LAS VEGAS — Stakeholders in CAISO’s Western Energy Imbalance Market last week reacted coolly to a proposal by Utah’s Deseret Power Electric Cooperative to tighten the market’s rules on transmission feasibility.
Deseret made the proposal during a Dec. 3 Regional Issues Forum panel that explored the differences between resource sufficiency and resource adequacy.
Don Tretheway, CAISO’s senior adviser for market design, said the difference is mainly timing.
“Resource adequacy is ensuring, on a forward basis, that you’ve contracted with sufficient steel in the ground so that you can meet your monthly peaks, your annual peaks. It’s really about … making sure that you can serve your load,” Tretheway said. “Resource sufficiency evaluations [are] a series of tests to ensure that someone’s not inappropriately leaning on an energy imbalance market [to meet demand] on a short-term basis.”
Four tests are conducted several times per hour to ensure an entity has met the agreed-upon threshold for participating in the EIM, Tretheway said, including a transmission feasibility test to determine if a participating entity has sufficient transmission capacity or unresolved transmission congestion. A balancing test determines if an entity’s actual load is within 5% of its base-schedule load for that hour, according to the ISO. A capacity test makes sure an entity has sufficient resources to meet its projected load, and a ramping test looks at ramping flexibility in 15-minute increments.
Clay MacArthur, vice president of power marketing at Deseret, said the EIM should adopt rules to address a loophole in the feasibility test that may allow entities to inappropriately spread around (socialize) the costs of congestion.
The transmission feasibility test, he said, determines if electricity can reach load within a particular balancing area. “It’s just a simple test that looks for congestion on the system,” he said.
The EIM’s design allows for the socialization of unforeseen congestion constraints within a given hour, but MacArthur said that’s not the problem. The feasibility test, he said, doesn’t account for an entity that knows it has transmission constraints but fails to report them ahead of time.
“They can just submit a base schedule that ignores that,” MacArthur told RTO Insider.
If an EIM entity knows of transmission constraints and includes them as part of its base schedule, it will bear the costs, MacArthur said. But if it doesn’t report its pre-existing constraints, the EIM’s market design can inadvertently shift the costs of those constraints to other load-serving entities across the market via neutrality charges. “If my schedules were balanced and somebody came into the hour with a known transmission infeasibility, why should I pay a share of that?” MacArthur said. “I can’t do anything to mitigate that.”
He proposed tariff language requiring EIM entities to “ensure that all financially binding base schedules submitted to the market operator are feasible and do not violate any known or expected transmission constraints.”
If they do, then the EIM would be required to notify the entity and give it a chance to revise its base schedule. If the entity doesn’t, then it may be subjected to congestion offset charges, the proposal says.
MacArthur called for greater market transparency by releasing suffiency test results and neutrality charges to market participants. That would allow for an objective evaluation of whether the market has a problem, he said.
MacArthur said he just meant “pass or fail” and “ones and zero,” without divulging privileged information.
His proposal prompted sometimes heated discussion between panelists and audience members, though not much agreement with MacArthur’s proposal.
Kelcey Brown, PacifiCorp’s manager of market and analytics, acknowledged her company had been a party to the problem described by MacArthur during the EIM’s early years, after starting operations in 2014, when utilities were still going through a learning curve. But she said the company put safeguards in place to ensure it wouldn’t happen again. She said she didn’t know of other examples.
“I’m not sure this is as big of an issue as Clay is referring to,” Brown said.
Petar Ristanovic, CAISO vice president of technology, agreed. “I don’t understand your concern, sir,” he told MacArthur.
MacArthur said the only way to determine the problems’ extent would be to have the information he’d asked for.
For about 30 minutes, panelists and audience members held a back and forth, trying to clarify or argue points.
At the end of the panel, Pam Sporborg, the new chair of the RIF, thanked the panelists “for a lively discussion,” and the audience responded with hearty applause.
MacArthur said that as the transmission customer of an EIM entity, Deseret couldn’t formally request further proceedings. CAISO could do that on its own, he said, or Deseret could file with FERC.
“That may be the only way to get it addressed,” he said.
VALLEY FORGE, Pa. — PJM Board of Managers Chairman Ake Almgren recognized fellow board member and interim CEO Susan Riley for her efforts to lead the RTO during a “challenging” season, telling the Markets and Reliability Committee on Thursday her work will continue under her successor, Manu Asthana.
“We are very excited to welcome Manu as our new president and CEO,” Almgren said. “He brings many decades of experience from the electric industry. Some were different experiences, but very relevant experiences. We are confident in his leadership moving PJM forward.”
Riley will resume her role on the board once Asthana arrives next month and will help ensure a smooth transition, some six months after former CEO Andy Ott resigned.
“Overall, I’m proud of the progress PJM has made to build stronger relationships with constituents, built on common respect and listening,” Riley said. “I know this great work will continue under Manu, and the board is anxious for him to start.”
FTR Vote Deferred
The MRC deferred voting on the first round of financial transmission rights credit-related policy changes after some stakeholders expressed concerns about the ripple effect the revisions may have on market design.
PJM said the recommendations, initially presented at the October MRC, will improve its credit risk policies after the Financial Risk Mitigation Senior Task Force delegated a more holistic FTR market review and possible design changes to a separate Market Implementation Committee task force. (See “FTR Market Rule Changes,” PJM MRC Briefs: Oct. 31, 2019.)
One change includes hosting five long-term FTR auctions a year, instead of three, in order to increase oversight and visibility into portfolio conditions so that more collateral can be collected if necessary. A second would alter the structure of Balancing of Planning Period auctions so that participants can buy and sell in any month of the year, rather than being limited to a specific quarter.
The PJM Industrial Customer Coalition (ICC) and the Consumer Advocates of PJM States (CAPS), however, said their longstanding concerns about increasing the auction frequency still stand.
“We think the monthly change bleeds into the market design element,” the ICC’s Susan Bruce said. “We’ve not fully thought through the impact of FTR underfunding. If we don’t have good information on transmission outages, we have concerns that it may affect underfunding and it may have implications for market design.”
“The advocate offices had very similar concerns,” said Greg Poulos, executive director of CAPS. “This is one item that has a little bit of impact on market design, something that consumer advocates have been asking to be reviewed since last year when the GreenHat [Energy] investigation was going on.”
PJM Chief Risk Officer Nigeria Poole Bloczynski reiterated that the independent GreenHat investigation recommended these very changes and said the task can revisit the issue, if needed.
“This is not a one-stop shop,” she said. “We will continue to make improvements.”
Riley chimed in, urging stakeholders to find consensus, saying, “If we could get to ‘yes’ on this, it would be a really big win.
“We thought long and hard about design changes versus credit changes,” she said. “I agree this straddles the two. I understand the concerns. Voting in favor of the increase in auctions enables better credit management. … It doesn’t mean that a review of this can’t be a part of market design changes that we consider.”
The MRC will reconsider the changes at its Dec. 19 meeting.
End of Life Issue Charge Endorsed
American Municipal Power and Old Dominion Electric Cooperative scored a big win on Thursday after stakeholders in a sector-weighted vote of 3.83 to 1.17 endorsed their joint problem statement and issue charge exploring end-of-life determinations.
While stakeholders rehashed a familiar debate before casting their votes over where PJM’s role in supplemental project planning should begin and end, the committee ultimately approved formalizing the discussion. (See Competitive TOs Push Against PJM Supplementals and “Stakeholders Mull Tx Asset Management Discussion,” PJM MRC Briefs: Oct. 31, 2019.) None of the 11 TOs voting endorsed the issue charge, according to PJM’s tally.
The MRC will continue working on the issue and recommend approval for any necessary governing document changes at its March meeting.
Comparative Cost Framework, Opportunity Cost Calculator in Flux
The MRC did not endorse revisions to the opportunity cost calculator or hear another first read of its pending comparative cost framework.
In the former issue, main motion sponsors Dominion Energy and Panda Power Funds are working toward a single-package compromise with PJM. (See “Opportunity Cost Calculator,” PJM TOs Wary of Cost Containment Rules.)
Real-time Values, Parameter-limited Schedules
Some capacity generators use real-time values (RTVs) to override unit-specific parameters for inappropriate reasons, PJM contends, causing unnecessary confusion during dispatch.
The original intent of RTVs was to provide a way for generation operators to communicate current operating capability to PJM if their resources couldn’t meet their unit-specific parameter limits or approved exceptions. Generators opt to use RTVs and forfeit operating reserve credits and make-whole payments as a result.
Except, some generators consistently use RTVs to increase notification time on parameter-limited schedules “to reflect the decision not to staff the resource during hours they project the resource will not be economic,” PJM said in a problem statement. The operational impacts mean that resources called in real-time based on their schedules cannot perform as expected.
PJM suggested a special session of the MIC to commence in 2020 to study the problem and recommend solutions.
Manual 03A: Energy Management System Model Updates and Quality Assurance — revisions stemming from a cover-to-cover periodic review and is phase one of an effort to update, reorganize and streamline the manual’s content.
Manual 13: Emergency Operations — revisions to incorporate the 2020 day-ahead scheduling reserve requirement.
Manual 15: Cost Development Guidelines — revisions that clarify that market sellers can only change the format of maintenance adders ($/MMBtu, $/MWh or $/start) during the annual review period for energy offer components. (See “Manual 15 Clarifications on VOM Costs,” PJM MIC Briefs: Nov. 13, 2019.)
PJM Manual 19: Load Forecasting & Analysis — a periodic review and documentation of the long-term load forecast.
Operating Agreement revisions that clarify the requirements for sharing forecasted unit commitment data to TOs for reliability studies.
Non-substantive changes to the Tariff, OA and Reliability Assurance Agreement that standardize cross references in all three documents.
Members Committee Elections
Members Committee Chairman Chuck Dugan, of East Kentucky Power Cooperative, led his last meeting Thursday before Vice Chair Steve Lieberman, of American Municipal Power, takes over next year.
Katie Guerry of Enel X will assume the role of MC vice chair. Brian Kauffman, also of Enel X, will take over as whip for the Other Supplier sector. Members also re-elected all existing whips, including:
Susan Bruce, PJM ICC, End Use Customers
Adrien Ford, Old Dominion Electric Cooperative, Electric Distributors
Michael Borgatti, Gabel Associates, Generation Owners
Sharon Midgley, Exelon, Transmission Owners
Load Management Test Rules
PJM’s new load management testing rules became official on Thursday after receiving endorsement from the MC.
In October, the MRC endorsed new load management and price-responsive demand testing rules for Capacity Performance resources after PJM said old measures failed to mimic real-life emergency procedures. (See PJM Stakeholders Support More Realistic DR Testing and “Stakeholders Urge Consensus on Load Management Testing Requirements,” PJM MRC/MC Briefs: Sept. 30, 2019.)
The new rules, effective with the 2023/24 delivery year, would give PJM authority over scheduling tests — instead of the resource itself — and provide advanced notification so participants can prepare. The changes would implement a three-step system that gives resources first notice of an upcoming test one week prior to the two-week testing window, with additional alerts by 10 a.m. the day before and the day of the scheduled test. There will be one test per year when there is no event, with half of resources tested in winter and the other half in summer.
Critical Infrastructure Resolution
Growing concerns over a pending Tariff attachment proposal from TOs that would create a new, confidential process to mitigate critical infrastructure reached a crescendo on Thursday when LS Power presented the first read of an advisory against the proposal.
Sharon Segner, vice president of LS Power, said her company believes the attachment conflicts with the OA because it will move forward without any vetting from the MC.
“We can’t veto or delay, but we can offer an opinion,” Segner said of the advising document. “It’s a voice that says the issues with the OA haven’t been addressed.”
At the heart of Segner’s argument is a belief that incumbent TOs don’t get exclusive rights to handling critical infrastructure on NERC’s CIP-014 list. Because the projects could carry significant regional implications, LS Power believes PJM should plan their mitigation. (See PJM TO Filing Stirs Up Transparency Concerns.)
“My company stands on the side of PJM,” she said. “My company believes that PJM is a world class transmission planner and, as a result of that, when it comes to national security, we believe PJM should be in charge.”
Incumbent TOs argue that NERC’s confidentiality standards — and their rights under PJM’s Attachment M-4 process — support their intention to file the mitigation plan at FERC without input from other sectors.
“There is no inconsistency between Attachment M4 and the OA,” said Pulin Shah, director of transmission strategy and contracts for Exelon. “The M4 process is not permanent. It will sunset in five years. There is a compelling need to move forward to address the loss of these substations.”
PJM maintained its neutrality in the debate and reiterated that all stakeholders agree about mitigating critical assets so they are no longer vulnerable to attack. (See PJM Remains Neutral in CIP-014 Debate.)
WASHINGTON — Last week was a busy one for the Solar Energy Industries Association.
The trade association held its annual policy summit at the Washington Plaza Hotel on Wednesday, on the eve of both the International Trade Commission’s midterm review of the Trump administration’s tariffs on imported solar panels and a Court of International Trade ruling affirming the exemption of bifacial modules from the tariffs.
On Thursday morning, SEIA held a rally outside of the trade commission’s headquarters in D.C., calling upon “solar workers, advocates and anyone passionate about fair solar trade policy” to attend and show support for ending the tariffs.
But Wednesday’s summit acted as a rally of sorts as well, as the solar investment tax credit expires at the end of this year, and legislation to extend it faces stiff competition for congressional attention amid impeachment proceedings and a Dec. 20 deadline to fund the government.
SEIA President Abigail Ross Hopper and keynote speakers urged attendees to be more active in contacting their representatives in Congress, particularly if those representatives are Republican.
The event opened with a speech from U.S. Sen. Catherine Cortez Masto (D-Nev.), who in July introduced the Senate version of a bill that would extend the tax credit for another five years. (The House version was introduced by Rep. Mike Thompson (D-Calif.)
“I need your help,” she said. “I need your help with some of my colleagues on the other side of the aisle. … Just make the call, if you haven’t already. They don’t need to publicly sign onto to the bill. … Just ask them to reach out to Mitch [Senate Majority Leader Mitch McConnell (R-Ky.)] and tell him why this is so important; why this needs to be passed; why this needs to be part of the package at the end of the day.”
Hopper echoed Cortez Masto’s call to action before she began her own speech, noting that she has found people in the industry to be timid when it comes to calling their representatives.
Many of the panels that followed focused on the best ways to lobby Republicans on solar energy policy. Speakers told their own success stories and described the gradually changing political landscape around renewable energy and climate change as encouragement for attendees.
Brandon Audap, vice president of government relations for Citizens For Responsible Energy Solutions, spoke about his efforts to lobby Republicans on climate change. His organization focuses only on trying to convince the GOP to enact “responsible, conservative solutions” to solve the problem.
As SEIA’s former director of federal affairs, Audap worked on the first tax credit legislation. Though “Republicans are more engaged on climate change,” there is no unified party stance on it, so his organization has had to canvas every elected official in Congress (250) individually, he said.
The good news for the industry: “The era of the Republican climate denier is coming to an end. It’s a dying breed. I could name a handful of serious climate deniers still.”
The bad news: “Don’t get me wrong. There’s plenty of guys who talk about climate change but have no intention of ever doing anything or advancing clean energy or tax credits.” He described a conversation he had with House Minority Whip Steve Scalise (R-La.), who told him, “‘Basically our guys are comfortable talking about airplanes and cow farts’” to mock the Green New Deal, a proposed resolution by Rep. Alexandria Ocasio-Cortez (D-N.Y.). Scalise’s reference came from a draft FAQ accidentally released by Ocasio-Cortez’s staff and later retracted, which Republicans have seized on to claim Democrats secretly want to ban air travel and hamburgers.
Audap said Scalise continued to say that “‘we’re going to ring all the political hay out of the Green New Deal and then get around to doing some serious policy.’”
The Economy, Stupid
The key then, panelists said, is to focus on the economic benefits of solar rather than the environmental ones.
Boyd Brown, one of the three partners in lobbying firm Tompkins, Thompson & Brown, described his firm’s successful efforts earlier this year to get South Carolina’s Energy Freedom Act passed into law. Both houses of the state legislature unanimously voted to pass the bill after its introduction in January, and Gov. Henry McMaster signed it into law in May. Among the provisions supporting solar power, the law permanently eliminated any caps on net metering. It also requires utilities to consider offering neighborhood community solar programs and for their integrated resource plans to fairly evaluate solar-plus-storage investments.
Brown, a former Democratic member of the South Carolina House of Representatives, laid out the challenge the solar industry faces on the lobbying battlefield. “You got to start peeling back this onion legislatively in these states where utilities have had the ability to run roughshod over the landscape over the last half-century,” he said. “You guys are really new to the game. And these folks are entrenched.” During the battle for the Energy Freedom Act, “I think there were like eight registered solar lobbyists in South Carolina, versus 67 utility lobbyists. So it was really a David-versus-Goliath match.”
South Carolina is also a rural, deeply conservative state, and concerns about climate change do not resonate with its residents, nor with those in similar states, multiple speakers said.
But the bill was spurred by and benefited from “a groundswell of pure hatred, really, for Big Nuclear and Big Energy” after the failure of SCANA’s expansion of the V.C. Summer nuclear plant, for which customers were left on the hook, Brown said.
“I’m not sure the words ‘climate change’ ever came out of my mouth when I was lobbying legislators in South Carolina. We talked about ‘energy freedom’; we talked about consumer choices; we talked about free-market and fair-market principles,” he said. “We were like, ‘Where are … the free markets that Republicans are supposed to believe in?’ So we were really able to … build a coalition around Democrats who believed in protecting the environment and Republicans who believed in fair-market principles.”
Corey Schrodt, legislative director for Rep. Francis Rooney (R-Fla.), advised attendees to “always localize” data they use in their messages, such as how much money constituents would save or how many jobs would be created. “When people see the numbers, especially big jumps in numbers, it catches their attention.”
He also stressed that every call, email and letter from constituents to their representatives is logged by staff. Each week, members of Congress are given statistics on how many messages they received and what issues they were about. “When you call in, it does get tracked. I can’t speak for every office, but I know that most offices use that information to their advantage in how they contact, how they message their own constituents.”
“Just put your best foot forward,” Audap said. “Don’t feel like you need to convince them on climate change to get their support for solar. That’s frankly irrelevant in a lot of offices, even some Democratic offices.”
Brandon Presley, Mississippi Public Service Commissioner and new president of the National Association of Regulatory Utility Commissioners, said for many residents, it’s not a matter of whether they believe in climate change. As an elected official in a poor district, “I represent people that worry about tonight how they’re going to feed their children, and how they’re going to put gas in the van to get them back and forth to school. And if I’m talking to them about climate change, although that’s important to me … [I’m] not making headway” with his constituents on solar policy.
Next Steps
The Court of International Trade on Thursday blocked the Office of the U.S. Trade Representative’s decision to revoke bifacial modules’ exemption from the solar panel tariffs, ruling that the office had violated the Administrative Procedure Act by not providing notice or opportunity to comment on a proposed decision.
“This is an important temporary reprieve for the bifacial module exclusion,” Hopper said in a statement after the decision. “We will continue to make the case that the … tariffs are harming the U.S. industry and the American consumer and that the bifacial exclusion was a fair and reasonable solution to the problem of domestic module supply shortages.”
The International Trade Commission will submit a report to President Trump on the tariffs as part of its midterm review by Feb. 7. At Wednesday’s summit, SEIA General Counsel John Smirnow said he thinks that the administration would eventually drop the tariffs, but he noted that Trump is notoriously unpredictable, especially when it comes to trade. The president’s tweets can lead to a drop in the stock market one day, and a rebound the next. “Anybody who tells you they know what is happening, what’s going to happen, dates certain … I’d be surprised if they actually do,” he said.
Erin Duncan, SEIA vice president of congressional affairs, asked Schrodt if a carbon tax or dividend would be the next big policy battle after the tax credit extension. Rooney is the only Republican supporter of the Energy Innovation and Carbon Dividend Act, which would tax the carbon emitted by fuels, deposit the revenue into a new Carbon Dividend Trust Fund and distribute the funds back to taxpayers.
“The unfortunate reality is that we’re headed into a campaign year,” Schrodt said. “I’ve been on the Hill long enough to know that we have from now to maybe until March to really do anything. It’s going to take smaller bites of the apple.”
Unmentioned by Schrodt is that Rooney is not running for re-election. His announcement came in October, one day after he told CNN he was open to investigating whether Trump should be impeached.
In his Nov. 21 response, van Welie noted the region’s efforts to integrate energy efficiency and demand response into the wholesale markets and addressed the senators’ concern that the Energy Security Improvement (ESI) market design project “further delays market reforms that recognize and facilitate state public policies to grow clean energy and address climate change.”
Van Welie said that although the ESI would benefit generators with stored fossil fuel, it could also provide opportunities for solar facilities with battery storage “or an offshore wind farm that operates at a high capacity factor during winter.”
“Rather than delaying the transition to a renewable future, ESI may actually accelerate the transition to reliable, zero-carbon renewable resources and storage technologies by recognizing and compensating these resources for the reliability attributes they provide,” van Welie wrote.
Price-responsive demand (PRD) energy market activity by month | ISO-NE
PC Chair Nancy Chafetz cut short the ensuing discussion, assuring stakeholders that they would have ample opportunity to voice their opinions at NEPOOL Technical Committee meetings over the coming months.
The PC also received a briefing from ISO-NE Director Brook Colangelo on the RTO’s cybersecurity work and its participation in last month’s GridEx V exercise. (See GridEx V Throws New Tech Curveball.)
COO Vamsi Chadalavada apologized for a computer glitch on Nov. 3 that caused the submission window for external transactions to close at 9 a.m. instead of 10 a.m.
The problem was due to a software error related to the daylight saving time transition, he said.
A new eMarket application had been placed in service Oct. 23, and a few participants could not enter or modify external transactions after 9 a.m. on Nov. 3, though the application performed as expected for all other supply offers and demand bids.
The day-ahead market was cleared with the offers and bids as of 10 a.m., per normal schedule, and the issue was fixed by early afternoon, Chadalavada said.
One stakeholder suggested that the RTO have extra staff on hand when transitioning to new software, just in case customers need service.
Natural Gas Prices Double from October
Chadalavada reported the energy market value for last month was $284 million, through Nov. 25, up $82 million from October 2019 and down $319 million from the same month a year ago.
Natural gas prices doubled from October to November, helping push average real-time hub LMPs to $35.52/MWh, up 74% from the prior month.
However, natural gas prices and LMPs were down 46% and 36%, respectively, from November 2018.
Average day-ahead cleared physical energy during the peak hours as a percentage of forecasted load was 99.6% during November, up from 98.8% during October, with the minimum value for the month of 95.7% posted on Nov. 8.
Daily uplift, or net commitment period compensation (NCPC) payments, in November totaled $3.3 million through the 25th, up $600,000 from October and down $1.3 million from the same month last year.
NCPC payments over the period were 1.2% of the energy market value.
Committee Officers Elected, Appointed
The Participants Committee re-elected Chafetz (Customized Energy Solutions); Vice Chairs Calvin Bowie (Eversource Energy), David Cavanaugh (Energy New England), Douglas Hurley (Synapse Energy Economics) and Tom Kaslow (FirstLight Power Resources); Secretary David Doot (Day Pitney); and Assistant Secretary Sebastian Lombardi (Day Pitney). In addition, Michael Macrae, energy analytics manager for Harvard Dedicated Energy, was elected vice chair representing End Users. He replaces Liz Delaney, who stepped down after leaving the Environmental Defense Fund to become director of wholesale market development for Borrego Solar.
ISO-NE appointed Mariah Winkler to serve as the new chair of the NEPOOL Markets Committee. Winkler has 10 years of experience in the Forward Capacity Market and led the Reliability and Transmission committees through discussions on issues such as FCM fuel security reliability reviews and competitive transmission solicitations.
The RTO appointed Emily Laine to replace Winkler as the new chair of the Reliability and Transmission committees. Laine also serves as secretary of the Demand Resources Working Group.
After 17 years serving the MC, most recently as chair, Alex Kuznecow will now serve as chair of the NEPOOL Working Groups.
2020 Budget
The PC unanimously approved a 2020 budget of $6,365,000 for NEPOOL, up $90,000 (1.4%) from 2019’s spending plan. NEPOOL expects to spend $6,625,000 by the end of this year, $350,000 above the approved budget. Most of the increase stems from $340,000 in above-budget spending for Day Pitney’s counsel fees, an 8.6% exceedance. Independent financial adviser fees and disbursements were $5,000 over budget (12.5%), and committee meeting fees were $30,000 more than planned (4.4%). They were partially offset by $25,000 in savings on the Generation Information System (-2.9%).
Breakdown of projected 2020 NEPOOL expenses | NEPOOL
Consent Agenda
The PC unanimously approved the Reliability Committee’s recommendation to revise ISO-NE Operating Procedure No. 2 to incorporate a new reference document and clarify the RTO’s role in approving the scheduling of planned equipment maintenance and outages.
It also approved the Markets Committee’s recommendation to change Market Rule 1 to sunset the fuel security reliability review provisions following Forward Capacity Auction 14, one year earlier than currently planned. The RTO said the review will not be necessary for FCA 15, when the ESI design is expected to be in place.
That compliance filing is due Jan. 21. Requests for rehearing of FERC’s order are due by Dec. 23.
Doot also mentioned the commission’s Notice of Inquiry in March for comments on whether it should change its method of calculating returns on equity for electric transmission and natural gas and oil pipelines (PL19-4). The proceeding has produced splits between transmission owners and load interests, as well as calls for new policies to increase the efficiency of existing lines and mandates on interregional planning. (See Tx Incentives NOI Brings Calls for Broader Reforms.)
He also drew attention to the D.C. Circuit Court of Appeals’ ruling Thursday indicating it will reconsider its precedent that allows FERC to issue “tolling” orders to indefinitely delay action on requests for rehearing. (See related story, DC Circuit to Reconsider FERC Tolling Orders.)
DENVER — Almost 500 members of the storage industry and assorted regulators, financiers, and utility and RTO representatives gathered last week for the GreenTech Media Energy Storage Summit 2019.
These are heady times for the industry. Seven states — California, Hawaii, Illinois, Ohio, Pennsylvania, Texas and West Virginia — have at least 50 MW of energy storage. In all, nearly three dozen states — blue, red and purple — have some sort of storage facilities, though some are 10 MW or less.
“The map is starting to fill out. That’s not a pattern you see with wind regions or solar regions,” said Daniel Finn-Foley, who leads consulting firm Wood Mackenzie’s energy storage team and focuses on front-of-the-meter energy storage applications.
Wood Mackenzie’s third-quarter market report indicates storage deployments were up 32% quarter-over-quarter to 430 MW, with 100 MW deployed during the period. Finn-Foley predicts the storage market will triple and come close to the $2 billion level in 2020, more than doubling to $4.2 billion in 2021, and that annual deployments will reach 5.4 GW by 2024.
“Energy storage is spreading across the United States in a way we haven’t seen other technologies do,” he said. “Storage has a value in whatever region it’s in. Years ago, we would have been confined to particular areas.”
Finn-Foley said the surging interest is driven by utility procurements and markets that see the need for storage’s fast-start abilities. That has led to a jump in grid operators’ interconnection requests.
“People are taking advantage of [storage’s] eligibility and hopefully making a little money. People are looking forward into these markets and making bets,” Finn-Foley said.
“No longer are developers going to the market and pushing up and saying, ‘Energy storage can do so much if you can give us a chance,’” he said. “It’s going to be the policymakers, the regulators, looking back down to the energy storage industry and saying, ‘We need you now, if we’re going to have these 100% renewable targets.’”
ISOs, RTOs Working to Accommodate Storage Resources
ERCOT is ground zero for storage’s growth, just as it has been for renewable energy. Though Texas currently classifies storage as a generation asset, developers have found the resource helps arbitrage wind power and meet demand peaks.
“We have a lot of people knocking on the door right now, a lot more than a few years ago,” said Paul Wattles, ERCOT’s senior analyst of market design and development. He recalled looking at the storage interconnection queue and seeing “almost nothing” in it.
Checking the numbers on a note in front of him, Wattles said ERCOT now has more than 5,600 MW of storage projects in the queue.
“I’m assuming that’s way back in the queue,” he said. “[Storage] is really in the category of noise, but with 5,600 MW in the queue, it won’t be noise for too long.”
Wattles said ERCOT’s scarcity pricing cap of $9,000/MWh, which the grid operator reached or neared for more than six hours this summer, “creates an opportunity for energy arbitrage, which I’m sure the batteries are well-qualified to take care of.” Storage providers are more likely to earn returns by providing ancillary service, he said, given the “island” grid operators need for fast-responding regulation service.
“Our challenge is to find friendly locations in ancillary service and the energy market for all types of resources,” Wattles said.
Storage in the ERCOT interconnection queue | Grid Monitor
SPP General Counsel Paul Suskie and James Pigeon, NYISO manager of distributed resources integration, joined Wattles on the panel as they discussed roadblocks to energy storage’s participation in U.S. markets and implementing FERC Order 841.
Suskie said SPP has largely complied with the rulemaking, designed to eliminate barriers to storage’s participation in wholesale electric markets. He said FERC wants the RTO to move energy storage requirements from the protocols into the Tariff, “which we’ll do.” (See FERC Partially OKs PJM, SPP Order 841 Filings.)
“What we’re seeing in the queue is solar and storage paired together” to take advantage of tax incentives, Suskie said. With more than 22 GW of installed wind capacity and wind bidding in at negative prices, getting paid to store off-peak power and then letting it back into the market “makes sense,” he said.
“We have more wind on the system than load,” Suskie said. “It’ll be an asset to store the wind energy. Wind can drop off dramatically, and we’re going to need more products to get us up quickly, and batteries will do that.”
NYISO is the only grid operator still waiting on an Order 841 compliance ruling from FERC. (ERCOT is not FERC-jurisdictional.)
“We’ve worked with stakeholders to see where we land in meeting all of FERC’s requirements and still find benefits while providing lowest-cost power,” Pigeon said. NYISO has proposed a model that allows storage resources to either blend into a higher aggregation with storage and demand response, or to come together as one, virtual, larger resource.
“By leveraging this new aggregation model, hopefully storage and DERs will be able to come together and help the ISO,” Pigeon said. NYISO currently allows four-hour storage resources and expects more interest, he said, which has led the ISO to propose two-, four-, six- and eight-hour increments.
“If the storage device decides it wants to run longer, it can do so at a discounted rate,” Pigeon said. “Hopefully, that provides a flexibility people can use and leverage.”
California Outages Open Eyes to Storage
California’s attempts to prevent wildfires with public safety power shutoffs in November left more than 2 million residents in the dark — and created additional demand for energy storage solutions.
“The experience of a shutdown is a real motivator,” said Thomas Plagemann, Vivint Solar’s chief commercial officer. “We’re talking a lot more with customers about resiliency. The ability to store some of your energy in the daytime, to keep the refrigerator running, charge your phone overnight … that resiliency is in high demand in California.”
“Storage has become a standard part of what we evaluate for with [California] customers, where it was demand-side management,” said Suparna Kadam, EnterSolar’s director of business development. “Resiliency is now more meaningful to customers.”
Colorado’s Polis: Seeing Value in Storage
As the governor of a state intent on reaching a 100% renewable grid by 2040, Colorado’s Jared Polis would normally have been the star of his presentation. That is, until he brought along Gia, a terrier mix rescued 10 years ago by Polis and his partner.
“She’s really into storage,” he said, as he placed Gia in the chair next to his. “Not so much on the generation side.”
Polis mentioned an upcoming adoption event for rescue animals at the governor’s mansion, but he also had another … pet cause on his mind.
A Democrat, Polis easily won election last year, running on a pledge to have the state’s grid running on 100% renewable energy by 2040. While the renewable goal is not state law, the legislature did codify a 50% emission reduction by 2030 that increases to 90% by 2050.
“Colorado is a very forward-looking state. The people want to make sure the future works for us, rather than against us. They understand this is the way Colorado is going, America is going, the world is going,” he said. “Sure, there’ll be potholes along the way — for instance, the lack of federal progress under this administration — but we see enormous progress at the local level.”
Polis said 14 municipalities have set more aggressive renewable goals than the state and numerous private sector companies “large and small” have announced renewable energy goals. Xcel Energy, the state’s largest electric utility, has announced an 80% carbon reduction by 2030, and Polis talked of visiting an Amazon distribution facility with a rooftop solar array nine football fields long that will provide 80% of the facility’s total energy needs.
“It’s all about the economics. The generation side, solar and wind, they are there. They have a lower cost than coal,” he said. “Natural gas comes and goes, but we’re not building out our capacity based on low prices now. The question is how we can retire legacy assets and give consumers opportunities for savings sooner rather than later.”
Polis sees energy storage as supplying some of the answers to the question. He noted that Xcel’s bids for wind-plus-storage came in “significantly” lower than existing coal production.
“I think that helped inspire their confidence in 100% green by 2030,” he said. “It’s amazing just to see the improvement on energy storage. It brings into the realm of the economically possible even more energy. I think people understand the savings and the resiliency that could result from increased renewable energy, coupled with storage. With storage, you have enormous opportunities over time for exponential, game-changing type technological advancements.”
Alice Jackson, president of Xcel Energy-Colorado, and Colorado Public Utilities Commissioner Frances Koncilja took a break from rate case arguments and regulatory filings to discuss the increase in renewable portfolio standards across multiple states and energy storage’s role. Six states and D.C. are chasing 100% RPS, with New York and California accounting for one-third of investment firm Morningstar’s RPS-based renewable energy growth estimate over the next 10 years, and solar, paired with storage, is expected to be responsible for much of the growth.
Koncilja said the PUC is just beginning to work with stakeholders to create storage requirements through its electric resource plan (ERP), which is conducted every four years.
“We have really left this to the market. The bids that came in [2018’s ERP process] were so robust and amazing, the question was, does a regulator really need to come in and deal with this?” she said. “We are moving away from least-cost to cost-effective. Least-cost might mean we would never get to the RPS we need.”
Xcel-Colorado saw an “overwhelming” response to renewable procurements. Jackson said there were so many responses to a 2017 request for proposals that it broke the company’s modeling tool.
“Normally, you would have gotten about 50 bids from customers. We got over 400 bids,” she said. “We were surprised by some of the [storage] pricing.”
Xcel-Colorado has agreed to an early retirement of 725 MW of coal-fired generation, which will require the utility to obtain an additional 450 MW of generation. It plans to add 1,100 MW of wind and 700 MW of solar and pair 275 MW of storage with solar.
“We’re not invited to make the film, we’re not invited to the Academy Awards, and we’re not invited to the after-party. We’re sort of the cleanup crew,” Koncilja said. “We are the implementation group. We do that through our rules and our statutes.”
Koncilja said recent state legislation included “Machiavellian” language that surprised the commission. The so-called “Turducken Bill” not only reauthorized the PUC, but also set carbon-reduction targets and established a process for issuing low-cost bonds to retire power plants in lieu of cleaner resources.
“We’re more attuned to how many things are being required of our utilities,” she said. “For me, it’s how do we make this a level playing field. It should be where everyone is bidding the same.”
Pacific Gas and Electric announced late Friday it had reached a $13.5 billion settlement with the individual victims of wildfires sparked by its equipment from 2015 to 2018.
The announcement ended a tumultuous week for PG&E that included a growing movement to take the investor-owned utility public and revelations in a state report that said worn and broken hardware on a century-old transmission line had led to California’s worst wildfire disaster.
PG&E’s agreement with the Tort Claimants Committee (TCC) and firms representing individual claimants, to be paid in cash and stock, matches a proposed deal by bondholders for their own Chapter 11 reorganization plan in an effort to take over the utility. PG&E and bondholders have engaged in mediation and negotiations with California Gov. Gavin Newsom to resolve their differences. (See PG&E Bankruptcy Judge Appoints Mediator.)
How PG&E’s announcement will affect the bondholders’ plan remains uncertain, but the utility hailed its settlement as a big step in its bankruptcy. The company is trying to emerge from bankruptcy by June so it can participate in a $21 billion wildfire recovery fund established by the state last summer under Assembly Bill 1054.
“From the beginning of the Chapter 11 process, getting wildfire victims fairly compensated, especially the individuals, has been our primary goal,” PG&E CEO Bill Johnson said in a statement. “With this important milestone now accomplished, we are focused on emerging from Chapter 11 as the utility of the future that our customers and communities expect and deserve.”
Neither the TCC nor other interested parties had issued any reaction to the announcement as of Sunday.
PG&E came under heavy criticism this fall for cutting power to millions of residents as part of its public safety power shutoff events, intended to prevent its equipment from igniting more wind-driven wildfires.
The $13.5 billion settlement with the TCC, composed of the lawyers representing fire victims, will resolve all claims arising from 22 major wildfires in Northern California’s wine country in October 2017 and the 2018 Camp Fire, PG&E said.
In a surprising move, the agreement includes the Tubbs Fire, which killed 22 people and leveled part of Santa Rosa in Sonoma County in October 2017. It’s unclear why that fire was included. State fire investigators determined a private landowner’s illegal distribution lines, not PG&E’s equipment, sparked that fire. PG&E has denied responsibility. A trial to determine liability is scheduled to start in January, but whether it will proceed is unknown.
On the tower suspected of starting the Camp Fire in November 2018, an insulator detached from the hangar plate and hung upside down.| PG&E/CPUC
The settlement also covers the Butte Fire, which decimated communities in the Sierra Nevada foothills southeast of Sacramento in September 2016, killing two people, destroying 475 homes and scorching more than 70,000 acres. Many victims of that fire have yet to receive compensation from PG&E.
The settlement with fire victims is the third and final agreement that PG&E wanted to emerge from Chapter 11 reorganization. The utility previously announced a $1 billion settlement with local governments over fire claims and an $11 billion settlement with insurers and hedge funds who hold subrogation claims against it.
On Wednesday, lawyers argued in court over whether the bankrupt utility should be allowed to move forward with a proposed $11 billion settlement with the subrogation claimants. Lawyers for fire victims have argued that the deal would leave the company without enough resources to fairly compensate fire victims. (See related story, PG&E Judge Weighs Insurers’ Settlement.) PG&E’s agreement with fire victims could potentially moot that concern.
All the settlements must be approved by U.S. Bankruptcy Judge Dennis Montali in San Francisco, who is overseeing the case.
PG&E’s stock price shot up from $7.66/share on Dec. 3 to $10.49 during trading Thursday based on rumors of the settlement with wildfire victims prior to its announcement. Shares closed Friday at $9.65.
The settlement ended an eventful week in the PG&E drama. California’s largest utility, facing billions of dollars in wildfire liabilities, is engaged in one of the largest bankruptcies in U.S. history.
On Dec. 3, the California Public Utilities Commission’s Safety and Enforcement Division released a nearly 700-page report that detailed PG&E’s failings in its inspections and maintenance on its 100-year-old Caribou-Palermo transmission line in the rugged foothills of Butte County. Those failings led to the Camp Fire, the deadliest and most destructive fire in state history, which killed 86 people and destroyed more than 19,000 structures in November 2018 in the town of Paradise, state fire investigators and the CPUC found.
On Thursday, San Jose Mayor Sam Liccardo said his plan to turn PG&E into a public utility was gaining ground — with 115 elected officials now supporting it — as he released an outline of principles meant to guide such a transition. Those principles include keeping the giant utility whole, instead of breaking off pieces into municipal utilities as some have suggested, while transitioning it to public ownership and operation. “Today, we released a … framework for a customer-owned PG&E that is transparent, accountable and equitable to put the company’s days of underinvestment, mismanagement and negligence far behind us,” Liccardo tweeted.
LAS VEGAS — CAISO’s Western Energy Imbalance Market Governing Body and Regional Issues Forum met last week in Sin City’s fake take on an ancient Egyptian pyramid, the Luxor Hotel and Casino. In the casino, gamblers pulled on the handles of slot machines while nursing free drinks. In a nearby meeting room, RIF participants discussed resource adequacy while sipping free coffee.
They also heard from representatives from Modesto Irrigation District, Tacoma Power and Turlock Irrigation District, who explained why they plan to join the West’s real-time interstate electricity market.
Money was a factor, but so too was the evolving Western electricity market, where interstate trading of diverse resources across state lines appears key to the future.
“As more and more folks join the EIM … the thought of not participating in that market is just not feasible … to be blunt,” said James McFall, Modesto’s assistant general manager of electric resources. “You’d get left out in the cold, and we’d have a very illiquid market to access at that point.”
The irrigation district was formed in 1887 to supply water to farmers in California’s Central Valley. It became an electricity purveyor in 1923 and now serves nearly 129,000 retail, commercial and industrial customers across 560 square miles.
The neighboring Turlock Irrigation District, which is two days older than MID, has a similar backstory, said its energy markets manager, Dan Severson. Its hydroelectric dams in the Sierra Nevada foothills are now part of a portfolio that includes natural gas, biomass, solar, wind and geothermal generation.
In his presentation, Severson echoed some of McFall’s remarks. He said that as EIM participation increases, the bilateral hour-ahead markets are becoming less liquid, with fewer trading — which will increase costs going forward. As the EIM looks to expand to a day-ahead market, liquidity could be further reduced, he said.
By joining the EIM, “we [have] access to a larger network of energy providers and increased revenues from sales and increase purchase of megawatt-hours,” Severson said.
Tacoma Power’s electricity comes mainly from hydropower, said Clay Norris, the utility’s power manager. The 125-year-old municipal utility is a subsidiary of a parent company, Tacoma Public Utilities, that also owns and operates a short-line railroad serving the Port of Tacoma.
Norris said Tacoma Power ran its own analyses instead of hiring a consultant when it considered joining the EIM. Its scenarios didn’t all pencil out. The utility has about a 70% chance of recovering the hefty start-up costs of joining the market in the next 10 years, he said.
But the move was about more than finances, he said, echoing that bilateral trading was becoming more difficult in the West, and the broader market of the EIM is now the primary route for buying and selling electricity, with diverse resources and fluid trading.
“This decade has really been about the EIM, I think,” Norris said.
Washington, like several other Western states, now has a 100% clean energy mandate by midcentury and needs to modernize its trading practices to achieve that goal, he said.
The three new entrants join a growing list of EIM participants in a Western market that’s proven popular for its financial benefits and wholly voluntary participation.
The Balancing Area of Northern California signed an implementation agreement with CAISO that will allow members Modesto, Turlock and others to begin trading in the EIM in April 2021.
The BANC agreement represents the second phase of the balancing area’s approach to incorporating its members into the EIM. Sacramento Municipal Utility District entered the market in April. (See SMUD Goes Live in Western EIM.)
Tacoma plans to begin participating in the EIM in 2022. By that time, 77% of the Western Electricity Coordinating Council’s total load will be active in the EIM.
BOSTON — Some 200 industry players braved the first major snowstorm of the season in order to attend the New England Power Generators Association’s inaugural energy summit last week, where state officials and investors debated the right market model to achieve environmental goals across the six-state region.
NEPGA President Dan Dolan said the inaugural conference marked the 20th anniversary of ISO-NE launching its wholesale electricity market in 1999.
Following are highlights of what we heard at the conference.
Wood Urges Markets to Become ‘Proactive’
Former FERC Chair Pat Wood III said that the electricity markets have provided a lot of benefits since the founding of the New England Power Pool in 1971, but that a “troubling amount of state subsidies outside the market … risks losing all the benefit of that market construct.”
“That efficient dispatch and that transparent display of pricing — people meeting each other in the market — brings down costs to the customer,” Wood said. “That’s fundamentally in the spirit of a public industry that’s got a lot of private interest involved but is a very publicly oriented industry.”
The link between what customers and their elected representatives want and what the markets are delivering is fraying because of the growing imbalance between market revenue and that from out-of-market contracts, he said.
“So, we’ve got to get the market design back to being a proactive function and not so much in the reactive mode,” Wood said. “Unbundle the crap out of everything and take exactly what we have in the FERC system and unbundle it.
“When we align the end-use customer price signals back to all these wonderful price signals we’re putting out in the wholesale market, that’s when we win.”
Massachusetts Sen. Michael Barrett, a member of the legislature’s Joint Committee on Telecommunications, Utilities and Energy, said his state can expect a big energy initiative soon.
“It’s fair to say the state subscribes to the idea that we are here to support deep electrification,” Barrett said. “Fundamentally, if you’re a power generator, this is very good news.”
Barrett said Massachusetts is “leading the way” on the Transportation and Climate Initiative (TCI), a collaboration of 12 Northeast and Mid-Atlantic states and D.C. seeking to reduce car and truck emissions, partly because New York has not joined.
“New York is sending staff to the multistate meetings, but Gov. [Andrew] Cuomo has not committed his state the way other governors have done,” Barrett said. “It would be wonderful if New York did join.”
The gasoline market does not show a perfect correlation between pricing and consumer behavior, “so if you double the price, you don’t halve consumption, but there is a positive relation, so we can make progress,” he said.
New Hampshire Sen. Martha Fuller Clark, chair of the Energy and Natural Resources Committee, said her state “has historically been a bit behind the other New England states in energy policy … which is not necessarily a bad thing, since we’ve been able to learn from the others.”
Massachusetts Energy and Environmental Affairs Secretary Kathleen Theoharides said that she is focused on bringing new renewable resources into the market as well as electrifying the transportation and building sectors to take advantage of the new hydro, wind and solar resources as they come online.
“We really feel you need to do those two pieces at the same time. You don’t just clean up your power and then do electrification next,” she said.
Transportation now accounts for 40% of carbon dioxide emissions in the state, region and country, so the TCI is working on a cap-and-trade system similar to the Regional Greenhouse Gas Initiative, which the state has been trying to do “in one form or another for the past 10 years,” Theoharides said.
“Our economies are tied together in the region, and pricing gasoline is more difficult if you’re doing it state by state,” she said. “If you look at the 12-state region, Massachusetts is about 10% of the emissions for that region, so when we’re able to get the whole region into something like this, we can actually multiply our impact on emissions 10 times.”
Theoharides said she worries about “the piecemeal nature of some our climate and energy policies” and that cities, states, regions and the federal government have to “pull together” better than they have to date.
Dan Burgess, director of the Maine governor’s Energy Office, highlighted the new push for renewables under Gov. Janet Mills and said that “a lot of the new energy legislation passed in Maine this year was done in a bipartisan way.”
Investor Perspectives
Jim Burke, executive vice president and COO of Vistra Energy, said that in the past three years, his company has “shut 4,200 MW of coal in Texas; we have just shuttered 1,500 MW of coal in Illinois last month; we have 400 MW that will close in two weeks; and our portfolio shifted from two-thirds coal to two-thirds gas.”
The company also has the 2,425-MW Comanche Peak nuclear plant in Texas, “and we’re building the largest battery so far … just an hour south of Silicon Valley; that’s a 300-MW battery.” It is also pairing energy storage with solar, he said.
“We are technology-agnostic,” Burke said. “We believe that trends that are happening in New England and California will happen elsewhere in the country, but we’d also like to see trends that are happening in Texas spread elsewhere. There are things we can learn from each market.”
Brookfield Renewable Power Managing Partner Mitch Davidson said his company invests in New England for the same reason it invests elsewhere: because it sees an opportunity to either acquire or build an asset and get a healthy return on it.
“Early on in New England, the capacity markets worked very well,” Davidson said. “In Forward Capacity Auction 8, we saw that the market was short, and the price signals were there … and in FCAs 9, 10 and 11, there were 2,000 MW built over those four capacity auctions. Those were the right signals … and that’s the kind of environment we want to put our capital to work in.”
In FCA 12, the company expanded its Bear Swamp pumped hydro facility, of which it is part owner, he said.
“What we have concerns about is the trend in which the market is heading … some uncertainties we’re seeing,” Davidson said.
Matthew O’Connor, managing director of Carlyle Power Partners, said his firm chose New England in 2015 “because it looked like a really good environment to invest: really hard to permit things, really hard to build things, lots of barriers to entry. And back then, we actually thought gas was going to come into the region.”
Carlyle is the second-largest owner of generation in New England after Vistra, with just under 2,500 MW, he said.
“We have a number of plants that are dual-fuel, so we are able to respond to ISO-NE when gas gets really short, as it does in the wintertime here,” O’Connor said.
“We see this as an attractive market, but I share Mitch’s concerns about the future,” he said. “As an example, we put almost $90 million in each of our plants over the last three years. We’re only going to be able to continue to do that if there’s going to be a return on that money, and we’re starting to get concerned that that might be good money after bad.”
Former FERC Chair Cheryl LaFleur asked, “Are you still confident that if we get the price signals right, we can still build the things that we need to serve New England? Or, how much is that in your thinking?”
“I think ‘confident’ is a strong word when answering that question,” O’Connor said. “The question is, do the economics support that [investment]? And we would argue today that they don’t.”
CARMEL, Ind. — A new team considering sequencing parts of MISO’s transmission planning with network upgrades identified in generator interconnection studies held its second meeting Wednesday, with stakeholders outlining the issues they hope to have addressed.
Upcoming discussions of the RTO’s Coordinated Planning Process Task Team (CPPTT) could result in strategies to lower the increasing costs generation developers are facing for network upgrades.
The task team is MISO and stakeholders’ response to complaints from the Environmental and Other Stakeholder Groups sector and others that renewable growth is being hindered by increasingly expensive upgrades. (See Renewables Group Calls for MISO West Tx Construction.)
Several stakeholders have called for the RTO to more closely align its studies that identify network upgrades for the interconnection queue with its annual Transmission Expansion Plan (MTEP) so that transmission that facilitates new renewable output isn’t borne exclusively by generation developers.
The team’s tentative mission is to identify “potential coordination and consistency issues” between MISO’s generator interconnection and MTEP processes.
MISO Manager of Resource Interconnection Arash Ghodsian promised that the team will examine the timing and methodology of the different studies under the interconnection queue and MTEP. “Where can we gain some efficiencies? Where can we gain some consistency?” he told stakeholders. He said the goal is to find the best transmission solutions that can meet a variety of purposes.
Clean Grid Alliance’s Natalie McIntire said the interconnection queue and the MTEP process should share assumptions so that it’s not a race to see which party will foot the bill of a transmission project. “We don’t want to have the timing of the studies determine who pays for the project. Right now, whatever study finishes first determines who pays. That seems to us to be an important principle here. We should have a better process to determine the beneficiaries,” McIntire said.
However, MISO Director of Planning Jeff Webb said it’s impractical to expect the RTO would be able to apply the same set of assumptions to every type of planning study. “It doesn’t make sense. It’s too prescriptive,” Webb said.
McIntire said that interconnection customers are discovering that the costs of network upgrades are “more than the capital costs” of the generation projects themselves.
“I don’t think anyone believes that these several million to $1 billion major upgrades are going to be paid for by interconnection customers,” EDF Renewable Energy Interconnection Manager Anton Ptak said.
He also said MISO “is just at the beginning” of seeing its utilities dramatically alter their fuel mixes and argued that it should identity the beneficiaries beyond the interconnection customer of such expensive upgrades.
“Once upon a time, we were ordered to do cost allocations for generator interconnections instead of the direct assignment approach,” Webb pointed out, noting that MISO has returned to assigning costs directly to interconnection customers and ignoring other beneficiaries. About 14 years ago, the RTO used a 50/50 cost sharing of network upgrades between interconnection customers and load in corresponding transmission pricing zones, with the zonal half collected like baseline reliability projects were, through a blend of 20% postage stamp and 80% sub-regional allocation. To be eligible for the cost sharing, interconnection customers had to become MISO network resources or have proof of a one-year power purchase agreement.
The Union of Concerned Scientists’ Sam Gomberg said MISO should strive to end the “free ridership” of beneficiaries. “Those seem like principles that we should be able to get behind,” Gomberg told attendees.
Great River Energy’s Mike Steckelberg suggested MISO consider creating a transmission project market, where multiple parties can bid in to share project costs.
MISO stakeholders are encouraged to send more issues for the task team to consider through Jan. 2. The CPPTT will hold another a meeting in mid-January.
CARMEL, Ind. — MISO stakeholders last week debated whether the RTO is being too conservative in anticipating industry shifts in its new futures scenarios for transmission planning.
MISO in October released a trio of new 20-year future scenarios to assist transmission planning for the 2021 Transmission Expansion Plan (MTEP 21). (See MISO Sets Course for New Futures.)
Now, the RTO has revised the scenarios’ names to Announced Plans, Accelerated Fleet Change and Advanced Electrification. It has also upped the age at which coal units retire by at least four years in each future and reduced carbon reductions from 50% to 40% in the Accelerated Fleet Change future.
MISO also cut its electrification predictions in both the Advanced Electrification (from 70% to 40% energy growth potential) and Accelerated Fleet Change futures (from 40% to 20%).
Finally, the Announced Plans future now contains an 85% probability instead of total confidence in changes identified in utilities’ integrated resource plans, including coal retirements, new gas-fired generation and emission-reduction targets.
At a special workshop Thursday, MISO Planning Manager Tony Hunziker said the changes were made after the RTO evaluated feedback from stakeholders.
“There was an emphasis on having more conservative assumptions,” he said.
A Question of Coal Retirements
Xcel Energy’s Drew Siebenaler pointed out that his company plans to end all coal use in the MISO footprint by 2030. He also said the RTO should consider that it is often expensive to keep aging coal plants cycling.
“What we’ve learned is it takes a ton of capital to keep these units [operating as reliability]-must-run. I’d like to also see how they’re going to be dispatched,” he told RTO staff.
Veriquest Group’s David Harlan said MISO wasn’t clear on what generation would replace retiring coal units. Hunziker said it would use the Electric Power Research Institute’s Electric Generation Expansion Analysis System (EGEAS) to predict generation expansion.
Clean Grid Alliance’s Natalie McIntire said it didn’t make sense to extend the lifespan of coal plants from 30 years to 35 in the Advanced Electrification future. She said coal use is ending, whether or not members want it to occur.
“I understand that there are a lot of stakeholders that are uncomfortable with an aggressive future. But it’s not MISO’s job to predict the future; it’s to create a reasonable range of plausible futures. We’re not trying to get everyone comfortable with every future. I don’t think it’s reasonable not to have an aggressive future in there, given that all of the [changes predicted] in MISO’s existing futures have been exceeded,” she said.
Comfort not the Goal
Megan Wisersky of Madison Gas and Electric said she agreed that stakeholders shouldn’t be at ease with the scenarios outlined in the futures.
“It’s not our job to make sure that everyone is comfortable. We really need futures that are stretches — that contemplate technological change, political change … that in late 2019, we can’t fathom,” she said.
Wisersky said MISO should craft futures using more intense industry shifts so it doesn’t again use obsolete predictions. The RTO plans to use its existing four futures one last time for the 2020 cycle of its transmission planning.
“It just seems like MISO has scaled back on these in response to a few stakeholders’ comments. These are supposed to be bookends,” McIntire said.
Minnesota Public Utilities Commission staff member Hwikwon Ham suggested MISO assume a 35-year coal plant age retirement in all three futures, then update the ages as utilities announce retirements.
Stakeholders also said MISO should take utilities’ IRP plans at their word, or even assume that utilities will exceed their IRP goals ahead of time. Some suggested that for utilities to publicly announce retirements and not see them through may constitute fraud.
McIntire asked if MISO would include corporate commitments to renewable energy and carbon-cutting in any of its futures.
“We considered that. We didn’t want to double-count them,” Hunziker said.
He said MISO would rely on load-serving entities to include that information in their load forecasting. However, he also said it might consider reaching out to multistate corporations whose renewable goals might be hard to pin down on a single-utility basis.
After MISO revealed its initial futures proposal, the Union of Concerned Scientists’ Sam Gomberg blogged that they were the result of the RTO “lean[ing] into the undeniable transition towards renewable energy resources, emerging technologies like battery storage and the growing momentum behind decarbonizing our economy.”
Gomberg said the new futures are “essential to ensure a modern grid is ultimately ready to support a clean and reliable electricity supply.”
“MISO’s job isn’t easy — making investments now to prepare for an uncertain future. MISO can’t create our clean energy future — that’s up to us as consumers to demand. But MISO, through its function as the regional grid operator, can either complement or hinder our progress. MISO’s proposed revamp of its planning process is a strong step in the right direction to ensure our electricity grid is ready for our clean energy future,” Gomberg said.
Hunziker invited more stakeholder opinions on the three futures. MISO will continue developing the futures scenarios through January, with the definitions completed in either February or March.
