ERCOT’s Technical Advisory Committee for this month will be conducted via a webinar rather than in-person, given the limited number of items to discuss.
TAC Chair Bob Helton has scheduled the online information session for 9:30 a.m. CT on Wednesday.
Committee members will be briefed on a change to the Resource Registration Glossary (RRGRR021) that adds new data requirements for dynamic models in the Transient Security Assessment Tool. The committee will vote by email on the urgent change request.
Calling it a “leadership transition,” CenterPoint Energy said late Wednesday that Scott Prochazka has stepped down as the utility’s CEO. He will be replaced by John Somerhalder II, a member of CenterPoint’s board of directors, who will serve as interim CEO.
Prochazka’s departure comes less than a week after the Texas Public Utility Commission approved a settlement in a proposed CenterPoint rate case that lowered the Houston utility’s return on equity from 10% to 9.4%. CenterPoint also agreed to a $13 million rate increase, far below its initial $161 million ask. (See PUCT Approves Reduced CenterPoint Rate Request.)
Milton Carroll, the board’s executive chairman, thanked Prochazka for his “meaningful contributions” and for leading the company through “significant growth and transformation.” However, he also said the board had determined that “now is the right time for a new leader with a fresh strategic perspective to lead the company through its next phase of growth and value creation.”
Under Prochazka, CenterPoint acquired Indiana utility Vectren for $6 billion last year. He had been with the utility since 2001, being named CEO in 2013.
Somerhalder II has 40 years of energy experience, including nine and a half years as CEO of natural-gas utility AGL Resources. He has been on CenterPoint’s board since 2016.
CenterPoint announced the shakeup after the market closed Wednesday. Its share price lost almost 3% on Thursday, closing down 71 cents at $25.72. The company has scheduled its year-end earnings call for Feb. 27, where it said it will announce “strong full-year 2019 results and provide 2020 [earnings-per-share] guidance.”
CAISO announced Wednesday that its president and CEO, Steve Berberich, intends to retire by early summer.
“Berberich has been at the helm of California’s power grid and wholesale market operator for nearly a decade, steering the organization during the integration of record amounts of renewable resources and expanding power markets regionally to benefit consumers across the western United States,” the ISO said in a news release.
The CAISO Board of Governors has started searching for a successor, it said.
“It has been an honor and privilege to lead such an extraordinary and talented team of professionals here at the ISO,” Berberich said. “I’m incredibly proud of their work and the successes we have had together in this historic energy sector transformation. I have witnessed this organization perform at the highest of levels, reaching milestones not thought possible before.”
Berberich served 14 years with the ISO, nine of them as CEO. Prior to becoming CEO, Berberich held a series of executive positions at the ISO, including vice president of technology, chief financial officer and chief operating officer.
“He was instrumental in installing industry-leading energy management and market systems, reducing reliance on fossil fuels in the electricity supply, and in welcoming new resources into the ISO’s wholesale markets,” CAISO said. “In 2014, he was recognized as one of the top 10 most influential energy leaders in the nation. Under his leadership, the ISO has been recognized internationally as a leader in renewable resource integration.”
Berberich was a key player in starting the Western Energy Imbalance Market in 2014. The interstate trading market has provided nearly $862 million in benefits to its nine participants and is on a path to expand to every state in the Western Interconnection.
Board Chair Dave Olsen praised Berberich for his service.
“His visionary leadership has put the ISO at the forefront of the worldwide transition to low-carbon electricity,” Olsen said. “His legacy is in an organization now thoughtfully positioned and more determined than ever to push toward that goal.”
The president of the California Public Utilities Commission called late Tuesday for escalating oversight and enforcement actions against Pacific Gas and Electric and said receivership may be necessary if the company can’t provide safe service once it exits bankruptcy.
“The receiver, if appointed by the superior court, would be empowered to control and operate PG&E’s business units in the public interest but not dispose of the operations, assets, business or PG&E stock,” President Marybel Batjer wrote in her proposed ruling.
CPUC President Marybel Batjer | California State Assembly
Batjer is the commissioner assigned to the CPUC’s investigation of PG&E’s bankruptcy proceeding under Assembly Bill 1054, passed last July (I.19-09-016). The commission and the U.S. Bankruptcy Court must approve PG&E’s restructuring plan by June 30 for it to participate in the state wildfire insurance fund created by AB 1054.
The measure requires the CPUC to approve the utility’s reorganization plan including the “electrical corporation’s resulting governance structure as being acceptable in light of the electrical corporation’s safety history, criminal probation, recent financial condition and other factors deemed relevant by the commission.”
Batjer’s 10 proposals focus on operational and financial changes meant to enhance safety. Some were first proposed by PG&E in recent testimony.
To address ongoing concerns, PG&E suggested appointing an independent safety adviser after the tenure of its court-appointed monitor ends, a plan Batjer adopted as part of her proposals. The company has the monitor as part of its probation resulting from the 2010 San Bruno pipeline explosion. Jurors in federal court convicted PG&E in 2016 of six felonies related to that disaster. A series of catastrophic wildfires in recent years led the company to seek bankruptcy protection in January 2019.
In another proposal, Batjer echoed a prior demand by Gov. Gavin Newsom for changes in the leadership of the utility and its holding company. (See PG&E Tries to Appease Governor with New Plan.)
“At least 50% of the directors should be California residents at the time of their election,” Batjer wrote. “There should be the presumption that the reorganized PG&E and PG&E Corp. boards of directors will be comprised of individuals not currently serving on the boards.”
She also proposed tying executive compensation to safety performance.
The largest part of Batjer’s ruling describes a six-step process of correcting potential PG&E failures to comply with state law and regulations. Her outline starts with enhanced reporting by PG&E to the CPUC of its safety performance.
Continuing problems would be met with an escalation of government monitoring and control including enhanced commission oversight, appointment of a third-party monitor, appointment of a chief restructuring officer and finally the installation of a court-appointed receiver.
“If PG&E, or any utility, is perceived as struggling to deliver on its responsibilities to the point that the legislature tasks the CPUC with ensuring that the utility develops a governance structure that responds to its ‘safety history, criminal probation, recent financial condition and other factors,’ then it is the CPUC’s responsibility to identify and develop remedial measures,” Batjer said in her statement.
The CPUC is seeking stakeholder input on the proposals beginning at an evidentiary hearing Feb. 26 and continuing during hearings throughout March.
On Tuesday, PG&E reported multibillion-dollar losses but said it expects sustainable financial performance after it emerges from reorganization. (See related story, PG&E Reports $3.6 Billion Q4 Loss.)
PJM began to sketch out how it will respond to FERC’s order expanding the minimum offer price rule (MOPR) Wednesday, suggesting that it may compress the schedule for the delayed 2022/23 Base Residual Auction and subsequent auctions.
At a special meeting Wednesday morning of the Market Implementation Committee, PJM also said it was considering eliminating two of three Incremental Auctions.
PJM will develop a schedule “that meets everyone’s needs to the best of our abilities,” said Adam Keech, vice president of market services, who added that the schedule will ultimately depend on how quickly FERC rules on the RTO’s compliance with its Dec. 19 order. PJM has said it will not schedule a capacity auction until after FERC rules on its compliance filing due March 18.
Keech said the RTO could compress the normal nine-month schedule into six months by shifting three deadlines that normally occur in months nine through six: nominations for winter capacity interconnection rights (CIRs); submission of seller peak-shaving adjustment plans; and preliminary must-offer exemptions for deactivations.
Typical PJM capacity auction schedule | PJM
Keech said leaving the schedule as is could mean those deadlines would come for a given delivery year before PJM had results of the previous auction.
Greg Carmean, executive director of the Organization of PJM States Inc. (OPSI), said his members need time to evaluate FERC’s compliance ruling to see if they need to make changes in state policy. OPSI sent the Board of Managers a letter last week asking for at least 12 months after FERC’s compliance order before the next BRA but to cap the schedule so the auction is held no later than May 31, 2021.
“That’s crazy,” Tom Hoatson of LS Power said of such a delay. “There’s business decisions, there’s investment decisions currently on hold. … I think you could run an auction as early as this fall for 2022/23.”
Richard Seide of Apex Clean Energy asked how PJM would respond if Maryland pulls out of the capacity market and adopts a fixed resource requirement (FRR).
But Marji Philips of LS Power called it a “gross exaggeration to say the world has changed.”
“I think it’s time we stop talking about a house on fire. It’s not on fire. … At least for the upcoming auction, there isn’t a lot that has changed.”
“All these ‘what ifs’ are not compelling,” said Bob O’Connell of Panda Power Funds. “PJM needs to set a schedule that includes all preliminary activity. We can always find reasons to push it off.”
Implied net avoidable-cost rate (ACR) for nuclear plants including capital expenditures | Monitoring Analytics
Carl Johnson of the PJM Public Power Coalition asked PJM and the Independent Market Monitor whether they expected to have to review more units going through the unit-specific exemption process under the new rules.
“I expect it will be more. How much more, I don’t know,” Keech said, adding that it will depend on the values set for the net cost of new entry (CONE) and avoidable-cost rate (ACR).
“It will be more — probably significantly more,” Monitor Joe Bowring said. But he said the Monitor is trying to streamline its review process. “We don’t want to be the thing that slows us down,” he said. “We’re happy to move as quickly as people need us to.”
Exelon’s Jason Barker said shortening the schedule from nine to six months “seems reasonable” but that it would be disruptive to have overlapping auctions because it could put unit owners in a position of having to make retirement decisions for a subsequent delivery year without knowing if it cleared in a prior delivery year.
“You can put all the caveats in the world around that. It has real-world implications,” he said, noting that a plant could see an exodus of its staff after announcing its retirement, even if it is later rescinded.
Keech said PJM is discussing canceling some first and second Incremental Auctions, noting that the postponed BRA for delivery year 2022/23 will likely be after the September date scheduled for the first IA for that period.
He said the RTO may recommend canceling such IAs any time the BRA is later “because you’ve always got the next [IA] coming up.”
If the RTO were to try to reshuffle the IAs, he said, “the logistics around the auction schedule gets extremely complicated.” Such a change would require FERC approval.
IMM to Estimate Cost Impact
In his own presentation on MOPR floor prices, Bowring presented a template for unit-specific exemption requests and an analysis of net ACR costs for nuclear plants.
Barker challenged Bowring’s estimates, saying they fail to account for the plants’ market and operating risks, which should increase prices by $7/MW-day to $18/MW-day. “Risk should be accounted for. It’s not accounted for in these numbers,” he said.
Other speakers questioned using a 20-year asset life for determining the costs of solar generation, saying it is too short.
“We’re not saying it has to be 20 years; that’s what the order is now,” Bowring said. “We think it serves everyone’s interests to have that clarified.”
Bowring also said the Monitor will be publishing “fairly soon” an analysis that will show that the expanded MOPR will not increase capacity clearing prices — contrary to others’ predictions of large increases. In his dissent on the order, Commissioner Richard Glick offered a “back of the envelope” estimate that capacity costs will increase by $2.4 billion annually. (See FERC Extends PJM MOPR to State Subsidies.)
“We’ll point out why that’s not accurate,” Bowring said of Glick’s estimate. But he said the Monitor will not forecast prices for individual locational deliverability areas because that could reveal confidential information and influence bidding behavior. “We don’t want to get out ahead of the market,” he said.
‘Death Penalty’
Seide challenged PJM for changing its interpretation of what he called the “death penalty” for resources that claim the competitive exemption but later accept a state subsidy.
Paragraph 162 of the order says an existing resource that claims the competitive exemption for a capacity delivery year, but later accepts a state subsidy for any part of that delivery year, will be denied capacity market revenues for any part of that year.
The commission said a new resource that claims the competitive exemption in its first year and later accepts a subsidy “may not participate in the capacity market from that point forward for a period of years equal to the applicable asset life that PJM used to set the default offer floor in the auction that the new asset first cleared.”
“Absent this change, PJM’s proposed language would allow gaming and incent the creation of subsidy programs timed to avoid the qualification window,” the commission said.
MIC Chair Lisa Morelli acknowledged that PJM had considered a narrower interpretation of the ban that would bar new resources for just the delivery year in question. But she said the RTO now agrees with Bowring that FERC intended such a circumstance to result in a lifetime ban.
“If FERC sees that [in PJM’s compliance order] and says that was not what the intent was, then they can correct us,” Morelli said.
“You’re accepting the death penalty,” Seide said.
“We prefer asset life ban,” Morelli responded, prompting laughter.
In their request for rehearing, trade groups representing wind and solar generators said the commission’s proposed rule is “unduly punitive and not proportional to the alleged harm caused.”
Additional MOPR Discussions
In a response to questions from stakeholders, Morelli said PJM won’t publish an “exhaustive list” of what it considers subsidies under the FERC order but will list those on which it agrees with the Monitor in the interest of transparency.
Morelli also released an updated schedule of MOPR discussions, including another special MIC session from 9 a.m. to 12 p.m. on Feb. 28. The MOPR will also be on the agenda for the MIC’s next regular meeting March 11. The Demand Response Subcommittee, which discussed the impact of the expanded MOPR on demand response and energy efficiency Wednesday afternoon, will resume its talks from 9 to 12 on March 12.
Following a close vote Wednesday, MISO’s Advisory Committee will recommend the RTO create a new sector for hard-to-define members.
The 12-9 vote means the Advisory Committee will advise the Board of Directors that a new Affiliate Members sector is needed so environmental groups in the current Environmental and Other Stakeholder Groups sector can have a singular voice.
The AC will suggest that the new sector not be allowed a vote in either it or the Planning Advisory Committee but have one designated seat for AC meetings and be allowed to offer opinions during the committee’s quarterly hot topic discussions.
The Affiliate Members sector would serve as a home for any MISO member that isn’t participating in another sector. Prospective MISO members must declare a sector affiliation before they can join the RTO.
The AC began debating the merits of an 11th stakeholder sector last year when Lignite Energy Council (LEC), a North Dakota coal lobbying group, approached MISO about membership. Not fitting neatly into any of MISO’s existing 10 sectors, it looked like it would be relegated to the “other” in the Environmental/Other sector. Some AC members said it wasn’t fitting that a sector would contain entities with diametrically opposed views. (See Feb. Vote Planned on 11th MISO Sector.)
MISO’s Power Marketers, Transmission-Dependent Utilities, Transmission Developers and — surprisingly — the Environmental/Other sector opposed the move. Instead, they supported an option that would maintain the Environmental sector’s “other” contingent and prescribe a six-month trial including LEC as a new member. The End-Use Customers sector abstained.
Speaking during the AC’s conference call Wednesday, MISO Deputy General Counsel Timothy Caister said he anticipates the board will now want to hold discussions with the committee over its reasoning behind the decision and its vision for the new sector.
“We stand ready to help support any questions the board or the Advisory Committee might have,” Caister said of MISO’s role.
If approved, the move will require MISO to file changes to its Transmission Owners’ Agreement with FERC.
So far, the proposed Affiliate Members sector seems destined for a fossil-fuel focus.
North Dakota Public Service Commissioner Julie Fedorchak said LEC has penned a nonpublic letter to MISO indicating its support to join the proposed sector. Fedorchak also said the group indicated that it has drummed up interest among other entities interested in joining, including coal and iron mining organizations, coal trade organization America’s Power (formerly known as the American Coalition for Clean Coal Electricity) and various chambers of commerce. As a rule, MISO does not confirm what entities approach it about membership, only revealing new members when its board votes on admitting them.
“We look forward to working with the Lignite Energy Council and others as they join MISO,” AC Chair Audrey Penner said.
America’s Power CEO Michelle Bloodworth said an 11th sector would ensure that “everybody with interest and requisite ability has a seat on the table.”
Bloodworth also asked that the AC revisit the no-vote stipulation in the future as the sector gains more members.
“As the energy industry continues to evolve, key players like the Lignite Energy Council, America’s Power and others who are involved in coal-generated electricity need to remain engaged in MISO’s market discussions,” Bloodworth said in a statement urging the board to support the new sector.
Meanwhile, the AC is planning on holding another panel-style discussion featuring industry experts in lieu of its usual hot topic discussion during next month’s MISO Board Week in New Orleans. The panel will focus on how RTOs deal with resource transition and likely feature one executive apiece from NYISO, CAISO and ERCOT.
Pacific Gas and Electric reported multibillion-dollar losses in its quarterly and annual reports Tuesday but said in a separate five-year forecast that it expects sustainable financial performance after it emerges from Chapter 11 reorganization.
“Our focus now is on working with all key stakeholders, including elected officials and state regulators, to position PG&E for emergence as a financially stable company with a renewed and rigorous focus on safe operations and customer service,” CEO Bill Johnson said in a statement.
| PG&E
The company said it would not hold a call with analysts to discuss its Q4 results but included detailed slide presentations in its filings.
In its annual report, PG&E said it lost $7.7 billion ($14.50/share) in 2019, an increase over the $6.9 billion ( $13.25/share) loss recorded in 2018. Fourth-quarter 2019 losses totaled $3.6 billion ($6.84/share), down from $6.9 billion ($13.24/share) the utility said in its quarterly report.
The losses mostly resulted from the 2017 and 2018 wildfires that drove PG&E to seek bankruptcy protection in January 2019. The fourth quarter numbers include a $5 billion pre-tax charge related to its previously announced $13.5 billion settlement with victims of the November 2018 Camp Fire that leveled the town of Paradise, the October 2017 Northern California wine country fires that destroyed part of the city of Santa Rosa and the 2015 Butte fire in the Sierra Nevada foothills.
In its forecast, PG&E said it expects to invest $37 billion to $41 billion in infrastructure improvements during the next five years, resulting in an 8% growth in rate-based revenues. Most of the investments will go to hardening its grid against wildfires. The outlook lists serious risk factors, including future wildfire liabilities, but says PG&E could see nearly $20 billion in annual revenue growth by 2024.
Reducing wildfire risks and focusing on safety will help it avoid future losses, PG&E said. Two-thirds of its revenues come from owning and operating electric, gas and generation infrastructure, the utility said, with the remaining third coming from pass-through costs for procuring commodities.
U.S. Bankruptcy Judge Dennis Montali and the California Public Utilities Commission must approve PG&E’s bankruptcy plan by June 30 for the utility to be able to participate in a $21 billion state fund to insure utilities against future wildfires. The fund and its participation criteria were included in last year’s Assembly Bill 1054.
Access to the insurance fund is regarded as vital to the company’s future because California holds utilities liable for fires ignited by their equipment regardless of negligence.
“Wildfire settlements, regulatory resolutions, the enactment of AB 1054 and [the] establishment of a multi-year investment and rate roadmap resolve uncertainty and provide stability,” the company said. PG&E has secured $59 billion for reorganization, and an additional $27 billion may be raised through future public offerings.
| PG&E
The company assured the financial sector Tuesday that it’s on track to meet the June 30 deadline because it has reached settlement agreements with fire victims, insurance companies and local governments in deals worth $25.5 billion.
“PG&E has made significant progress in our Chapter 11 cases over the past year,” Johnson said. “We have resolved essentially every consequential issue within the bankruptcy court’s jurisdiction, most notably reaching a [$13.5 billion] settlement with wildfire victims.”
However, many fire victims have begun to question the deal because it allocates nearly $4 billion of the $13.5 billion to reimbursing government entities, including the Federal Emergency Management Agency. (See What SpringCould Bring for PG&E.)
Gov. Gavin Newsom, too, has challenged the bankruptcy plan, saying PG&E would have so much debt that it wouldn’t have the tens of billions of dollars needed to harden its grid.
The utility said it is continuing to work with the governor’s office to resolve his concerns, but it acknowledged in its SEC filings Tuesday that its “ability to meet the eligibility and other requirements [of AB 1054] may be adversely impacted by the California governor’s review of the proposed plan.”
MISO has begun developing the software to create a 30-minute reserve product for use in late 2021.
Following FERC approval of the reserves’ Tariff definition late last month, the RTO said it moved the project status from conceptual design to a software build phase that will last less than two years. The project was originally scheduled to remain in the conceptual design phase through the first half of 2020.
MISO hopes to begin discussing the software with stakeholders at Market Subcommittee meetings during the second quarter of this year.
The reserves will be furnished by either online or offline resources capable of being deployed within 30 minutes to meet local, sub-regional and market-wide needs.
MISO regions requiring short term reserves are indicated with red arrows. | MISO
The RTO expects the new market product will reduce revenue sufficiency guarantee (RSG) make-whole payments, lessen out-of-market commitments, make market prices more transparent and provide pricing signals that incentivize a greater number of fast-start resources that can meet voltage and local reliability requirements more cheaply. Using the reserves, MISO estimates net production cost benefits of $5 million annually and a $1.6 million reduction in RSG make-whole payments paid in MISO South. (See “MISO Preps Tariff for Short-term Reserves,” MISO Market Subcommittee Briefs: Oct. 10, 2019.)
FERC approved MISO’s plan for implementing the reserve product on Jan. 31 (ER20–42).
In the order, the commission disagreed with criticisms raised by Entergy and state regulators in MISO South, who said the proposal was vague and was driven chiefly by economics, not reliability. Entergy and MISO South regulators also demanded MISO conduct more analysis to identify which market participants and load pockets would stand to benefit from the reserve product, arguing that MISO South customers could disproportionally foot the bill for the reserves because it will be used to manage flows on the regional dispatch transfer (RDT) limit between MISO Midwest and MISO South.
FERC said MISO’s reliability versus economic impetus was beside the point.
“Whether managing the RDT is a reliability or economic concern is irrelevant since the limit is a binding constraint that needs to be enforced pursuant to MISO’s settlement agreement with SPP,” the commission said.
FERC said MISO’s reserve design “reasonably allocates costs based on load-ratio share in grouped zones where constraints result in the need” for the reserves. MISO doesn’t need to model benefits according to load pocket, the commission said.
“We find that MISO has supported its proposed short-term reserve product as representing an efficient, transparent, market-based solution for managing post-contingency reserve needs,” FERC said.
ERCOT CEO Bill Magness last week told the Board of Directors that the grid operator finished 2019 with a net positive variance of $35.4 million, boosting the pool of funds to implement real-time co-optimization (RTC).
ERCOT CEO Bill Magness | ERCOT
Magness said during the board’s Feb. 11 meeting that a preliminary budget review indicated a 13.3% increase in revenues and a 3.4% decrease in expenditures. He credited a $19.2 million increase in interest income and a $6.5 million increase in system administrative fees for much of the positive variance.
Interest income was coming in over budget as a result of higher balances and rates, Magness told the board in April. The unexpected revenue has been set aside to fund an RTC development pool, now at $52.5 million. ERCOT has estimated it will cost at least $40 million to add RTC to the market.
Magness said the administrative fee variance benefited from warmer-than-normal weather from August into October. September provided $2.4 million and August $1.3 million in actual revenue above budget. October and November accounted for $800,000 and $700,000, respectively, in overages.
October “is kind of what you would expect,” Magness said. “September was the really unusual thing.”
ERCOT’s 2019 financial summary, variance to budget | ERCOT
ERCOT’s load continues to grow, with a 2% increase in annual energy usage between 2018 and 2019, after a 5% increase between 2017 and 2018. Over the past decade, energy use is up 20.4%, from 319,097 TWh to 384,040 TWh. The decade before, energy use was up 7.7%.
“[Growth] was as substantial as it felt like, and we continue to see growth,” Magness said.
Real-Time Co-optimization Team Finalizes Scope
ERCOT’s Matt Mereness thanked “all y’all” as he secured the board’s approval of the final batch of RTC key principles that will guide the grid operator’s addition of the market tool into its energy market.
RTC procures both energy and ancillary services every five minutes to find the most cost-effective solution for both requirements. (See “Committee Endorses Final Real-time Co-optimization Principles,” ERCOT Technical Advisory Committee Briefs: Jan. 29, 2020.)
ERCOT’s Matt Mereness briefs the board on real-time co-optimization. | ERCOT
Mereness chaired the Real-Time Co-optimization Task Force, which wrapped up nine months of work by producing a 44-page document that defines the principles, or boundaries, that staff and stakeholders are working toward.
“It’s been painful but focused,” Mereness said of the group’s 16 meetings. “Collaborative, not always perfectly unanimous, but working together to find solutions. One secret that made it work is we had a single forum. All the smart people were in the room working on it.”
Congratulated by board Chair Craven Crowell, Mereness responded, “It takes a village.”
Staff plan to file a set of Nodal Protocol revision requests (NPRRs) implementing RTC in March. The task force will serve as a clearinghouse to address language changes and comments, with a goal of submitting all NPRRs to the Protocol Revision Subcommittee for its consideration in November. If everything stays on schedule, the Technical Advisory Committee and the board will see the final NPRRs in November and December.
According to its schedule, RTC will be added to the market by mid-2024 before a planned update to ERCOT’s Energy Management System.
Helton, Lange Re-elected to TAC Leadership
The board approved staff’s determination that developing systems to enable economic dispatch over DC ties between the grid operator and other systems would be “prohibitively complicated and expensive” and is not “presently feasible.” Staff said existing systems and processes are sufficient enough to manage congestion caused by DC ties.
“A five-minute dispatch would be technically and jurisdictionally a challenge,” Mereness said.
ERCOT had been directed by Texas’ Public Utility Commission to study and determine whether some or all DC ties should be economically dispatched or whether implementing a congestion management plan or special protection scheme would more reliably and cost-effectively manage congestion caused by DC tie flows.
Nick Fehrenbach, manager of regulatory affairs and utility franchising for the city of Dallas, pointed out the Southern Cross project is a “commercial venture for economic benefits” and raised concerns about the import and export of power outside economic dispatch.
“This troubles me,” Fehrenbach said. “I don’t know the next project of this nature, but this is something we need to resolve in the long run.”
Mereness said that ERCOT has changed its scheduling of DC ties. As their ramp comes in, it is offset by the grid operator’s economic dispatch.
Leadership Re-elected
In other action, the directors re-elected Crowell as chair, former PUC Commissioner Judy Walsh as vice chair and Magness as CEO, and ratified ERCOT’s officers.
The board’s consent agenda, which passed unanimously, included 16 NPRRs, single revisions to the Nodal Operating Guide (NOGRR) and Verifiable Cost Manual (VCMRR) and a system change request (SCR):
NPRR826: creates a new process for determining the mitigated offer cap for reliability-must-run (RMR) resources.
NPRR838: revises the RMR process by removing the requirements for units to submit operations and maintenance estimates and for RMR resources to submit quarterly O&M updates.
NPRR955: defines a limited-impact RAS to accommodate NERC Reliability Standard PRC-012-2.
NPRR963: allows an energy storage resource’s (ESR) components to be considered in aggregate for generation resource energy deployment performance scoring, controllable load resource energy deployment performance scoring and settlement of base point deviation charges.
NPRR964: removes from the RMR process the term “synchronous condenser unit” and its related agreement.
NPRR967: removes the 10-MW limit for limited-duration resources.
NPRR970: clarifies the fuel-dispute process for reliability unit commitment (RUC) make-whole payments.
NPRR971: updates the energy offer curve’s cost cap value.
NPRR974: requires ERCOT to include additional data about the amount of projected capacity available in the short-term system adequacy report.
NPRR977: requires ERCOT to post a report of canceled RUCs to the market information system.
NPRR978: incorporates revisions to address recent changes on the PUC’s resource adequacy reporting rules.
NPRR980: changes how forced outages longer than 180 days are treated in ERCOT’s Capacity, Demand and Reserves report.
NPRR982: clarifies that a deployed block-load transfer will be appropriately compensated.
NPRR985: modifies the time period used to compute the forward adjustment factor components of the total potential exposure calculation and clarifies that the three forward weeks commence on the applicable operating day, rather than following the operating day.
NPRR986: gives ESRs more flexibility in updating real-time energy offer curves and bids.
NPRR988: corrects NPRR929’s intended implementation by clarifying that conditions in its language are necessary for determining whether a point-to-point obligation with links to an option bid is eligible to be awarded.
NOGRR183: aligns the Nodal Operating Guides with NERC’s remedial action scheme reliability standard.
SCR806: adds resource-specific offer information to all individual disclosure reports on ERCOT’s website.
VCMRR026: removes an appendix to align the manual with NPRR970’s proposed protocol language and NPRR617’s revisions.
WASHINGTON — Jason Burwen, vice president of policy for the Energy Storage Association, took his audience down memory lane Wednesday, recalling the industry’s growth since he joined the organization in 2015.
At the time, he told an audience of 200 at ESA’s annual Energy Storage Policy Forum, there was only 200 MW of non-hydro storage on the grid, virtually all in front of the meter and less than one hour in duration. The market was almost entirely frequency regulation.
Just five years later, there is more than 1,500 MW of storage online, one-third of it behind the meter, with some batteries capable of injecting energy for up to eight hours. In addition to providing ancillary services, it is also seeking roles as capacity and transmission. It is increasingly being paired with solar and wind generation.
“We are a mature industry,” Burwen said, slowing for emphasis.
It’s not all rosy, however. Burwen decried the Trump administration’s tariffs on storage technology imports.
“We have a global supply chain in the energy storage industry and certainly just as we are getting our legs underneath us, it is [an] incredible setback to have that uncertainty when folks are contracting years down the line,” he said. “So, that’s something that we’re trying to make sure that the administration is aware of — recognizing how much effort is going into promoting resilience and [how] storage can be key part of that.”
Storage remains dwarfed by wind (108 GW) and solar (75 GW) generation in installed capacity. And although ESA formed a political action committee last April, it raised less than $5,000 and disbursed only $2,000 in 2019. The American Wind Energy Association’s PAC disbursed more than $78,000 last year and more than $300,000 in the 2018 cycle. The Solar Energy Industries Association PAC spent almost $179,000 in the 2018 campaigns and more than $63,000 in 2019.
But there’s no doubt storage has gained some clout in D.C. As ESA was having its forum, CEO Kelly Speakes-Backman was testifying before a House Energy and Commerce subcommittee. She spoke in support of HR 4447, which would provide technical assistance to rural electric cooperatives for storage and microgrid projects, and HR 1744, a bipartisan bill that would amend the Public Utility Regulatory Policies Act to require utilities to consider storage in their supply-side resource planning processes.
Burwen said the industry “accelerated dramatically” last year. Congress saw the introduction of more than a dozen bills promoting storage, some calling for an investment tax credit. FERC conditionally approved RTOs’ compliance plans with Order 841, the commission’s 2018 rulemaking requiring the RTOs to allow energy storage resources full access to their markets. (See Storage Plans Clear FERC with Conditions.) New York and California expanded their storage incentives, with Nevada finalizing a storage target and Maine and Virginia recommending them. (Last week, Virginia lawmakers approved a 3,100-MW energy storage target by 2035.)
Battery storage costs have dropped dramatically, along with the cost of solar and wind generation, opening new opportunities.
“In the last two years, projects that pair renewables technologies with large-scale batteries have for the first time become economically viable,” BloombergNEF reported in its 2020 Sustainable Energy in America Factbook, released last week. “In particular, ‘PV-plus-storage’ projects have under-bid natural gas-fired plants to win power-delivery contracts in certain states thanks to a 77% drop in the price of a typical PV module and an 87% decline in battery pack prices.”
ESA says its “vision” is to reach 35 GW of storage by 2025, a 23-fold increase from current levels. “This is undoubtedly ambitious and will require fundamental changes in how the grid is planned and engineered, including a reform of U.S. energy markets and regulations,” ESA said.
It projects that electrifying transportation and buildings will add more than 3,500 TWh of annual demand in addition to current U.S. consumption of 4,200 TWh, with annual additions of storage reaching 7 GW in 2024. Wood Mackenzie Power & Renewables projects a more modest deployment of 4.4 GW in 2024.
To reach its goal, ESA is focusing its policy efforts on three goals: ensuring the ability to interconnect to the grid, which FERC supported with Order 845; including storage in all planning processes and procurements as an alternative to other resources; and winning compensation for the resource’s flexibility and other attributes.
The association has called for updating utility integrated resource planning to consider storage as an option for system capacity. IRPs, Burwen said, will be “the new RPS” (renewable portfolio standard). In the next five years, storage will become a “fully integrated part of” discussions on reaching 100% clean energy targets, Burwen said.
“In some respects, the last five years have been about mainstreaming energy storage as supply. And the next five years, we’re probably talking about mainstreaming energy storage as infrastructure, both in the grid and in the built environment,” he said.
RTOs Discuss Opening Doors for Storage
Panel discussions earlier in Wednesday’s conference included state regulators and officials from CAISO, MISO, PJM, ERCOT and NYISO.
Burwen asked one panel about RTOs’ role in resource adequacy, citing FERC’s controversial Dec. 19 order requiring an expansion of PJM’s minimum offer price rule (MOPR) to cover new state-subsidized resources. State officials have criticized the ruling as an attack on their jurisdiction over resource adequacy; some are considering withdrawing from the capacity market as a result. (See PJM MOPR Rehearing Requests Pour into FERC.)
Michael DeSocio, NYISO’s director of market design, said the issue is the subject of “conversations” in the ISO’s stakeholder processes and proceedings of the New York Public Service Commission.
“What we’re really looking for is a little bit of time. … These are complicated issues,” he said. “The markets have offered a level of transparency that you didn’t have before the markets existed, [which] is really important so you get a fair shake at making a go out of it. … I’d really hate to see that go away. So, we’re working hard to see if we can come up with solutions to those concerns.”
In a second RTO/ISO panel, ERCOT’s Kenneth Ragsdale said that although the Texas grid operator is not under FERC jurisdiction, Order 841 “helped us rationalize why we need to spend more time on storage.”
“We’re looking at how we can integrate [storage] with the system we have. … We’ve looked at allowing bid offer curves to be updated intra-hour instead of once at the hour. … We are trying to find the proper way to represent what this asset can provide to us [for resource adequacy]. We are really trying to get away from, ‘No you can’t interconnect that,’ to ‘Yes.’”
Stacey Crowley, CAISO’s vice president of external and customer affairs, said the ISO and storage providers are in the middle of a “trust-building exercise.”
“The operators are going to need to trust that those resources are there when the resource says they’re going to be there,” she said. “One of our really smart attorneys said, ‘Stacy. This is a marathon. And we are literally just tying our shoes right now.’”
Burwen noted that MISO generated controversy in December when it became the first RTO to file a proposal with FERC for treating storage as transmission.
The RTO’s storage-as-transmission-only assets (SATOA) proposal drew complaints that it would provide transmission owners a monopoly (ER20-588). The RTO said it was an initial step designed to avoid complexities over cost recovery, such as how non-TOs would be compensated for providing transmission services. SATOA resources would be barred from simultaneous participation in MISO’s energy market, at least initially. (See MISO SATOA Proposal Faces Opposition.)
Laura Rauch, MISO’s director of settlements, acknowledged the proposal is “imperfect.”
“If you read our filing, you saw that we acknowledge that this is … only a first step,” she said.
Glick Seeks Tech Conference on Hybrid Resources
In a keynote speech, FERC Commissioner Richard Glick acknowledged his two years on the commission have been “maybe a little more contentious than previous FERCs have been. We’ve had, certainly, quite vivid and interesting debates among the different commissioners and advisers.
“One of the reasons is that the transition to a clean energy future … creates a lot of conflicts,” he continued. “People that were in the business before that see their technologies are maybe on the way out are going to fight very hard. … There are winners and losers. Not everything is a win-win situation.”
“Chairman [Neil] Chatterjee has stated a number of times … he wants to make FERC boring again,” he continued, sparking laughter from the audience. “I have to say, he just hasn’t succeeded quite yet.”
But Glick credited Chatterjee for supporting Order 841 — one of the few times that the chairman voted differently than his fellow Republican, Commissioner Bernard McNamee.
He expressed hope that the commission will return to the issue of aggregated distributed energy resources, which it declined to act on in Order 841. “In my view, we should be ready to go. I don’t think there’s any additional information we need,” he said, noting the commission held a technical conference and received comments on the issue. (See Commenters Divided on DER Aggregation, State, LDC Roles.)
He also expressed confidence that the commission will prevail in a legal challenge over its jurisdiction over storage, noting the Federal Power Act gives it authority over all sales for resale, “even behind the meter.” State regulators, utilities and public power groups asked the D.C. Circuit Court of Appeals in July to overturn FERC’s decision not to allow states to opt out of Order 841. (See States, Public Power Challenge FERC Storage Rule.)
Glick said he wants to learn more about reports that storage providers have been reluctant to enter the energy markets in some regions, saying their involvement will be necessary to accommodate a big increase in intermittent renewables. “Especially if we don’t build as much transmission as we need to build, the only way to deal with this extra intermittency is through storage. A lot more storage.”
He also said FERC should hold a technical conference on hybrid storage. Among the questions the commission needs to answer, he said, is how the addition of storage to an existing solar or wind project affects its position in the interconnection queue and whether it is treated as a dispatchable or intermittent resource. “We need to learn what some of these issues are — what some of the barriers are — for hybrid technologies,” he said.
