FERC on Tuesday approved a MISO proposal requiring owners of load-modifying resources to provide firmer and more clearly documented commitments regarding their availability before participating in the RTO’s capacity market.
The proposal represents the first piece of MISO’s three-part near-term resource availability and need initiative.
” … Recent maximum generation emergency events have frequently occurred outside the summer season as generator forced outages and high load conditions converge with planned generator outages that are typically scheduled in the spring and fall seasons. MISO contends that these spring and fall maximum generation emergency events do not align well with the obligations of LMRs, which currently are not required to serve MISO load in non-summer seasons,” the RTO said in making the case for the new rules.
MISO control room | MISO
The new rules require a load-modifying resource (LMR) to offer capacity in accordance with a seasonal availability report provided to MISO and commit to deploying based on the shortest notification time it “can consistently meet” but no longer than 12 hours (ER19-650). LMR owners must provide that information to MISO during registration.
In return, MISO will issue scheduling instructions before an emergency occurs based on an LMR’s unique notification times. The RTO has also promised to confirm or withdraw advanced scheduling instructions at least two hours prior to an expected emergency event. LMRs that acknowledge scheduling instructions will receive credit for one of the five times per year that LMRs are required to respond, regardless of whether the emergency declaration is made.
MISO said the rules will improve transparency around LMR capability and give it easier access to LMRs during emergency situations.
In approving the filing, FERC also granted a waiver of MISO’s usual deadlines for LMRs to register their availability for the April capacity auction. LMRs now have until March 1 to complete registration. (See “LMR Registration Confusion” in MISO Preliminary PRA Dataup Slightly from Early Prediction.)
A group of MISO industrial customers protested the filing, saying the RTO was vague and failed to outline how the “best physical capability” and “shortest notice requirements” of LMRs would be measured and verified. Those customers also said the new availability requirements could create an “incentive for LMRs to exit the market,” which could drive up capacity auction clearing prices.
But FERC said cut-and-dried availability rules wouldn’t work best for LMRs, which differ in operating characteristics and limitations: “Although a specific definition would provide certainty to some LMRs, it would likely be incompatible with the capabilities and circumstances of other LMRs. Therefore, we find reasonable MISO’s proposal to give flexibility to each LMR in determining its own capabilities and the type of supporting documentation it can provide for the purpose of demonstrating its capabilities.” The commission also dismissed as “speculative” the claim that the RTO’s proposal will force LMRs to exit the market.
MISO has two other near-term filings awaiting FERC action as part of the short-term resource availability and need project: one to subject demand response to annual capability testing and the other to impose new generator accreditation penalties for planned outages taken fewer than 120 days in advance and during what MISO deems “low-margin, high-risk periods.” The trio of filings is aimed at immediate relief in time for spring and to buy time for in-depth solutions. The Market Subcommittee and Resource Adequacy Subcommittee will work on the more involved solutions — yet unnamed — through 2020. (See Stakeholders Seek Slowdown on MISO RAN Project.)
PJM will extend the submission window for long-term projects an additional two weeks to account for recent transmission planning rule changes approved by FERC.
“We are not expecting significant changes, but we are expecting some changes, so we felt it right to extend the window,” PJM’s Brian Chmielewski told a special meeting of the Transmission Expansion Advisory Committee Feb. 20.
FERC earlier this month approved PJM’s revisions to its market efficiency planning rules effective Feb. 13. (See FERC OKs PJM’s Market Efficiency Rule Changes.) The updates impact Section 1.5.7 of the RTO’s Operating Agreement that would exclude from market efficiency planning — with exceptions — generation either with only an executed facilities study agreement (FSA) or with an executed interconnection service agreement (ISA) under suspension (ER19-562).
A second ruling issued Tuesday accepts PJM’s changes to its evaluation of economic-based enhancements as part of its Regional Transmission Expansion Plan, ensuring the benefit/cost ratio for projects proposed in the current year — as opposed to those with delayed in-service dates — will be an “apples-to-apples” comparison (ER19-80).
The rule changes come near the tail-end of the long-term transmission planning window opened in November, which accepts proposals capable of reducing future congestion. (See PJM Market Efficiency Rules Could Slip Deadline.) Chmielewski said extending the submission window will not affect the market efficiency planning cycle, with final review by the TEAC and the board scheduled for December.
Revised Benefit/Cost Ratio
In the Feb. 19 ruling, PJM won its bid to revise the benefit/cost ratio to ensure projects with delayed in-service dates only receive analysis within the existing 15-year planning horizon. Under previous rules, PJM said it spent considerable time developing ad-hoc projections for years beyond the current cycle, resulting in “risky” and “unreliable” modeling.
FERC agreed with PJM’s argument that “limiting the timeframe over which benefits are calculated for market efficiency projects with in-service dates beyond the RTEP Year would address concerns regarding the additional risk of using more speculative benefit estimates for projects with farther out in-service dates.”
The new calculation factors the present value of the total annual enhancement benefit for the 15-year period starting with the RTEP year — defined as current year plus five — minus benefits for years when the project is not yet in-service, divided by the present value of the total enhancement cost for the same 15-year period.
“Thus, under this proposal, if a proposed market efficiency project has an in-service date that extends beyond the RTEP Year, benefits and costs (i.e., revenue requirements) would be evaluated over the same timeframe used for projects with an in-service date of the RTEP Year, which would be for a shorter period than under the current calculation,” FERC concluded.
ITC Mid-Atlantic and NextEra filed a joint protest Oct. 31 arguing the calculation favors smaller, more incremental market efficiency projects and incumbent transmission owners with the ability to propose small-scale upgrades to their own systems. The Independent Market Monitor seconded protestors’ concerns in a separate filing, noting PJM didn’t provide sufficient evidence to suggest their new calculation wouldn’t encourage developers to “game” the system.
PJM said it reviewed 13 projects from the 2016/17 planning window with in-service dates beyond the RTEP year and found that benefit/cost ratios for 11 improved under the changes. The RTO acknowledged several methods exist to levelize project evaluations — each with pros and cons — but prefers its proposed method because it eliminates ad hoc projections for out years.
“We find PJM’s proposal to use the same 15-year planning period for evaluating all projects to be just and reasonable, given that the data for periods outside of the planning period are less accurate,” FERC ruled. “PJM has made a filing to align its benefit/cost analysis with its planning horizon, and we find that proposal just and reasonable as it establishes a level playing field upon which competing market efficiency projects may be evaluated.”
ISO-NE CEO Gordon van Welie said Wednesday that his concerns about New England’s ability to keep the lights on continue to grow despite recently enacted market rule changes, predicting that energy security risks “could become a year-round concern.”
The region has benefited from a milder-than-normal 2018/19 winter and has not faced the severe, lengthy natural gas shortages that marked the two-week cold spell early last year. The RTO also has implemented its Pay-for-Performance incentives and held its first capacity auction under rules intended to mitigate price suppression by subsidized resources.
But speaking at his annual State of the Grid press call, van Welie said the transition to a “hybrid” grid with growing distributed and renewable generation means that “eventually nearly all resources in the fleet will have some energy limitations.”
In addition to limited oil and LNG supplies and just-in-time natural gas deliveries, the region will face new challenges as the shares of wind and solar generation grow. “As this contingent of energy-limited resources grows, the region’s energy-security risks could become a year-round concern,” he said. “New England’s power system is operating from a strong foundation, but the vulnerabilities we’ve discussed in previous briefings are still here, and still growing.”
The grid operator marked a milestone on April 21, 2018, a sunny day when — for the first time — net load peaked overnight because of strong solar power during mid-day.
“On the other hand, clouds and snow cover prevented solar panels from reaching their seasonal potential during last year’s historic 16-day cold spell, particularly during Winter Storm Grayson,” van Welie said. The cold snap also exposed the limits of energy storage, which van Welie said may eventually “help manage through day-to-day variations but may not be able to charge up again to help when bad weather lasts for multiple days.”
Record-high solar production on April 21 reduced ISO-NE’s net load by more than 2,300 MW at mid-day. | ISO-NE
First Auction Under CASPR
Van Welie said he was pleased with the RTO’s first capacity auction under its Competitive Auctions for Sponsored Policy Resources rules. The February auction made ISO-NE the first grid operator to implement a market-based mechanism to accommodate state-sponsored resources. State-sponsored Vineyard Wind won a 54-MW capacity obligation from a retiring resource in the substitution auction under CASPR.
Forward Capacity Auction 13 cleared at the lowest price in six years, with high levels of new resources, including conventional generators and renewables. Sunrun’s home solar and battery aggregation project became the first in the nation to win a capacity commitment from a grid operator. (See ISO-NE Completes FCA 13 Despite Controversy.)
Van Welie said he expects capacity prices to rise as uneconomical resources retire and declining energy prices — a consequence of increasing renewables with no fuel costs — force generators to seek more revenue from other sources.
ISO-NE’s interconnection queue currently lists more than 150 projects totaling more than 20,000 MW, a level “we’ve rarely seen,” van Welie said. Wind generation represents about two-thirds of the proposed new capacity, more than half of it proposed for offshore. In the past, only about 30% of capacity that enters the queue has come to fruition, however.
Wind power represents almost two-thirds of the proposed capacity in ISO-NE’s generation queue. More than half of the proposed wind is offshore.| ISO-NE
Van Welie said New England states’ increasing renewable portfolio standards are “leading to complexities in market design as well as grid operations, thereby requiring adjustments to both.”
The RTO sees pricing carbon as an “elegant” solution to eliminating out-of-market contracts for renewable resources but has been unable to persuade policymakers to adopt it. “I’ve been a bit of a broken record on this,” said van Welie. He said the Regional Greenhouse Gas Initiative is an “excellent concept” but that its carbon prices are too low to be effective.
Retirements
In June, New England became the first region to price active demand response resources in the daily energy market alongside generators. DR and energy efficiency have been eligible for capacity payments since the start of the capacity market in 2006. In FCA 13, more than 4,000 MW of DR and EE cleared, more than 10% of the total.
Despite the growth in demand-side resources and renewables, however, New England is facing increasing challenges from plant retirements. The retirement of the 677-MW Pilgrim nuclear plant by June “will worsen the region’s energy security risks and its emissions profile,” van Welie said.
ISO-NE says New England states’ increasing renewable portfolio standards are “leading to complexities in market design as well as grid operations, thereby requiring adjustments to both.” | ISO-NE
The region, which will see 5,200 MW of retirements between 2013 and 2022, could face another 5,000 MW of nuclear and coal-fired generation retirements, the RTO says. The region’s nuclear capacity will be reduced to 3,347 MW, with only the Millstone and Seabrook plants remaining.
The RTO is predicting a slight decrease in peak demand over the next 10 years because of EE but says the trend could reverse with the growth of electric transportation and heating. “We don’t expect electric vehicles or heat pumps to have a substantial effect on regional demand in the near future,” van Welie said.
Future Initiatives
Van Welie said the RTO is “facing reality” and does not expect any new gas pipeline capacity. “We have to operate with what we have,” he said, citing more transmission to deliver renewables and imports, and more oil and LNG storage as alternative answers.
Van Welie said the RTO’s Pay-for-Performance incentives, which took effect last June, “may not address all aspects of the region’s winter energy security challenges that have continued to intensify since the incentives were developed.”
Although it provides price signals for resources when the grid is at risk, it does not tell generators of fuel supply shortages days or weeks ahead. “We don’t have a regional fuel gauge that indicates how close we’re getting to the bottom of the fuel tank,” he said.
The RTO’s long-term solution for its winter energy security concerns would expand the current day-ahead market to a multiple day-ahead construct. It will seek to co-optimize its fuel and energy supplies to ride out a seven-day outage of the largest non-gas resource on the system.
“If it’s clear we have more than enough fuel for tomorrow but will run short before the end of the week, resources that can save energy for the end of the week will be properly compensated,” van Welie explained.
It also would include a forward market settlement against the multiday co-optimized market. “The forward market would be seasonal in nature, roughly six months ahead of winter,” he said.
The RTO opened discussions on the proposal in November and plans to provide more details in a white paper in April. It hopes for a FERC filing by November with implementation over three to five years. “This is a very complex project,” van Welie said. “Probably the most complicated thing we’ve done in the history of the ISO.”
(Updated to add PJM’s motion for stay, filed Feb. 21.)
By Christen Smith and Rich Heidorn Jr.
PJM Chief Financial Officer Suzanne Daugherty will retire April 1 after months of recriminations by stakeholders over credit policies that allowed a small trading shop to default on more than $100 million in financial transmission rights losses.
RTO officials declined to say whether Daugherty’s departure was related to the default of GreenHat Energy, saying only that it was her decision to leave. CEO Andy Ott announced Daugherty’s departure in an email Wednesday.
In a brief interview, Daugherty also declined to say whether her departure was related to the GreenHat controversy. “This is the timing for when I decided to move into retirement with my husband” who retired a year ago, she said.
Daugherty said her April 1 departure will allow her to complete PJM’s year-end financial reporting in March. She said she plans to do more traveling with her husband and resume volunteer work in children’s health and education and has no plans to seek a new job. “This is a true retirement,” she said.
GreenHat
Daugherty found herself the target of PJM members’ ire over the RTO’s handling of GreenHat, a small company that was able to procure 890 million MWh of FTRs — the largest FTR portfolio in PJM — while putting up only $600,000 in collateral.
The company, which listed its address as a UPS store in Coronado, Calif., was owned by two traders who previously gained notoriety as participants in J.P. Morgan Ventures Energy Corp.’s scheme to manipulate the Doubling Down – with Other People’s Money.)
At the Market Implementation Committee meeting on Feb. 6, Daugherty told members that a FERC order to rerun the July 2018 FTR auction to liquidate GreenHat’s positions could add $250 million to $300 million to the $186 million the RTO had earlier projected the default would cost members. (See PJM Won’t Act on FTR Order Before Stay Ruling.)
The Board of Managers is expected to issue a report on its investigation of the GreenHat debacle in about a month.
Stay Request Filed
On Feb. 21, PJM filed a motion for a stay on the commission’s order until the commission acts on the RTO’s planned request for rehearing and clarification (ER18-2068).
PJM said the commission ordered rerunning of the August planning period balance FTR auction “without recognition that the results of every auction conducted subsequently likely would be inconsistent — as to FTR paths, megawatt quantities, and ownership — with the revised August auction results.”
The RTO said the order runs “headlong against the commission’s policy against rerunning markets, and its emphasis on avoiding upsetting market participant reliance on settled markets.”
It said rerunning the auction would likely require multiple market participants to post 10 or 20 times as much collateral, pushing some of them in default. It also could give some FTR holders “a free option to retroactively extinguish unprofitable FTRs,” harming others.
20-year Career
Daugherty, who also holds the titles of treasurer and senior vice president, joined PJM in 1998 and became an integral part of the organization, ultimately managing the Business Planning & Analysis Department and serving as controller, liaison to the president and, most recently, as chair of the Markets and Reliability Committee.
In an email announcing Daugherty’s departure, Ott praised her for establishing the stated rate plan, leading the Advanced Control Center project and the Women’s Employee Resource Group.
“We are grateful for Suzanne’s countless contributions to PJM,” he said in the email to stakeholders. “Her relentless focus on driving excellence has helped solidify our reputation as a leading provider of reliable grid operations.”
In 2018, the Philadelphia Media Network — publisher of The Philadelphia Inquirer, Philadelphia Daily News and Philly.com — honored Daugherty with its inaugural Influence of Finance Award for her contributions to PJM as both its longest serving and first female CFO in the organization’s 90-year history.
“It has been my honor and privilege to serve PJM’s employees and members for more than two decades,” Daugherty said in a press release Wednesday. “I am proud to have been part of such an outstanding team doing extremely important work, and I know PJM will continue to forge ahead with innovation, integrity and outstanding service to its members.”
Daugherty told employees about her decision to leave PJM on Tuesday.
Ott assured stakeholders Daugherty’s retirement will not impact day-to-day operations or execution of PJM’s long-term strategy. The RTO said it “has already begun to review its succession plans and will transition Daugherty’s responsibilities in the coming weeks.”
MISO’s Advisory Committee is still deliberating whether state regulators elected to the RTO’s Board of Directors should be subject to the same “cooling-off” period requiring industry executives to wait one year after leaving a regional company before joining the board.
During a Feb. 20 conference call, committee Chair Audrey Penner said the discussion was “simply forward-looking” and that she had not heard of any member challenging the nomination and election of former Minnesota Public Utilities Commission Chair Nancy Lange to the board last year.
Lange’s appointment to the board, made while she was finishing her term on the commission late last year, sparked stakeholder conversations over whether the one-year moratorium for executives should also apply to regulators. Members were mixed in their views, with some sectors — such as independent power producers and utilities — favoring a broader application of the rule, while others thought it should not apply. (See MISO Members Split on Regulator Cooling-off Period.)
A representative from MISO’s State Regulatory Authorities sector Wednesday said the group continues to believe that state regulators are naturally resistant to conflicts of interest.
“Their work is entirely focused on protecting the public. … We don’t have material business relationships, and we take a statutory oath,” Minnesota PUC Commissioner Matthew Schuerger said.
However, DTE Energy’s Nick Griffin said a cooling-off period for candidates across all industry sectors “makes sense.” He said the Transmission Dependent Utilities sector supports the moratorium extension to regulators in MISO states.
The board is awaiting a recommendation from the Advisory Committee as to whether it prefers expanded use of the yearlong sit-out provision. Director Thomas Rainwater, who last year chaired the Corporate Governance and Strategic Planning Committee, has said his committee will act on the Advisory Committee’s recommendation.
Penner asked for more written sector opinions on the topic. The Advisory Committee will again take up the item at its next meeting on March 20 in New Orleans.
MISO estimates that it delivered between $3.2 billion and $3.9 billion in benefits to its members in 2018, the RTO said Tuesday.
The benefits estimate is up from 2017, when MISO said it saved members from $3 billion to $3.7 billion. (See MISO Touts $3 Billion in 2017 Savings.) The RTO estimates its membership benefits annually through its Value Proposition study, in which it attempts to quantify the efficiency and reliability gains from its operations against non-RTO entities. MISO does not track cost savings to individual market participants.
“In a rapidly transforming industry, MISO continues to deliver technological, economic and innovative solutions that benefit our members and stakeholders,” Vice President of Strategy and Business Development Wayne Schug said in a release.
MISO said it can trace most of its 2018 value to its “footprint diversity,” which allows geographically dispersed local utilities with differing load patterns to draw on a wider range of available generating assets, allowing those utilities to significantly reduce reserve margins from 23.7% to 17.7%. That footprint diversity saved members anywhere from $2.2 billion to $2.7 billion in deferred generation investments last year, officials estimate, avoiding the need for an additional 13.6 to 15.9 GW in capacity.
MISO said it also saved members $354 million to $414 million through its wind generation planning and placement efforts in 2018. Centralized economic energy dispatch saved members $282 million to $312 million, while reliability efforts saved $262 million to $285 million, the RTO said.
The 2018 Value Proposition accounts for MISO’s $304 million in operating costs during the year. The RTO estimates it has provided its footprint a total $24.3 billion worth of cumulative net benefits since 2007.
Stakeholders last year questioned the extent of the RTO’s 2017 benefits. During a call last January, one stakeholder contended that MISO should balance its estimates of members’ compliance cost savings with the costs to members of attending stakeholder meetings and monitoring the RTO’s FERC filings. Others pointed out that the figures assumed that the region’s utilities would not otherwise be coordinating activities and reserve sharing absent an RTO.
The federal judge overseeing Pacific Gas and Electric’s bankruptcy case suggested last week he might prohibit the utility’s electricity suppliers from seeking FERC’s help with disputed contracts and order the agency to leave the fate of the contracts to the Bankruptcy Court.
PG&E has indicated it may seek to rescind costly PPAs with solar and wind generators. The utility said it has 387 power purchase agreements with 350 companies worth about $42 billion. Some PPAs, entered into before wind and solar dropped in price, are likely far above current market rates. (See PG&E Wants to Undo Contracts, Revamp Biz in Bankruptcy.)
“The debtors respectfully request that this court issue an order …. [blocking] any entity’s attempt to enforce the FERC order, and any action by FERC, or any other entity, that would attempt to divest or otherwise nullify or impede this court’s exclusive authority to approve or deny the debtors’ requests to assume or reject executory contracts under Section 365 of the Bankruptcy Code,” PG&E’s lawyers wrote in their Jan. 29 motion.
At a hearing Thursday, lawyers for PG&E and generators including NextEra and Calpine, which have PPAs with PG&E, debated the pros and cons of an injunction before Judge Dennis Montali, of the U.S. Bankruptcy Court in San Francisco.
Judge Dennis Montali | Commercial Law League of America
To preserve their PPAs, the generators are seeking to intervene in the PG&E bankruptcy case — another issue Montali must ultimately decide. They also want Montali to deny the injunction.
FERC wants the jurisdictional dispute, involving the Bankruptcy Code and Federal Power Act, heard by a U.S. Circuit Court of Appeals. “The circuit courts have ‘exclusive’ jurisdiction to ‘affirm, modify or set aside’ FERC orders,” lawyers with the U.S. Justice Department argued in court papers filed Feb. 6.
The adversarial proceeding between PG&E and FERC is separate from the utility’s bankruptcy, but the cases are closely linked and are both being heard by Montali for now. FERC’s motion to withdraw the adversarial proceeding from Montali’s courtroom is pending a hearing in May.
At times during Thursday’s hearing, Montali questioned the need for an injunction, but at other points he seemed inclined to issue one. Toward the end of the hearing, he said he might even skip the usual step of issuing a preliminary injunction and move straight to a permanent injunction.
There are no disputed facts in the case, just questions of law, he noted. Issuing a permanent injunction would allow the generators to file a direct appeal, letting a higher court decide the matter and speeding up the case, he said.
“There’s nothing to do between preliminary and permanent” because there are no factual disputes to resolve at trial, Montali said.
In the end, the judge put off a decision, giving FERC time to file its written arguments. The next hearing in the matter is scheduled for Feb. 27.
ERCOT is “much more likely” to deal with “emergency-alert type conditions” this summer given the system’s 7.4% reserve margin, CEO Bill Magness told his Board of Directors and the Texas Public Utility Commission last week.
“With the lower reserve margin, you’re just increasing your risk that any kind of circumstances — low wind, generation outages, extreme weather — could cause challenges on the system this summer,” Magness said during the board’s Feb. 12 bimonthly meeting. “That means bringing on resources we have available and the tools for dealing with that.”
ERCOT CEO Bill Magness (right) details preparations being made for the summer months.
Magness said the city of Garland’s December decision to indefinitely mothball the 470-MW coal-fired Gibbons Creek Generating Station has “effectively reduced” ERCOT’s reserve margin from 8.1%. The grid operator, which has a target planning reserve margin of 13.75%, avoided taking emergency measures last summer despite extreme heat and an 11% reserve margin.
The board took the news calmly as Magness detailed preparations being made for the summer months. Chief among those is the creation of a Gas-Electric Working Group, designed to facilitate reliability coordination between the natural gas and electric industries and ensure clear communication.
GEWG Chair Chad Thompson, ERCOT’s senior manager of operations engineering and support, stressed during the group’s first meeting Feb. 15 that the grid operator doesn’t want to interfere with existing relationships.
“[We] don’t want to get in the middle of your business. ERCOT wants to be a facilitator,” Thompson said.
The GEWG stems from a November gathering that PUC Chair DeAnn Walker held with several trade associations, municipalities, and other members of the electric and gas sectors. The PUC encouraged owners of gas-fired generation facilities, gas pipelines and electric utilities that serve the pipelines to participate in the working group.
“If we do get into a load-shed event, we want a clear understanding of where the critical facilities are,” Thompson said.
Walker has also convened meetings with ERCOT market participants and other stakeholders, similar to what she did before last summer. During the commission’s Feb. 7 open meeting, she said she has received significant input, “Some of it the same as last year.”
ERCOT has gathered transmission owners to ask that any planned outages be limited to off-peak periods and that restoration times be shortened. It will release its final seasonal assessment of resource adequacy on March 5, providing a scenario-based analysis of its summer expectations.
Texas Competitive Power Advocates, a trade organization representing about 60% of Texas generation, has said its member companies are planning to invest $100 million in existing facilities in ERCOT to prepare their fleets for summer demand.
ERCOT’s load and demand projections through 2023 | ERCOT
Advanced Energy Economy and the Sustainable FERC Project last week petitioned FERC for a declaratory order regarding ISO-NE’s possible attempt to retroactively apply new performance standards that would affect the eligibility of energy efficiency resources participating in the RTO’s capacity market.
The petitioners also asked the commission to clarify the appropriate process for changing the terms of market eligibility for EE resources.
ISO-NE’s graph shows the value of energy efficiency resources. | ISO-NE
The Feb. 13 filing cited a series of recent phone calls made by ISO-NE staff to Forward Capacity Market participants with qualified EE capacity resources. During those calls, staff members said that the RTO intends to change how it measures the demand reduction value of EE resources for participation in the FCM.
“ISO-NE staff indicated that the ISO may potentially do so retroactively and without seeking commission approval for these changes, even though the contemplated changes could significantly change the quantity of the resources that have already qualified for, and cleared, the most recent Forward Capacity Auction, FCA 13,” the groups said.
The complaint specifically alleges that the changes may include new “net-to-gross” conversion factors to revalue EE resources, factors “never previously required of, nor imposed on, market participants,” nor defined or described in the RTO’s Tariff or manuals.
The petitioners pointed out those factors were not included in most market participants’ FCA 13 measurement and verification documents — “the qualification determinations which were filed with, and have been accepted by, the commission for participation in FCA 13.”
“ISO-NE has created uncertainty about the methodology it will use to calculate demand resource values going forward, and this is causing real and continuing harm to the capacity market,” the petitioners wrote.
The RTO says the discussed changes are not a settled matter.
“We raised the matter of measurement and verification with EE providers recently and intend to have a more full and complete discussion before any changes would be made,” ISO-NE spokesman Matthew Kakley said.
But one key environmental group is skeptical of the RTO’s intent.
“New England’s grid operator is proposing to change the rules midstream and out of the public eye, without explaining what the new rules would be,” said Bruce Ho, a senior advocate at the Natural Resources Defense Council. “This is absurd. Federal regulators need to step in and ensure that energy efficiency resources get a chance to compete fairly in the capacity market. Any changes to the established market rules must be subject to careful consideration and review.”
The two complainants said they filed the petition to “provide greater certainty” to New England EE resources in the near future.
“The measurement and verification changes proposed by ISO-NE in its phone calls would substantially impact the energy efficiency market in New England, reducing the value of energy efficiency resources in the FCM, driving up prices and ultimately forcing ratepayers to pay higher prices,” they said. “Petitioners and our members and partners hope to work cooperatively to address these issues with ISO-NE in the stakeholder process moving forward.”
ERCOT CEO Bill Magness said last week that the grid operator will use favorable budget variances to fund the addition of real-time co-optimization (RTC), as it has been directed to do by the Texas Public Utility Commission.
ERCOT’s Board of Directors gathers for its February meeting.
In delivering his CEO report to the ERCOT Board of Directors during its regular bimonthly meeting Feb. 12, Magness said staff have identified $43.7 million in favorable variances that would cover the project’s estimated $40 million cost. Much of the variance is because of aggressive interest rate assumptions set in 2017, Magness said.
The PUC last month directed ERCOT to proceed with RTC’s implementation. Commission Chair DeAnn Walker has said that RTC would bring economic and operational benefits to the market. (See Texas PUC Responds to Shrinking Reserve Margin.)
Staff have said it will take four to five years to implement RTC, the process of procuring energy and ancillary services simultaneously in the real-time market every five minutes to find the most cost-effective solution for both requirements.
Magness said he would provide a clearer picture during the board’s April meeting, following a financial audit that determines the final variances.
“As we know from past projects, until we get the protocols written and we know what we’re building, it’s hard to get a much better estimate than the one we’ve provided,” he said.
As for the interest assumptions, Magness said, “We’ll be reupping those and changing those to where we accurately believe we are in 2020 and 2021.”
Staff Present Transmission Planning Report
Jeff Billo, ERCOT’s senior manager of transmission planning, briefed the board on the grid operator’s transmission planning practices, assuring them that staff carefully match projects and needs.
“We take our job very seriously, and we only build what needs to be built,” he said.
Annual transmission costs — charged to consumers to pay for ERCOT’s system — have steadily risen from about $1.3 billion in 2008 to nearly $3.5 billion in 2017. Billo said the rise can be attributed to the Competitive Renewable Energy Zone (CREZ) project, natural load growth and Far West Texas load growth.
According to NERC’s 2018 long-term reliability assessment, ERCOT’s 1.76% 10-year forecasted growth rate trails only that of the Western Electricity Coordinating Council’s Rocky Mountain Reserve Group subregion (1.8%).
“A strong economy leads to load growth,” Billo said.
ERCOT’s Jeff Billo explains the grid operator’s transmission planning processes.
Much of the CREZ project, a 345-kV infrastructure build connecting wind-rich West Texas with urban centers, went into service in 2013. Almost $5 billion was invested that year alone, resulting in a $700 million one-time bump in transmission costs, he said. However, CREZ has also provided a strong 345-kV backbone as ERCOT works to meet the growing petroleum-fueled load growth in the Permian Basin, where peak demand has doubled since 2009.
“Without CREZ, we would have seen a significant amount of transmission needed for far West Texas,” Billo said. “It’s been a challenge keeping up with that growth.”
He said transmission upgrades incorporate double-circuit capability and higher-voltage lines to be able to meet even higher loads in the future. ERCOT has conducted special assessments to try and get ahead of that higher growth.
“Based on 2018 forecasts and studies, our plan is sufficient,” Billo said.
A wave of wind and solar projects in West Texas — “There’s more wind and solar existing or planned than CREZ’s capacity,” Billo said — and increased LNG activity on the Gulf Coast will result in more load growth and congestion. ERCOT has already approved the Freeport Master Plan Project to address LNG growth, and the work to integrate Lubbock Power & Light’s load is expected to relieve constraints in that region. (See “Regulators Grant Preliminary Approval to Sharyland-LP&L Projects,” Texas Public Utility Commission Briefs: Feb. 7, 2019.)
Board Approves Leadership for 2019
Magness introduced Jeyant Tamby to the directors as an ERCOT senior vice president and its first chief administrative officer. Tamby, who was among the officers ratified by the board for one-year terms, served as former CEO H.B. “Trip” Doggett’s (2010-2016) chief of staff. He will bring together many of ERCOT’s corporate functions into a more efficient structure, Magness said.
Magness, who was elected to another one-year term as CEO, also announced the retirement of Human Resources Vice President Diane Williams, who joined ERCOT in 2014.
“I’ve seen pictures of her grandchild,” he joked. “I can’t convince her to stay.”
Craven Crowell and Judy Walsh were re-elected to the board as chair and vice chair, respectively. However, Walsh has stepped down as chair of the Finance and Audit Committee and will be replaced by unaffiliated director Terry Bulger.
The board also confirmed ENGIE’s Bob Helton and the Office of Public Utility Counsel’s Diana Coleman as chair and vice chair, respectively, of the Technical Advisory Committee.
ERCOT, SPP, MISO Hammer out Coordination Plans
ERCOT Assistant General Counsel Nathan Bigbee said staff have revised a coordination plan with SPP and, pending final direction from the board and additional comments, will negotiate the final revisions with its neighbor.
ERCOT has been working on a new bilateral agreement with SPP since 2016 as a result of its switchable generation resource (SWGR) policy review. ERCOT began similar discussions with MISO last year. The three grid operators met to jointly discuss coordination principles and develop updated agreements and are currently taking their coordination plans through their respective stakeholder processes.
Bigbee said the plans offer greater detail around switchable-unit operations during emergency situations. The biggest change authorizes the requesting grid operator to issue directives upon receiving notification of an SWGR’s release. The controlling grid operator is required to notify the resource’s operator that the unit is needed to address an emergency condition in the neighboring region.
The release can be denied should the SWGR’s release “cause or exacerbate” an emergency condition. In the unlikely event of a simultaneous emergency scenario, primary control is assigned to the grid operator when the SWGR’s capacity has been nominated to satisfy that operator’s supply adequacy or capacity planning requirements.
“You may be asking, ‘We don’t even have a capacity market in the ERCOT region. How can we ever be primary?’” Bigbee said. “If the capacity has been nominated to satisfy supply adequacy requirements in the region, then it’s considered to be our capacity. We presume that capacity is going to be available on peak, unless you’ve submitted a notification under the protocols that says the capacity is obligated elsewhere by a contractual obligation during peak-load season.”
ERCOT will post the plans’ final executed versions on its website.
Board Approves Ancillary Service Changes
The board approved the TAC’s recommendation to tweak ERCOT’s ancillary service offerings, which predate the switch from a zonal to a nodal market in 2010. (See “TAC Endorses Granularity to Ancillary Services Products,” ERCOT Technical Advisory Committee Briefs: Jan. 30, 2019.)
The Nodal Protocol revision request (NPRR863) creates a new ERCOT contingency reserve service (ECRS) and modifies responsive reserve service to become primarily a fast frequency response (FFR) service. The changes are designed to provide the grid operator with more “granular tools” to resolve low inertia levels caused by the changing resource mix, and to allow resources to earn compensation for providing primary frequency response.
ERCOT’s ancillary services design has remained the same, as wind, solar and battery resources increase their market presence.
ExxonMobil Power and Gas Services’ Glen Lyons, representing the consumer market segment’s industrial sub-segment, abstained from the vote. Lyons noted the four opposing votes cast during the TAC meeting by industry consumer groups, which opposed the implementation timeline.
FFR will be implemented in 2020 and ECRS no earlier than Jan. 1, 2022.
The board approved eight other NPRRs and two Other Binding Documents revision requests (OBDRRs) on its consent agenda:
NPRR850: Lays out principles for ERCOT and market participants to follow during a market suspension and restart, and how activities will be settled during those events.
NPRR871: Gives ERCOT a mechanism to conduct a reliability review through its normal study process of customer- or resource-funded transmission projects, but without providing a recommendation.
NPRR886: Requires ERCOT, to the extent possible, to provide notice and allow time for comments before executing any new or amended agreement with another control area operator.
NPRR905: Provides resettlement to reflect the proper distribution of the congestion revenue rights balancing account.
NPRR907: Replaces the M1a component of the total potential exposure calculation with a value that can vary based on non-banking business days and ERCOT holidays following the specific operating day. The M1a component sets a time period reflecting the number of days between an operating day and the beginning of a mass transition of the market participant’s electric service identifiers.
NPRR910: Codifies eligibility, pricing and settlement for a resource that has been awarded a three-part supply offer in the day-ahead market but decides not to operate in the real-time market, and subsequently receives a reliability unit commitment instruction.
NPRR911: Reinstates previous language in the applicable protocol sections for determining the real-time LMPs of logical resource nodes for online combined cycle generation resources (CCGRs), following NPRR890’s approval. The LMPs will now be based on their weighted average at the resource node for each of the generation resources in the online CCGRs, using their real-time telemetered outputs to calculate the weight factor.
NPRR915: Defines batteries and other limited-duration resources and clarifies how their qualified scheduling entities should indicate to ERCOT their unwillingness to be deployed in real time, thus reserving the capacity for expected values above the energy offer curve.
OBDRR010: Codifies that the high sustained limit for a resource will continue to be included in the online capacity considered in operating reserve demand curve (ORDC) pricing even when that resource has been awarded a three-part supply offer in the day-ahead market but decides not to operate in the real-time market and subsequently receives a RUC instruction. Related to NPRR910.
OBDRR011: Shifts the ORDC’s loss-of-load probability curve by 0.25 standard deviations in 2019 and by the same measure in 2020, resulting in a single blended ORDC curve.
