportation represents 43% of emissions in the TCI region, and total transportation-related carbon emissions are nearly twice as large California’s, Theoharides said.
Clockwise from top left: Katie Dykes, Connecticut DEEP; Jonathan Raab, Raab Associates; and Kathleen Theoharides, Massachusetts EEA. | Raab Associates
TCI expects to finalize a memorandum of understanding setting its targets this fall, when each jurisdiction will decide whether to sign the MOU and participate.
“It is a capital investment program,” Theoharides said. “It is a point of regulation far upstream from the consumer at the wholesale or fuel-supplier level. Credits would be auctioned off in each state, and the proceeds would go back into the states, much as they do in RGGI, to invest in clean transportation solutions that give people the option to choose transportation that reduces air pollution and that provides mobility for more residents.”
Amid the COVID-19 pandemic, TCI has the potential to reduce the public health impact of environmental pollution significantly, Theoharides added.
“The pandemic has highlighted the connections between air pollution and respiratory diseases, and TCI is a way to ensure sustained investment in transportation that gives people better, more affordable choices for getting to work, school and health care services while cutting the pollution that makes people sick and makes them more vulnerable to disease,” Theoharides said.
Connecticut has pledged to cut carbon emissions by 80% from 2001 levels by 2050 and 100% in the electricity sector by 2040. Dykes said it is “long past the moment for significant changes in the wholesale electricity markets to ensure that Connecticut can either secure the resources that we need to meet our clean energy goals in-market, or that we can get credit for what we have had to procure outside of the market in order to meet our goals.”
Dykes said a “unified approach” is needed to meet the decarbonization mandates.
“We are not even in an acceptable place in terms of having a proactive transmission planning process that ensures adequate competition in our RTO,” Dykes said about ISO-NE. “For the transmission investments, when you look at the dollars spent per mile deployed, New England is at the bottom of the heap in terms of providing … value for our ratepayers. Transmission service costs are more than twice the average of other RTOs and ISOs.”
Dykes thinks that improving the transparency and accountability of ISO-NE and institutions like the New England Power Pool that are “core to the design and implementation of our wholesale markets” is a “necessary and essential step” to achieve affordable decarbonization that uses competition and minimizes risk to ratepayers. She said the current structure reflects that states do not have adequate input and accountability in the design and structure of the RTO’s governance.
Moderator Jonathan Raab said both Massachusetts and Connecticut have plans and policies in place to meet “really bold decarbonization mandates.” He then asked Theoharides and Dykes if New England states can be “fully decarbonized without strong complementary federal action on numerous fronts” and what the federal government could or should do to facilitate the region’s decarbonization efforts.
Dykes said the impact of climate change on the economy and public health is “accelerating faster than we had anticipated.” She said there is a severe disconnect between states and the federal government, which, Dykes said, is “walking away or even making our climate progress more difficult.”
“We have companies in a private market that can accelerate and deploy climate solutions so quickly and cost-effectively,” Dykes said. “I think the tragedy of all this disconnect at the federal level is that it’s preventing the incredible strengths and advantages of our country from being applied at the scale that we need to solve this climate crisis.”
Theoharides added: “It matters that we have a target as a nation we’re shooting for; it’s not just a handful of states which have mandatory emissions targets; we need a federal target, and we need every state to be pulling its weight to get us there. That leadership needs to come from the top.”
Decarbonization Takes the Whole Village
The conference’s second session featured a four-person panel with representation from local and state governments plus a global nonprofit and think tank. The presentations touched on some of the same topics that Theoharides and Dykes broached earlier and delved into job creation and the social justice aspects of decarbonization.
Hal Harvey, CEO of Energy Innovation, said it is not true “that one has to sacrifice economic vitality in order to have a clean environment.” The financial upside of clean energy is good jobs, lower costs and less local pollution, he said. There were 3.3 million clean energy jobs in the U.S. at the start of 2020, representing more than 40% of the energy workforce, Harvey said.
“The fastest two growing careers in America are solar installer and wind installer,” Harvey said. “The opportunities do not require college degrees. … Roughly half of Americans do not have a college degree; we need an energy strategy that gives them great jobs.”
Hannah Pingree, director of policy innovation and future for Maine Gov. Janet Mills, said the first-term Democrat had made climate progress one of her top agenda items, especially in job creation.
“Maine is embarking right now on an offshore wind project, trying to launch the first floating turbine in the next couple of years, so obviously that’s one of the many exciting things we think could bring jobs and economic prosperity,” Pingree said.
Clockwise from top left: Eugenia Gibbons, Health Care Without Harm; Chris Cook, city of Boston; moderator Jonathan Raab; Hal Harvey, Energy Innovation; and Hannah Pingree, Maine Governor’s Office of Policy Innovation and the Future | Raab Associates
While climate change can drive job creation, Chris Cook, chief of environment, energy and open space for the city of Boston, said it also affects socially vulnerable populations. One of the city’s major initiatives this year is creating Community Choice Electricity, which was recently approved by the Massachusetts Department of Public Utilities. The program will allow the city to buy electricity for residents and businesses through its combined buying power to provide affordable and renewable electricity to those who participate in the program.
“If we provide a clean economy [and] a decarbonization pathway that doesn’t expand equity opportunities for our most socially vulnerable residents, then we will have failed,” Cook said. “It’s not about what we do. It’s about who we do it for. They are our neighbors; they are our friends. They are the people that we are charged with at the city level to take care of, and they need to be actively part of the solution.”
Eugenia Gibbons, Boston director of climate policy for Health Care Without Harm, a global nonprofit that works to reduce the health care sector’s environmental footprint, said climate solutions like decarbonization must benefit historically marginalized communities.
“Essentially we are coming from a place of understanding that climate justice will only be achieved if policies that are enacted bring about concrete improvements in the health and lives of communities that continue to bear the burden of environmental and climate pollution,” Gibbons said. “Equity absolutely has to be a factor in designing, implementing and evaluating policy and program solutions. Otherwise, the disparity will just be perpetuated and exacerbated.”
In the absence of federal leadership, “we absolutely have to demonstrate at the state and local level what is possible and what we are capable of achieving [and] ensure that we are not leaving anybody behind when we move forward with this pathway to decarbonization,” Gibbons added.
When Raab asked the panel for closing thoughts, Harvey said 2020 is an inflection point.
“If we use this decade well, we can land at a reasonable climate future, but this is the decade that matters. This is where we have to stop all new fossil installations, period, and much more rapidly change the direction that we are on,” he said. “I can say now it’s cheaper to save the Earth than to ruin it, because it is. We better get busy, because if we don’t do it this decade, it isn’t going to happen.”
More than 60% of New Yorkers said they approve of NYISO’s carbon pricing plan after learning of the advantages of such a price in the state’s wholesale electricity markets, according to a poll released by the ISO on Monday.
A joint task force between NYISO and the state’s Public Service Commission issued a proposal last December that would use the social cost of carbon (SCC) as a baseline for such a price.
The poll conducted by Siena College Research Institute (SCRI) showed how an informed opinion increased support for carbon pricing.
When respondents were initially asked about NYISO’s proposal, 47% said they were in favor, 36% opposed and 17% expressed no opinion. But after respondents were informed of the plan’s benefits — including replacement of polluting power plants with cleaner generators and the economic boost from adopting clean technologies — support grew to 62% and opposition fell to 27%, while 11% had no opinion.
“At least a plurality of every demographic found each of these potential outcomes making it more likely to support” carbon pricing, SCRI Director Don Levy said.
The SCRI poll shows broad support for New York getting 70% of its electricity from renewable sources by 2030 and increasing to 100% zero-emitting sources by 2040. | SCRI
NYISO released the poll two days before a technical conference on carbon pricing at FERC.
“We view this poll result as a validation of New York’s efforts to develop an innovative solution to the state’s renewable energy goals,” CEO Rich Dewey said in a press conference.
The fact that FERC invited him to testify at the technical conference along with Rana Mukerji, the ISO’s senior vice president for market structures, shows that carbon pricing is “increasingly recognized” as a vehicle to transition the power industry toward renewable energy, Dewey said.
Asked what he hoped to accomplish at the technical conference, Dewey said, “These investments are going to be made in renewable resources. He wants FERC “to understand and accept that a state policy element, appropriately designed and controlled, fully transparent and open, does have an effective place in helping markets position themselves to achieve those goals as efficiently and as effectively as possible.”
The commission earlier in September rejected the ISO’s proposal to make it easier for public policy resources to clear its capacity market, specifically helping those resources in New York City and capacity zones G-J to avoid buyer-side mitigation if enough existing capacity exits the market, or if demand increases enough to boost capacity requirements. (See FERC Rejects NYISO Bid to Aid Public Policy Resources.)
CAISO last week won FERC approval for its second effort to implement market rule changes to allow generators to recover the costs of higher natural gas prices (ER20-2360).
The changes emerged from CAISO’s Commitment Costs and Default Energy Bid Enhancements (CCDEBE) initiative. FERC rejected an earlier filing by the ISO in 2019, saying its generous multiplier for gas resources was neither fact-based nor warranted.
CAISO’s revised plan, which eliminated the multiplier, measured up, FERC said.
“We find that CAISO’s CCDEBE proposal will allow resources that face high gas costs resulting from inter-day variation in natural gas prices to reflect those costs in their reference levels,” FERC said. “By reflecting the actual costs of these resources in reference levels, CAISO’s proposal will facilitate a more efficient dispatch of its system.”
The ruling was one of two that FERC issued Sept. 21 involving CAISO’s efforts to comply with Order 831.
Issued by FERC in 2016, Order 831 requires ISOs and RTOs to raise the hard caps on supply bids from $1,000 to $2,000. Offers over $1,000 require suppliers to justify their costs. It’s meant to allow supply resources, especially gas generators, to earn prices sufficient to recover their operating costs during periods of high demand, thereby helping to ensure reliability.
To comply with the order, CAISO proposed revising its Tariff with a two-tier bid cap structure. The plan includes a soft cap of $1,000/MWh — which would apply to all energy bids except for virtual bids and those for non-resource-specific system resources — and a hard cap of $2,000/MWh, which would apply to all energy bids.
CAISO’s Department of Market Monitoring objected, arguing that the ISO’s proposed provision regarding verification and recovery of minimum load cost bids was unclear and unsupported.
FERC dismissed the objection and said the revisions complied with the requirements of Order 831, subject to a further compliance filing to update certain eTariff records (ER19-2757).
“We find that, as required by Order No. 831, CAISO’s Tariff revisions proposed herein and reflected in the 2020 CCDEBE proposal set forth the process for CAISO to verify that a resource’s bid above $1,000/MWh reasonably reflects that resource’s actual or expected costs,” FERC wrote.
‘Natural Gas Price Volatility’
In the cost-recovery ruling, FERC said it had rejected CAISO’s 2019 CCDEBE proposal because the ISO failed to show that it was just and reasonable to apply a 125% multiplier to commitment cost bid caps derived using supplier-submitted costs.
“Specifically, the commission stated that ‘whereas a multiplier applied to an index captures deviations from an average cost, and therefore may account for resource-specific cost deviations from the index, a multiplier applied to supplier-submitted costs would provide additional headroom on top of verifiable actual costs’ and that CAISO had not provided sufficient evidence to support this upward adjustment,” FERC wrote.
PG&E’s natural-gas fired Colusa Generating Station | PG&E
In its revised proposal, CAISO altered its methodology, including eliminating the multiplier from its plan. Instead, it submitted changes that let suppliers request adjustments to their ISO-calculated commitment costs — their start-up and minimum load costs — and to their energy-price reference levels to more accurately reflect their costs.
“CAISO asserts that the proposed revisions will provide a just and reasonable method for verifying a supplier’s request to increase a resource’s reference levels when its actual or expected costs will be greater than CAISO-calculated costs based on verifiable contemporaneously available information,” FERC wrote.
“CAISO explains that these procedures will enable it to use fuel or fuel-equivalent prices in calculating reference levels that reflect suppliers’ actual or expected fuel or fuel-equivalent costs,” it said. “CAISO contends that this, in turn, will provide CAISO with more efficient resource schedules and dispatches and will ensure that suppliers are adequately compensated.”
FERC agreed with CAISO’s assessment.
“CAISO’s proposal to adjust the reasonableness threshold in response to inter-day fuel price increases in a fuel region, and in response to persistent conditions faced by a resource, will … ensure that its markets accurately reflect natural gas price volatility, which in turn will result in dispatching resources more efficiently,” FERC said.
“Additionally, we find that CAISO’s proposal to exclude existing commitment cost and default energy bid multipliers from the calculation of a resource’s adjusted reference level is just and reasonable and addresses the concerns that led to rejection of the 2019 CCDEBE proposal,” it said. “Under CAISO’s proposal in this filing, reference level adjustments will be based on a resource’s actual or expected costs and will not provide additional headroom above a resource’s verifiable actual or expected costs.”
Maine’s sunshine will soon provide more than just lighting for viewing the fall foliage.
The Maine Public Utilities Commission last week announced a procurement of renewable energy, and solar developers were the clear winners, claiming 14 of the 17 projects selected. It is the PUC’s largest procurement of renewable energy since restructuring more than 20 years ago.
The selected projects were evaluated through a competitive bidding process based on expected value to Maine’s consumers and economy. Solar will account for 482 of the 546 MW of the approved projects, with wind (20 MW), hydroelectric (4.5 MW) and biomass (39 MW) making up the remainder.
The biggest projects are Swift Current Energy’s 100-MW solar farm in Hancock County, which signed a term sheet with Versant Power, and Granite Apollo’s Canton (65 MW) and Roxbury (55 MW) projects, which signed agreements with Central Maine Power.
Maine currently has about 93 MW of solar power, according to the Solar Energy Industries Association, ranking it 43rd among states.
PUC Chairman Philip Bartlett told RTO Insider that this process “reflects just how much renewable energy potential there is in Maine and the benefits to Maine’s economy from moving forward aggressively.”
Thomas College solar roof in Waterville, Maine | Coastal Enterprises
Winning bidders estimated the projects would reduce greenhouse gas emissions by approximately 500,000 tons per year. They have also committed to providing more than 450 full-time jobs during the construction phase and more than 30 full-time-equivalent positions in each operational year.
“It’s really important that as we are transitioning to a clean economy that we recognize the important economic benefits to Maine people and the jobs that can be created,” Bartlett said. “I think it’s certainly beneficial that there’ll be a lot of jobs during the construction phase as well. That will help at a time when the economy is struggling, so hopefully, the combination of those things will have a meaningful long-term impact.”
The projects promise more than $145 million in initial capital spending. In addition, the ReEnergy Livermore Falls biomass project will generate payments to Maine-based contractors for the harvest of wood fuel averaging $11 million to $12 million annually during the 20-year contract term.
“I think that’s an indication of how strong a market signal this was, and we’re excited about this procurement, which is the first to not just look at the price that comes with these projects, which in this case was very competitive, but also look at the economic benefits,” Dan Burgess, director of Gov. Janet Mills’ Energy Office, told RTO Insider. “It’s pretty innovative to have those built-in directly into the contracts and the term sheets; I think it’s a guaranteed positive impact for an economy.”
The first-year energy prices for the 15 new projects awarded term sheets ranged from $29.75 to $40/MWh, with a weighted average price just under $35/MWh.
These projects are the first since Mills signed legislation last year to increase the state’s renewable portfolio standard to 80% by 2030 and set a goal of 100% renewable energy by 2050.
Another round of procurement bids for renewable resources is due in mid-January, and developers that were not initially selected can enter again. The two procurements must equal 14% of the state’s 2018 retail electricity sales. The awards announced last week represent 9.4% of 2018 sales.
The Energy Bar Association’s Canadian Chapter held its first annual meeting online Thursday, with discussions on cybersecurity and holding virtual adjudication hearings amid the COVID-19 pandemic.
The chapter, formed a year ago, was originally going to hold the meeting in D.C. in April, at the same time as the EBA Annual Meeting, but it was forced to reschedule it in an online format because of the pandemic. (See EBA Holds Annual Meeting Online Successfully.)
Here’s some of what we heard.
Challenges of Cybersecurity on the Distribution Side
David Morton, chair of the British Columbia Utilities Commission, opened the conference with an anecdote about visiting the U.S. Department of Energy for a briefing on cybersecurity earlier this year (before the pandemic hit).
There were two briefings that day: one for those with top secret security clearance and those without. Morton attended the latter, “but I’m not sure it would have made any difference,” he said.
“I couldn’t even tell anybody about it anyway. … I had to sign and swear I wouldn’t share [the information he received] with anybody when I brought it back to my commission,” Morton said. “So, what am I supposed to do with that information? How can I even apply it to any of the work that I do?”
Clockwise from top left: Mary Anne Aldred, Ontario Energy Board; BCUC Chair David Morton; EBA Canadian Chapter President Gordon Kaiser; and Louis Legault, Régie de l’énergie du Québec. | EBA
Morton also pointed out that NERC’s mandatory reliability standards only cover the generation and transmission side of the electric industry, leaving the distribution side vulnerable. “If you took out the distribution system in Greater Vancouver, that’s just as bad as taking out the transmission system, at least to the 2.5 million residents in Vancouver,” he said.
“I do think it would be appropriate to raise the bar somewhat on standards,” said Alex Foord, chief information officer for Ontario’s Independent Electricity System Operator. “The larger entities … are going to come along and do the right thing. The challenge is when you get into smaller [utilities] … they don’t have the expertise, the sophistication and the time to do it. But candidly, that’s no excuse for the lack of action; they owe it to their consumers to do better.”
Cintron Shares Experiences with Virtual Hearings
FERC Chief Administrative Law Judge Carmen Cintron gave attendees a candid behind-the-scenes look into how she transitioned the commission’s Office of Administrative Law Judges from in-person to virtual hearings after the pandemic hit.
The pandemic “caught me, to use an American expression, with my pants down. We had modeled for the whole United States being under a nuclear attack; we had modeled for hurricanes; we had modeled for everything, except a pandemic,” she said.
FERC Chief ALJ Carmen Cintron | EBA
The office was immediately able to transition to virtual settlement conferences, which aren’t as complicated as hearings, Cintron said. Its settlement success rate has actually risen to 92%, from its usual 89%. “We attribute this to the fact that the business entities, the decision-makers, can actually participate without having to travel” to D.C.
Meanwhile, Cintron postponed imminent hearings until the office’s IT department set up Cisco’s Webex platform and the ALJs trained in using it and practiced by simulating hearings. The first virtual hearing began May 6 and lasted 16 days. One of the parties filed a motion to halt the proceeding, arguing that its virtual nature was a violation of due process, but it was denied by Cintron.
Though she said the process has been an overall success — with even the party that filed the due process motion responding favorably after their hearing was over — Cintron said it has not been without challenges, mostly owing to technical problems. It was immediately clear from her opening remarks that she is not a fan of Webex, and later in the discussion, she said she wants to migrate to Microsoft Teams. The different parties’ varying degrees of computer proficiency and internet bandwidth were early frustrations. ALJs also needed to obtain up to three separate computer monitors in order to conduct hearings in their homes.
Cintron said she anticipates the online-only format to continue into next year. Even once the crisis ends, she expects hearings to be a mixture of in-person and virtual.
ERCOT staff told stakeholders last week they are working to reduce errors following two recent unrelated events that led to price corrections and resettlements.
Kenan Ögelman, ERCOT’s vice president of commercial operations, shared with the Technical Advisory Committee the speaking points he will deliver to the Board of Directors during its Oct. 12 meeting. He said the grid operator has several initiatives that will cut down on errors and price corrections and will also elevate testing, “which is kind of our last line of defense.”
“We’re making additional revisions and [instituting] controls around market changes that impact pricing,” Ögelman said during the TAC’s meeting Wednesday. “We’re reviewing all of our manual processes … especially around resettlement items.”
Ögelman said several revision requests are being drafted to address the problem. ERCOT is also evaluating protocol language to address recent discussions the Public Utility Commission has had in open meetings. While discussing a telemetry error that led to a price correction Sept. 14, PUC Chair DeAnn Walker said, “We shouldn’t wait for there to be a really huge event.” (See Texas PUC Rejects Call to Reprice Error.)
In February, staff updated the network model by adding dynamic ratings for three transmission transformers. A software error erroneously applied the new ratings to three unrelated 345/138-kV transformers in addition to the intended transformers. ERCOT didn’t discover the cause of the error and the affected transformers until July, when it issued a market notice.
Staff reviewed all binding transmission constraints in the day-ahead market between Feb. 14 and July 7, finding 67 operating days that had at least one constraint binding on one of the transformers. They also found one instance of binding transmission in the real-time market.
Staff will ask the ERCOT board to review day-ahead and real-time prices for the June and July operating days that are eligible for repricing, as required by the grid operator’s protocols. David Maggio, ERCOT’s director of market design and analytics, said the pricing changes were “fairly minimal,” but balancing account changes resulted in an overpayment to load of about $8,000 for June and an underpayment to load of approximately $15,000 for July.
The real-time constraint resulted in a net settlement to counterparties of almost $47,000.
More recently, a manual update to the network model inadvertently disabled a remedial action scheme for four day-ahead market operating days in August. Staff were able to correct the prices before they became final during the last day and will ask the board to review the other three operating days.
Members Reject Ancillary Service NPRR
Members rejected a Nodal Protocol revision request (NPRR1025) that would remove the real-time online reliability deployment price (RDP) from ancillary service imbalance calculations. The measure was approved by an 18-10 margin, with two abstentions, but its 64% approval fell short of the two-thirds threshold for endorsement.
ERCOT’s Independent Market Monitor reiterated its opposition to the NPRR as written, citing what it said were two flaws.
“The first, and most important, is that it breaks a foundational principle in the market, that dispatch sent out by ERCOT should be the most profitable dispatch, given their offers and limitations. With this NPRR, in times of high ERS [emergency response service], that won’t be true anymore,” the IMM’s Steve Reedy said.
“Secondly, the [operating reserve demand curve] adder calculation is not affected by the ERS deployment,” he said. “That weight is carrying right now by the RDP adder. If you take that away from resources … that should raise the ORDC adder. We would support this with those associated indifference payments, which would be smaller than the megawatt implications in effect right now.”
The NPRR was drafted by the Lower Colorado River Authority. John Dumas, the public utility’s vice president of market operations, said it was driven by the divergence between the value of real-time reserves and day-ahead ancillary service prices during ERCOT’s 2019 energy emergency alerts, caused by including the RDP in the price of real-time reserves.
“LCRA believes that only the ORDC adder should be included in the price of real-time reserves,” Dumas said. “This removes what we believe is an undue risk to loads and generators for participating in the day-ahead ancillary service market. It removes the real-time deployment price adder and removes risk and cost.”
2% Solution: Monitor to Draft NPRR
Based on discussions with TAC leadership and the IMM, the Monitor will draft an NPRR to address a desk procedure left over from ERCOT’s zonal market, Ögelman said.
Several stakeholders had suggested such action when staff brought forward a discussion of the “2% rule” to the August TAC meeting. An artifact from the zonal market, which was replaced by the nodal market in 2011, the rule says generating units with shift factors of less than 2% should not be dispatched by the real-time market in response to transmission overloads. (See ERCOT Technical Advisory Committee Briefs: Aug. 26, 2020.)
The IMM in August said it believes the 2% rule should be eliminated and all congestion priced in real time, regardless of generation’s effect. “Prices matter,” IMM Director Carrie Bivens said during the discussion.
“I presume [the Monitor will] be putting the [shift-factor] percentage at zero, and we’ll see how that progresses,” Ögelman said. “Stakeholders can modify that as they see fit.”
He said ERCOT will take a position on the issue when comments are filed.
Under the rule, if a transmission constraint exists for which there are no generator shift factors of at least 2%, ERCOT operators must verify that a mitigation plan or temporary outage action plan exists for the contingency, and they are to review the plans with the affected transmission owner. If no plans exist, then the operators are to develop a mitigation plan with ERCOT’s operations support engineer. If no plans have been developed within 30 minutes, the operations desk issues a transmission watch, a step down from an emergency.
TAC Adds 10 Change Requests to List
TAC Chair Bob Helton complimented the committee for its virtual work this year, noting that it has passed 79 revision requests, with 65 more in the pipeline, while working from home.
“That says a lot about how we’ve progressed in troubled times,” Helton said.
The committee then passed a combination ballot, with an abstention, that added 10 more RRs to the approval list.
In a separate vote, the TAC approved the annual update to the major transmission elements list. Four members abstained from the vote.
One of the endorsed changes, a revision to the Planning Guide, will likely be appealed during the October board meeting. The change (PGRR077) clarifies that ERCOT’s transmission planning analysis will assume DC tie flows are curtailed when necessary to meet reliability criteria.
Shams Siddiqi, with Rainbow Energy Marketing, said the current $23/MWh transmission charge for DC tie exports during summer off-peak hours is a significant barrier to exporting energy. It also suppresses the market’s opportunity to address the allocation of sunk costs, adversely affecting decisions to consume or export, he said. Only the Public Utility Commission can modify the DC tie export’s Tariff, he said.
“Until and unless the PUC eliminates or significantly reduces the DC tie export tariff, the only equitable treatment of DC tie load is to treat DC tie load as other load in the ERCOT reliability transmission planning process,” Siddiqi said in filed comments. “If the PUCT were to eliminate the DC tie export tariff … [it] would remove an inefficient barrier to trade.”
Staff told Siddiqi he could appeal the revision request when it comes before the board next month. Helton noted that at least one PUC commissioner will call in to the meeting.
“If parties or stakeholders want to do it, they can file a petition for a rulemaking at the PUC,” said Katie Coleman, who represents Texas Industrial Energy Consumers. “The issue of transmission allocations is a really old issue that’s come up multiple times. I think the PUC is aware of these issues and can address them, if [it] wants to.”
The combo ballot included six other NPRRs, two changes to the Nodal Operating Guide (NOG) and a system change request (SCR):
NPRR999: Revises protocol language on DC tie schedules and creates a section related to ramp limitations on DC ties. It is intended to clarify that when ERCOT determines system conditions show insufficient ramp capability to meet the sum of all DC ties’ scheduled ramp, it will curtail schedules on a last-in, first-out basis. Before curtailing DC tie schedules, ERCOT, with enough time, may request one or more qualified scheduling entities to voluntarily resubmit e-tags with an adjusted ramp duration.
NPRR1033: Specifies that ERCOT does not have an obligation to pay interest on former market participants’ cash collateral balances upon its determination that financial security is no longer needed to cover the terminated participant’s potential future obligations.
NPRR1035: Requires ERCOT to publish all DC tie schedules 60 days after the operating day.
NPRR1036: Clarifies some processes associated with late payments and payment breaches and aligns protocol language on market participants’ registration and qualification with language in the standard form market participant agreements.
NPRR1037: Corrects switchable generation resources’ (SWGRs) settlement when instructed to switch from a non-ERCOT control area to the ERCOT control area. The NPRR includes the SWGR’s operational costs in the non-ERCOT control area in calculating switchable generation operating cost for resources with approved verifiable costs.
NPRR1038: Establishes a limited exemption from reactive power requirements for some energy storage resources (ESRs). The exemption is available only to an ESR that achieved initial synchronization before Dec. 16, 2019, and applies only to the extent the resource is unable to comply with the reactive power requirements when it is charging. To qualify, the ESR’s operator must submit a notarized attestation to ERCOT that says the ESR would be unable to comply with the requirements without making physical or software changes.
NOGRR214: Describes ERCOT’s process for collecting geomagnetically induced current monitor and magnetometer data to satisfy requirements of NERC Reliability Standard TPL-007-3 (Transmission System Planned Performance for Geomagnetic Disturbance Events).
NOGRR218: Removes the requirement that disturbance-monitoring equipment owners annually submit their databases to ERCOT.
SCR811: Adds a predicted five-minute solar ramp to the resource-limit calculator’s formula for calculating the generation-to-be-dispatched value. The solar ramp rate will be calculated from the intra-hour PV power forecast and the short-term PV power forecast.
New York’s investor-owned utilities are working with government officials and project developers to fine-tune the processes and contract terms of state-mandated energy storage solicitations.
Approximately 60 energy storage developers participated Thursday in a technical conference hosted by the New York State Energy Research and Development Authority (NYSERDA), anonymously questioning a panel of three utility executives on matters such as expanding timelines for requests for proposals beyond the current six months; extending payment terms and contract duration up to 10 years; modifying in-service dates out to 2025; reducing the storage duration requirement from four hours to one; and providing developers the option to sell a project to the utility upon completion.
The New York Public Service Commission’s December 2018 storage order required Consolidated Edison to procure at least 300 MW of storage capacity and each of the other utilities (Central Hudson Gas and Electric, New York State Electric and Gas, Niagara Mohawk Power, Orange and Rockland Utilities, and Rochester Gas & Electric) to procure at least 10 MW each, with assets to be operational by Dec. 31, 2022, on contracts up to seven years.
The RFPs started in 2019 and are to continue annually as needed to meet individual utility storage goals. New York state now has about 93 MW of advanced energy storage capacity deployed with 841 MW in the pipeline toward meeting its goal of 1,500 MW deployed by 2025 and 3,000 MW by 2030. The 1,400 MW of traditional pumped hydro storage in the state does not count for the goal totals.
Stephen Wemple, Con Edison | NYSERDA
Each utility has conducted its initial RFPs and is developing the next round of solicitations after having notified bidders of first-round results.
“We’re looking for feedback from the participants during this session as well as through a follow-up email [with comments due Oct. 8], and this will culminate in a filing with the commission, which will allow for more formal comments for commission action,” said Stephen Wemple, Con Ed vice president of regulatory affairs. The next round of RFPs is expected in the second quarter next year.
The PSC on Sept. 17 modified dynamic load management implementation plans for the six utilities, all related to storage, saying the initial plans “resulted in a bias towards short-term, low-capital investment solutions” because of their yearly performance structure (18-E-0130). (See “DLM Incentives Extension,” NYPSC Accepts CLCPA Environmental Review.)
Time and Negotiations
The feedback indicated that six months is very compressed for an RFP, from posting to final selection, and that developers need more time; whether a month or more is yet to be determined, said James Mader, manager of smart grid programs at NYSEG.
Mader addressed these questions: How does the current process flow? Does it start with bidders who have potential projects, or does the RFP require those opportunities to be concrete and ready to go?
“The current process was you’d look at the RFP and submit your bid once you received bidding approval, and then we would analyze and review what we received,” Mader said. “Moving forward, that’s something we’re looking to potentially tweak or adjust.”
The RFPs also required developers to have site control and to have applied for their interconnection agreement, which utilities factored into the viability of a project, Wemple said. “We want to go through a process; we want to select bidders that are well positioned to deliver and complete their projects in the time frame required.”
The first round of RFPs “was a learning experience for everybody, and the idea is to have a value-based bid cap — what is the utility actually going to get — and developers are going to give their best proposal in there,” said Schuyler Matteson, senior energy storage project manager at NYSERDA.
“For the utilities who are still under contract negotiations, and that includes Con Ed, we hope to make an announcement in the near future. … We don’t want to bias those negotiations, but there were a couple of utilities that did not have any finalists,” Wemple said. “I know that included my affiliate O&R.”
Jeffrey May, CHGE | NYSERDA
Central Hudson also reported no bidders that met the bid ceiling, while NYSEG said it was still in negotiations. National Grid did not take part in the panel but did participate in the conference planning and had a manager listening in, Matteson said.
Utilities received feedback that high pre- and post-commissioning security requirements increased bid prices; large upfront payments caused difficulties with financing for some developers; and annual payments did not cover operations and maintenance costs.
“From our perspective, we didn’t see anything that really jumped out at us to indicate that one offer or another was assuming things that were significantly different from anyone else,” said Jeffrey May, energy resource manager at Central Hudson. “To speak to the spread in pricing, there was nothing obvious to us that indicated a driver as to why some bids might have been significantly higher than others. … There were no offers that met the bid ceiling, so maybe if we had gotten into a deeper dive, we might have seen where some of those differences were, but there was nothing on the surface from our evaluation matrix.”
Tech Specs and COD
Utilities determined that a commercial operation date of Dec. 31, 2022, is not feasible for resources being procured in 2021 and proposed to move the date out three years to year-end 2025.
One question on that issue was whether the utilities could begin payments if a project comes online ahead of the date set by regulators. Wemple said Con Ed would.
Several developers provided feedback that uncertainty in the post-contract market led to attributing little or even negative value to merchant “tail” years, and that extending the contract duration from seven to 10 years would spread costs over a longer period while increasing potential contract revenue.
Developers said that removing the four-hour duration requirement would bring in a wider range of bids and address concerns related to buyer-side mitigation issues.
“I think the expectation is that a shorter-life battery, while perhaps not getting as much or any capacity value, could make up for it on its relative ‘less cells to pay for’ by providing regulation or other ancillary services,” Wemple said.
New York City’s Demand Response and Load Management Programs with Con Edison rely on real-time metering for analysis of energy usage. | NYSERDA
One commenter said that requiring a maximum number of cycles over the course of a year might be a good way to give bidders a sense of how the storage asset might be used.
Another commenter was concerned about “trying to align the NYISO class year process with knowing what the NYISO assignment of system upgrades are, because that impacts interconnection costs.”
“Hopefully we’ll get a little better clarity from the ISO on what their timing for the next class year process will be, and at least try to see if we can work that into this [RFP] process,” Wemple said.
One proposed revision to the RFP process would let the developer provide O&M services for a defined period (e.g., five years) and to mitigate uncertainty in post-contract market revenues by having the developer sell the project to the utility at the COD.
One developer asked whether the utilities are sure they can own storage in the first place.
“Certainly, with a commission order … the commission can allow us to do lots of different things, and actually in many cases, we already own storage as part of prior non-wires solicitations,” Wemple said.
MISO and SPP have once again failed to identify any beneficial cross-border transmission projects after a fourth interregional study.
RTO executives broke the news during a virtual meeting of the MISO-SPP Interregional Planning Stakeholder Advisory Committee (IPSAC) on Friday. Stakeholders were unsurprised by the announcement after already hearing indications that the fourth coordinated system plan (CSP) study would be fruitless. (See MISO, SPP Close to Ruling out Joint Projects Again.)
“All the work that we put into the study, I feel like it’s a building block for future studies,” SPP’s Neil Robertson told stakeholders, adding that the studied flowgates would most likely show up in future interregional studies.
This year the RTOs focused on 10 routinely congested flowgates in Minnesota, Iowa, Nebraska, Kansas, Missouri, Oklahoma and Arkansas.
“I fully anticipate that we’ll be seeing these constraints again,” Robertson said, citing expanding renewable generation flows between the RTOs. “The increase in interregional flows are only trending one way, and that’s up.”
MISO and SPP planners said the RTOs’ transmission planning futures scenarios — both updated this year — will probably yield larger project benefit ratios in future joint studies.
The study also turned up discrepancies in the RTOs’ separate project cost estimates, Robertson said. The grid operators will work together to produce more consistent cost estimates in the future, he said. (See SPP Seams Steering Committee: Sept. 17, 2020.)
“We intend to reach a lot more consensus about how cost estimates are determined in the interregional studies. Cost estimates are essential … to figuring cost-benefit ratios, and we’re going to make sure they’re not a roadblock in future studies. I want to stress that this will be a priority,” he said.
Congested flowgates studied under the 2020 CSP | MISO, SPP
Robertson noted that MISO and SPP haven’t worked out exactly how they’ll make their cost estimates line up better.
“The local [transmission owners] have a perspective; the RTOs have a perspective; even the stakeholders have a perspective. Those are the things you have to kind of talk out,” he said.
However, Robertson stressed that differing cost estimates didn’t prevent any project candidates from “crossing the finish line” this year.
“Cost estimates were not the determining factor in a project not getting approved,” he said.
The Advanced Power Alliance’s Steve Gaw asked if the RTOs suffer from a process issue in which they’re not examining solution candidates thoroughly enough.
Robertson said MISO and SPP studied more project candidates than the 34 they presented to stakeholders.
The RTOs have somewhat assuaged stakeholder concerns by announcing a new joint study targeting generation interconnection challenges. (See MISO, SPP to Conduct Targeted Transmission Study.) That study could yield new transmission capacity and thus facilitate development of the renewable generation in the RTOs’ interconnection queues.
Robertson said MISO and SPP have yet to determine the scope of the study, the geographic areas to be studied or whether the study will affect the possibility of a 2021 CSP study. The RTOs plan to hold an annual issues review in the first quarter of 2021 where they will discuss possible needs for transmission solutions.
“All of those questions are yet to be answered. … We’ll share details as soon as we possibly can,” Robertson said. “But please keep in mind that the vast details of the study have yet to be determined.”
MISO Director of Planning Jeff Webb said he expects study results to roll in at the end of 2021.
Stakeholders have repeatedly asked how this study will differ from MISO and SPP’s CSP studies.
“I think that’s a fair question. We’ll have to lay that out more clearly at the kickoff meeting,” Webb said at the MISO Planning Advisory Committee’s meeting Wednesday, though he added that the study will target needs for interconnecting generation, something the CSP studies don’t consider.
