State consumer advocates asked the D.C. Circuit Court of Appeals on Friday to review FERC’s Dec. 19 order expanding PJM’s minimum offer price rule (MOPR) — despite the fact that the commission has not acted on numerous requests for rehearing.
FERC’s December order extended the MOPR to all new state-subsidized resources, saying it was needed to combat price suppression in the RTO’s capacity market (EL16-49, EL18-178). (See related story, PJM Stakeholders Get First Look at MOPR Floor Costs.)
The advocates for New Jersey, Maryland, Delaware and D.C. asked the court to hold their petition for review in abeyance, acknowledging that it could be dismissed under the court’s “current precedent,” which holds that FERC’s rulings are not “final” orders ripe for judicial review while rehearing is pending.
The advocates said they filed the petition “out of an abundance caution” because of the pending en banc review in Allegheny Defense Project v. FERC over whether the Natural Gas Act authorizes FERC to issue tolling orders that extend the statutory 30-day period for commission action on rehearing requests (No. 17-1098).(See DC Circuit to Reconsider FERC Tolling Orders.)
The advocates said they feared that awaiting further commission action before seeking judicial review of the Dec. 19 order could deny them the right to do so. “For the reasons stated here, petitioners ask that the court hold this petition in abeyance until the issuance of a decision by this court in Allegheny Defense,” they wrote.
If the court decides FERC cannot issue such tolling orders under the NGA, the advocates said, “that determination would almost certainly mean that FERC cannot do so under the counterpart provision of the [Federal Power Act]. If such a determination were accorded retroactive application, then the [Feb. 18] tolling order would be a nullity, petitioners’ request for rehearing would be deemed to have been denied by operation of law on Feb. 20, 2020 (i.e., 30 days after the filing of the request for rehearing), and the 60-day time period for petitioners to seek judicial review of the Dec. 19 order would have begun on Feb. 21, 2020.”
Oral arguments in Allegheny Defense are scheduled for March 31, with a ruling expected this summer or early fall.
In a note to its clients Monday, ClearView Energy Partners said that the advocates’ “long shot” petition could spur FERC to act more quickly on rehearing, noting that the commission has yet to act on rehearing on its June 2018 order that found PJM’s capacity market unjust and unreasonable and led to the December order.
“A decision that changes the court’s interpretation of FERC’s tolling order authority this fall could potentially complicate the ability of PJM to hold auctions late in 2020 or early in 2021 as it currently plans, as these petitioners may then have grounds to seek an injunction pending appeal,” ClearView said.
AUSTIN, Texas — Infocast’s annual ERCOT Market Summit last week brought together nearly 300 industry representatives and policymakers to discuss the Texas grid and the challenges it faces.
ERCOT CEO Bill Magness keynoted the Feb. 25-27 event, cracking wise as he reviewed the system’s performance during a pair of summers with record demand and tight reserves, while offering his 2020 vision.
“I get to talk about that a fair amount, as that’s a characteristic of the ERCOT market these days,” he said. “It always starts with, ‘Tell me about this summer. I know what you did last summer.’ So I soldier on.”
Magness said he and his staff knew that the summers of 2018 and 2019 would be “pretty challenging” when more than 4.1 GW of the market’s coal capacity was retired in 2017.
“Now that we’ve gone through both [summers], we know how the system performs with tight reserves,” he said.
Despite a reserve margin of just 8.6% last summer, ERCOT was able to meet a record demand of 74.8 GW in early August, breaking the mark set in 2018 by more than 1 GW. The real problem came later in August and September, two of Texas’ hottest months on record, when West Texas wind production dropped during the early afternoon hours. That created a trough of wind energy before coastal wind production picked up, forcing ERCOT to rely on emergency response service to meet demand.
The grid operator called two energy emergency alerts to address the loss of production. Prices, meanwhile, soared during the scarcity conditions, hitting their cap of $9,000/MWh.
“We saw a real solidifying of what’s become a pattern, with the resource mix driven in large measure by the wind,” Magness said. “Most of my mid-afternoons are spent watching the charts, to see if the wind catches up to the load or not. Consequently, we tend to see that our tightest reserves are during those times when we’re in that trough of wind generation.”
Staff are projecting an additional 7.6 GW of new capacity will come online for summer 2020, much of it renewable energy or smaller gas-fired peakers. The grid operator expects a reserve margin of 10.6% this year — still 3 points below its planning reserve margin target of 13.75% — and 18.2% in 2021.
“It’s nice to see double digits, but that’s not materially different from an operations perspective,” Magness said. “People ask me, ‘Are we out of the woods yet?’ And I say, ‘We have become skilled forest creatures.’”
ERCOT and its stakeholders are following the same playbook as they did in preparing for the last couple of summers: limiting transmission and generation outages, strengthening communication with market participants, setting up emergency transfers with neighboring grids, and calling on emergency reserves.
“We’re fully engaged at ERCOT to facilitate whatever shows up,” Magness said.
Participants Offer Kudos to ERCOT’s Market Design
A panel of market participants followed Magness to the stage and added their insights on the ERCOT market’s performance last summer and measures being taken to strengthen it.
Shell Energy North America’s Resmi Surendran suggested the market might have been lucky last year, pointing out the heat didn’t reach 2011 levels, when Texas recorded its hottest summer on record.
“It could have been much worse. If we had had 2011 weather, the peak would have been 78 GW, not 74 GW,” Surendran said.
Katie Coleman, legal counsel for the Texas Industrial Energy Consumers trade group, responded that some of the credit for ERCOT’s energy-only market must go to the market itself.
“We’ve been hearing for the past three summers how lucky we are,” she said. “At some point, you have to start chalking it up to good market design and good market incentives.”
As did other speakers, the panel lamented the lack of pricing signals incenting new baseload generation. Intermittent renewable resources continue to provide much of the new construction and capacity in ERCOT, but they also add more risk.
Referencing a 2014 Brattle Group study on an “economically optimal” reserve margin that suggested a 10.2% reserve margin would lead to a loss-of-load event (LOLE) once every three years, Lower Colorado River Authority’s John Dumas highlighted the potential danger.
“Having a good market design is good. You can be a good driver, but your reaction time at 110 mph needs to be a lot quicker than at 65 mph,” Dumas said. “When you’re shrinking those reserve margins, you’re taking on a lot more risk.”
“The best way to describe the ERCOT market is that it works in practice, but not in theory,” Coleman said. “We’ve gone from planning to a one-in-10 year [LOLE] standard and never had an event, to an event in three years, and we’ve never had it. I think the world is watching what the market is doing here, because consumers are paying less and because of the incentives we’ve created so that resources show up when they’re needed the most.”
The Public Utility Commission and ERCOT continue to tweak the market. The commission in January 2019 directed the grid operator to change its operating reserve demand curve, which provides a price adder during periods of generation scarcity, by combining its curves into a single curve and shifting the standard deviation in its LOLE probability.
Coleman said the standard deviation shift means “prices get higher and stay there longer.” She said the curve combination is more significant because “it says how variable your reserves are year-round, and we’re just going to peanut-butter that across all hours.”
“It is certainly increasing pricing,” she said. “The issue is not a matter of how much you increase prices … you’ll still get the most economic resources. Right now, that’s not thermal generation. If you incentivize thermal resources, I don’t know anyone who thinks that’s a good idea.”
“You may not see any new build announcements from us, but we are putting in $100 million into our Texas fleet,” said Calpine’s Brandon Whittle, noting the upgrades will “capture extra megawatts” and provide more generation for the grid this summer.
ERCOT Works to Stay Ahead of Oil & Gas Growth
ERCOT is conducting its biennial long-term system assessment (LTSA) of the 345-kV system, which it is required to file with the state legislature each even-numbered year. Examining a 10- to 15-year planning horizon, the LTSA uses a range of scenarios to identify upgrades that are robust over a number of the scenarios or more economical than upgrades found in near-term assessments.
The 2018 LTSA report projected a significant amount of additional solar generation and transmission improvements needed to export solar and wind output from West Texas. Not mentioned in the overview is the load growth fueled by the petroleum-rich Permian Basin and other western plays.
“Oil and gas load has been a struggle for us,” said ERCOT’s Jeff Billo, senior manager of transmission planning. “New wires take four to five years to get constructed. The commitments of new growth we’re getting from the oil and gas sector are only one or two years away.”
“Oil and gas load continues to migrate further and further west,” Magness said. “There wasn’t much grid out there too long ago; it was pretty much the end of the system. Where there wasn’t much grid before, we’ll have to muscle it up pretty fast.”
Billo said ERCOT has undertaken a number of initiatives, at the direction of PUC Chair DeAnn Walker, to review its processes and try to stay ahead of the load growth.
“Two things: Can we identify the need for new transmission to serve oil and gas customers sooner, and secondly, can we speed up our process?” Billo said. “Can we get the engineering, the planning done quicker so we can start the construction quicker?”
“It’s pretty clear that new construction [in West Texas] is the No. 1 priority of this current commission,” Electric Transmission Texas President Kip Fox said. “Oil and gas is the lifeblood of Texas. Getting power to those locations is important to the growth of Texas.”
ERCOT’s generator interconnection queue numbered 613 requests as of Jan. 31, with a staggering total of 119.4 GW of capacity under some form of study. Solar requests account for more than half of that (73.6 GW), doubling wind requests (30.6 GW).
Tuan Pham, CEO of solar developer PowerFin Partners, said there’s a reason for the massive amount of solar capacity in the queue: the $15/MW application price.
“A structural problem at a high level is that the cost … is extremely low,” he said. “It takes $15/MWh to get into the ERCOT queue, but the cost to build a solar project is about $1 million/MWh. [The application fee] might as well be zero. I don’t believe the [numbers for] future buildout and supply of solar in the state.”
“I’ll take the heavy under [bet] on everything that’s in the queue,” said Brandon Wax, executive director of commodities for J.P. Morgan. “What the market needs is dispatchable generation, and that is going to be really tough to build. The reserve margin I’m interested in is the reserve margin on those low-wind days. The next three to four years, you’ll see a lot of solar, the occasional peaker and behind-the-meter generation.”
Solar energy has been concentrated in the solar-rich areas of barren West Texas. However, with transmission congestion becoming a factor, developers are now eyeing locations closer to load centers.
“We’re seeing an unprecedented growth on the transmission system of renewable energy, but the great locations have all been sucked up,” Fox said. He referenced the Competitive Renewable Energy Zones (CREZ) project that resulted in the construction of 3,500 miles of transmission, capable of carrying 18.5 GW of capacity, in illustrating today’s problem.
“Build it, and they would come. They just didn’t think they would come as much as they did,” said Fox, whose joint venture between American Electric Power and Berkshire Hathaway Energy was responsible for 20% of the CREZ build. “There’s a lot more requests for interconnections than the CREZ lines are capable of carrying.”
“Transmission planning is a very complex thing. Not only are you planning for reliability, but you’re planning for the future,” said Swaraj Jammalamadaka, vice president of transmission for Apex Clean Energy. “The biggest change is the economics of renewables. There’s demand for cheap, renewable resources. As Kip said, you build it and they will come. They’ve been waiting for a long time. It’s not about congestion today, but forecasting tomorrow. Is the market actually responding to it? It’s very complex to get market design and transmission planning right to ensure the right resources are being used.”
“As a wind or solar developer, you’re trying to get your project online however, whenever,” Wind Works Power CEO Ingo Stuckmann said. “If you look at the system, there’s two elephants in the room. The first elephant is getting the transmission out in the West. We had this CREZ I system built, but where’s our second CREZ system? I don’t think there’s an appetite for another CREZ system.
“The second elephant is the August summer scarcity pricing. How do you meet these prices? In Germany, they’ve designed a system that can be 100% renewable. That’s the cheapest source of remediating all these peaks immediately.”
Is Too Much Demand Response Too Much?
Potomac Economics’ Steve Reedy, acting director of ERCOT’s Independent Market Monitor, said the Monitor is a “pretty big fan” of demand response, be it emergency response service, charges during the four 15-minute coincident peak events during the summer months and “plain old” DR.
Reedy said while the first two DR schemes account for much of the response, he finds “plain old” DR the most exciting.
“That’s what really helps the market become a market, where you actually have buyers and sellers meeting in the marketplace and responding to prices,” he said. “You can respond to the shortage by building more generators, investing money in plants to make them more efficient, investing in tools and procedures to look at prices … that’s the beauty of the energy-only market. The high prices we get during shortages sends price signals to the market, and the market determines the most efficient way to get energy to where it’s needed.”
“You can’t count on demand response for transmission,” he said. “Demand responds to systemwide scarcity conditions, but that may or may not be when a local area is experiencing a transmission constraint, so it may not respond when you need it for transmission.”
Claudia Morrow, vice president of commercial pricing for Vistra Energy, had a simple answer when asked whether the market would see another round of $9,000/MWh scarcity prices this summer.
“Until someone can forecast when the wind is going to blow and the sun is going to shine, that’s going to be a challenge for the market and market participants,” she said. “The answer is to invest and spend capital on plants, to be sure they’re there when needed.”
“The volatility will continue this summer,” said Michael Enger, Austin Energy’s energy market manager. “Our weather will determine whether we see the same magnitude of prices.”
Fellow panelist Brad Richter, Citigroup Energy’s origination director, cautioned against expecting any help from new baseload generation.
“The forward curves do not support additional generation. The market isn’t sending price signals to give us more generation,” he said. “We’re increasingly in an environmental market. It’s all sunshine and wind, and it’s going to keep happening because the forward curve is not incenting new generation.”
What will it take to incent new generation?
“Brownouts … that’s the kind of signal the market’s going to need to wake up and have assets in place to support the market,” Richter said.
New Jersey Gov. Phil Murphy said Friday the state will procure the remainder of its 7,500-MW offshore wind goal in five solicitations through 2028.
Murphy issued an executive order last November directing state officials to acquire 7,500 MW of offshore wind by 2035. The state awarded a contract for 1,100 MW to Ørsted in June 2019. Commercial operation is projected for 2024. (See New Jersey Doubles OSW Target.)
Gov. Phil Murphy | Phil Murphy
On Friday, Murphy announced the state will issue a solicitation for an additional 1,200 MW in the third quarter, with bids due in the fourth quarter and the award announced in the second quarter of 2021. Commercial operation is projected for 2027.
The governor also announced four additional solicitations through 2028, with commercial operation completed between 2029 and 2035.
Murphy said he released the schedule to provide the certainty needed by developers, original equipment manufacturers and others in the OSW supply chain.
“By announcing this planned solicitation schedule, we are demonstrating to our partners in industry and labor that we are committed to implementing this process in a thoughtful way that ensures economic growth for New Jersey,” Murphy said.
“New Jersey opened the largest single-state solicitation, is building a supply chain that will support projects up and down the East Coast, and is poised to double our offshore wind capacity,” New Jersey Board of Public Utilities President Joseph Fiordaliso said. “Offshore wind is a critical component in realizing the governor’s vision of 100% clean energy by 2050 and ensuring our planet survives for future generations.”
Murphy said the schedule could be revised based on the “transmission solutions and development schedule, the status of additional lease areas, permitting, port readiness, establishment of a supply chain, workforce training and cost trends.”
Liz Burdock, CEO of the Business Network for Offshore Wind, thanked the governor for responding to its request for a multiyear schedule of solicitations and said she hoped other East Coast states would follow suit.
“However, we are also concerned that the state does not currently have a long-term comprehensive plan for working with utilities, regional transmission organizations and other grid experts to ensure that the state’s energy systems are ready for the massive gigawatts of power that will be generated off the New Jersey shoreline starting in 2024,” she said in a statement.
“Grid and transmission planning is key to ensuring the steady growth of the U.S. offshore wind industry in the long term. We only have a few years to modernize and increase the capacity of the onshore grid to handle the double task of the electrification of transportation (electric vehicles) and the greatly increased generation of clean energy from offshore wind and solar.”
FERC last week rejected MISO’s bid to expand its Independent Market Monitor’s physical withholding mitigation to include non-capacity resources.
MISO had sought to change its resource adequacy construct to remove provisions that exempt all resources that aren’t planning resources from physical withholding penalty charges in the day-ahead market. On Friday, however, the commission said the proposal was too vague and could effectively subject the RTO’s non-capacity resources to a must-offer rule (ER20-668).
Monitor David Patton had said the proposal would remedy a “flaw” in MISO’s Tariff that excludes non-capacity resources from physical withholding mitigation even if they have market power.
MISO and its Monitor introduced the idea with stakeholders last summer. Patton said the expansion of mitigation would apply only in “clearly” uneconomic behavior from units. Suppliers without market power will not be subject to the new rule and are not under an obligation to offer, he said at the time. (See MISO, Monitor Strengthening Mitigation Measures.)
The RTO had proposed that behavior wouldn’t be deemed physical withholding if a market participant “reasonably expected the costs of making its resource available to be higher than the resource’s expected net revenues from being available.”
But FERC said MISO’s proposed process “lacks sufficient clarity to distinguish between non-capacity resources legitimately withheld from day-ahead markets due to economic reasons and those withheld in an attempt to exercise market power.”
The commission said the proposal’s ambiguity “places non-capacity resources at risk of being penalized in circumstances that do not warrant it.” FERC said it was unclear whether MISO’s market participants would have to prove their units weren’t “economically viable prior to each day-ahead hour.”
The commission also said MISO’s Tariff change was silent as to how seasonally available resources would be treated if an operator decides that it’s economic to operate on a day when it would normally be idled.
FERC also agreed with protesters that MISO’s provision could have the effect of forcing non-capacity resource operators to make offers in the day-ahead market rather than risk potential sanctions. Protesters included several MISO generators, the Electric Power Supply Association, Calpine, Midwest Power Producers, the New England Power Generators Association and the National Hydropower Association.
“MISO’s proposal may effectively create a must-offer obligation on resources that do not receive a corresponding capacity payment,” FERC said. Even though the Monitor promised in an affidavit to be on-hand to discuss ahead of time whether a unit should offer into the day-ahead market, FERC pointed out that MISO didn’t include the pledge in its proposed Tariff language.
Glick Advises Alternate Course
Commissioner Richard Glick tacked a fuller explanation at the end of the order to explain his rejection and urge MISO to find another solution.
“I agree with my colleagues that MISO’s proposal casts too wide a net, putting certain non-capacity resources at risk of being penalized even when they lack market power and, therefore, have no incentive to withhold their capacity for the purpose of driving up prices,” Glick wrote in a concurrence.
However, Glick said he shared MISO’s concern that non-capacity resources could exercise market power through physical withholding.
“The Market Monitor has observed what appear to be exercises of this type of market power by non-capacity resources in MISO over the past several years. Addressing the potential for market participants to exercise market power is critical and would not, in and of itself, require the imposition of a must-offer obligation on non-capacity resources,” Glick said.
Glick said MISO, the Monitor and the stakeholder community should devise another way to prevent non-capacity resources from exercising market power.
Facing opposition from state regulators and consumer advocates, PJM said Monday it will suspend an initiative that could tighten fuel requirements for black start resources.
PJM’s David Schweizer told a special meeting of the Operating and Market Implementation committees that the initiative will go on “hiatus” for several months to allow the RTO to do additional analysis on the potential benefits of requiring some or all black start resources to have a secondary source of fuel in addition to their primary source.
Citing potential capital costs of up to $513 million, the Organization of PJM States Inc. (OPSI) told PJM in a letter Feb. 13 that “with no clear measure of benefit or risk reduction … there is not a strong foundation at this time to support any of the options” under consideration. It recommended “stakeholders consider refocusing their efforts towards exploring risk-informed measures that would be used to better define black start resource availability expectations.”
Based on OPSI’s feedback and discussions with other stakeholders, Schweizer said PJM concluded the “best approach is to step back and further assess the impacts” of the proposals before bringing any of them to a vote. The MIC had been planning a vote on the packages in a special session before its regular March 11 meeting. That special meeting has been canceled.
PJM called for the initiative in 2018, noting that the only fuel assurance requirement for black start resources is that they maintain enough for 16 hours of run time.
During the hiatus, Schweizer said the RTO will pursue a “three-pronged” research project, including expanding a previous study on the impact of delayed restoration resulting from the unavailability of black start units lacking fuel.
“We may look at expanding that analysis to look at more transmission operator zones or a different type of analysis with different assumptions,” he said.
RTO staff also “will look at something with respect to gas pipeline assessment impact analysis” and seek to estimate the economic impact of a delayed restoration “to address the concerns that the state commissions have raised,” Schweizer said.
He said the studies will take “several months to six months.” Staff will provide more details on the studies and timeline at the Market and Reliability Committee’s March 26 meeting.
In the meantime, he said, PJM also will propose a new problem statement and issue charge on the “rather urgent” need to update black start testing requirements. It also would consider updating black start termination and substitution rules and the capital recovery factors for compensation to reflect current tax laws and interest rates.
“ODEC will be very pleased to hear this news,” Old Dominion Electric Cooperative’s Adrien Ford said of PJM’s decision to conduct additional analysis on fuel security before seeking a vote.
Before adjourning the meeting, stakeholders heard summaries of two alternatives to the PJM/Calpine proposal that 100% of black start units have a secondary fuel source. PJM estimates its proposal would require $513 million in capital spending, increasing annual revenue requirements by $67.2 million over the current $65 million.
Alternative Plans
Greg Poulos, executive director of the Consumer Advocates of the PJM States (CAPS), offered a proposal that would limit fuel assurance requirements to one resource per TO zone. “I didn’t see the votes [of consumer advocates and load interests for] going any higher than that. That’s why I put this together,” he said.
Poulos said the proposal was based on discussions with “a couple” of state advocates’ offices but was not an official CAPS proposal, which would require a vote of members. PJM estimated the capital cost of the proposal at $13 million, or $1.9 million per year.
PJM stakeholders are considering proposals that could add $1.9 million to $67 million in annual spending on black start resources. The RTO currently spends $65 million a year. | PJM
After the Feb. 5 MIC meeting, Exelon and the D.C. Office of the People’s Counsel joined on a proposal that each TO zone have at least one fuel-assured black start resource, with additional fuel-assured resources being awarded based on a cost/benefit analysis performed by PJM with input from the TO. (See “States, Advocates Unsure of Black Start Fuel Assurance,” PJM MIC Briefs: Feb. 5, 2020.) PJM estimated the cost would fall between Poulos’ and the RTO’s plan.
Tom Hyzinski of GT Power Group said that even doubling black start costs would add only $2.50/year to his electric bill for an all-electric home. “It’s been asserted that the benefits [of the PJM/Calpine proposal] haven’t been shown,” he said. “The cost of even the most expensive option is relatively modest.”
Erik Heinle of the D.C. OPC noted that the costs would not be spread evenly over the RTO’s footprint. “Some zones wouldn’t pay anything; others would be hit more substantially,” he said.
Thus, he said, PJM should allow state regulators to determine their “risk tolerance.”
“It would be their ratepayers who would be responsible for coming up with that difference,” he said.
FERC last week approved PJM’s updated annual cost responsibility assignments for projects in the Regional Transmission Expansion Plan (RTEP) over the objections of Old Dominion Electric Cooperative (ODEC), which said the RTO should be required to provide more information (ER20-717).
Included in the approvals are assessments for regional facilities, necessary lower-voltage facilities and merchant transmission facilities with firm withdrawal rights, based on the zones’ and facilities’ peak load in the 12 months ending Oct. 31, 2019.
ODEC asked FERC to order PJM to specify each zone’s peak megawatt value and the date and time of the peaks, which were not included in the RTO’s Dec. 31 cost allocation filing. The commission said ODEC should seek the information through the Transmission Expansion Advisory Committee and noted the data are “readily available” on the RTO’s website.
$237M in RTEP Additions
The ruling came a week after the PJM Board of Managers added almost $237 million in baseline transmission projects to the RTEP: FERC Form 715 transmission owner criteria projects totaling $202.37 million and RTO baseline reliability projects totaling $34.6 million.
American Electric Power is responsible for $188.4 million in Form 715 improvements, including projects to correct N-1 and N-1-1 thermal and voltage violations in the western Fort Wayne, Ind., area for contingencies in the Carroll, Sorenson, Columbia and Whitley stations.
PJM’s board approved AEP’S $188.4 million project to correct N-1 and N-1-1 thermal and voltage violations in the western Fort Wayne, Ind., area for contingencies in the Carroll, Sorenson, Columbia and Whitley stations. | PJM
Another AEP project will correct N-1-1 thermal and voltage violations on the Bradley-Sun 46-kV line section and Tams Mountain-Glen White 46-kV line section.
Also making Form 715 improvements is American Municipal Power, which is spending $7.5 million for a new 0.3-mile 138-kV, double-circuit line tapping the Beaver-Black River 138-kV line and expansion of the Amherst No. 2 substation.
Two TOs are making investments driven by reliability or baseline load growth.
Delmarva Power & Light is spending $20.5 million to rebuild 12 miles of the Wye Mills-Stevensville 69-kV line and reconductoring the Silverside-Darley 69-kV line and replacing terminal equipment.
FirstEnergy’s American Transmission Systems Inc. (ATSI) is spending $14.1 million to reconductor an 8.4-mile section of the Leroy Center-Mayfield Q1 line between Leroy Center and Pawnee Tap.
The spending approved Feb. 20 is in addition to $163 million in projects, mostly to address baseline reliability criteria violations, which the board approved Dec. 3.
Previously approved baseline projects to replace three 230-kV breakers in the PSEG zone in Bergen County, N.J., totaling $3 million are no longer required and have been canceled.
Since 2000, PJM has authorized $37.8 billion in RTEP projects.
A U.S. district court last week dismissed with prejudice a lawsuit seeking to overturn a Texas law giving the state’s incumbent utilities the right of first refusal over transmission projects (1:19-cv-00626).
The District Court for the Western District of Texas on Wednesday effectively ended an attempt by a number of NextEra Energy subsidiaries to repeal the legislation (Senate Bill 1938), which they said discriminated against out-of-state transmission developers.
The court also denied intervention requests by nearly a dozen parties.
Passed last May, the law grants certificates of convenience and necessity to build, own or operate new transmission facilities that interconnect with existing facilities “only to the owner of that existing facility.” (See Texas ROFR Bill Passes, Awaits Governor’s Signature.)
District Judge Lee Yeakel said the plaintiffs, NextEra Energy Capital Holdings (NEECH) and four other NextEra transmission owner/developer entities, failed to demonstrate that the law discriminates against out-of-state transmission providers or has a discriminatory purpose or effect.
NEECH, NextEra Energy Transmission (NEET), NextEra Energy Transmission Midwest and Lone Star Transmission alleged that SB 1938 discriminates against interstate commerce by giving electric utilities that already operate in Texas the sole right to build transmission lines with an end point in the state. They based their reasoning on the Constitution’s Commerce and Contracts clauses. (See NextEra Takes Texas to Court over ROFR Law.)
The court found SB 1938 was not “analogous” to the cases the NextEra companies cited, “all of which involve the flow of goods in interstate commerce or burdensome requirements as a precondition for allowing the flow of goods in interstate commerce.”
“SB 1938 does not purport to regulate the transmission of electricity in interstate commerce,” Yeakel wrote. “It regulates only the construction and operation of transmission lines and facilities within Texas, which distinguishes it from the cases upon which plaintiffs rely.”
Hartburg-Sabine Junction project | MISO
Yeakel said the law does not single out Texas transmission providers “as the sole beneficiaries of the right of first refusal over out-of-state providers” and does not “overtly discriminate” by granting incumbent transmission providers the ROFR “because that preference does not discriminate against out-of-state providers.”
“Indeed, most incumbent providers in Texas are owned by out-of-state companies, and SB 1938 allows out-of-state providers a means to enter the Texas market for transmission services by buying a Texas utility,” Yeakel said.
The plaintiffs had claimed standing because the law jeopardizes its Hartburg-Sabine Junction competitive project in southeast Texas. NEET Midwest in 2018 won a competitive bid from MISO for the project, which would consist of a new 500-kV line, four 230-kV lines and a 500-kV substation.
MISO executives have acknowledged that the congestion-relieving project “may face challenges” as a result of the law, casting its future into doubt. (See Uncertainty Deepens for Hartburg-Sabine Project.)
Katie Coleman, counsel for the Texas Association of Manufacturers, said the industrial lobbying group agrees with the decision.
“Industrial companies in Texas see theoretical benefits to a bidding process for transmission but have yet to see a workable model,” she said. “If and when the state wants to move in that direction, it needs to be done deliberately and with appropriate customer protections. Until then, having the current endpoint owners build new lines makes the most sense for customers and the state.”
PJM stakeholders on Friday got their first look at the price floors that could be applied for capacity resources under the expanded minimum offer price rule (MOPR).
PJM shared what it called “informational” net cost of new entry (CONE) values, while The Brattle Group, which was hired by the RTO, gave a presentation on its work to develop avoidable-cost rate (ACR) values, the default minimum price for existing units.
The Brattle Group’s preliminary gross avoidable-cost rate (ACR) for existing generating resources, showing low, high and “representative” costs ($/MW-day) | The Brattle Group
PJM’s informational net CONE numbers range from a low of $235/MW-day for a combined cycle plant to a high of $3,261/MW-day for offshore wind.
PJM’s Gary Helm said the RTO was terming the net CONE values “informational” because they include “placeholder” energy and ancillary services (E&AS) offsets from a 2018 FERC filing. “We feel pretty good” about the gross CONE values, he said.
Brattle’s preliminary gross ACRs for “representative” plants ranged from a low of $40/MW-day for solar PV to $892/MW-day for a single-unit nuclear plant (using 2022 dollars).
PJM’s capacity prices have never exceeded $245/MW-day, a peak set in the EMAAC region for delivery years 2013/14. The RTO’s most recent Base Residual Auction, held in 2018, saw a top price of $204/MW-day in the PSE&G zone.
Resources seeking to offer below the net ACR or net CONE values would have to seek a unit-specific exemption.
Both PJM and Brattle representatives emphasized during the special meeting of the Market Implementation Committee that their numbers were preliminary and would be refined before the RTO makes its compliance filing, due March 18.
Energy & Ancillary Services Offset
PJM’s Pat Bruno began the session with a presentation on the differences between the use of forward-looking and historical E&AS revenues. The E&AS will be subtracted from generators’ going-forward costs to determine unit-specific net ACRs.
The RTO and its Independent Market Monitor currently calculate unit-specific offer caps with a simple average of net E&AS revenues from the three most recent calendar years.
PJM’s preliminary net cost of new entry (CONE) values, including energy and ancillary service (E&AS) revenue offset | PJM
Bruno said PJM intends to allow use of both historical and forward-looking E&AS revenues in determining MOPR offer floors for both new and existing units, consistent with its previous policy on new units.
He acknowledged this could result in an existing unit’s net ACR floor price being above its net ACR offer cap. In such cases, he said, the seller will be required to offer at the floor price.
Becky Robinson of Vistra Energy said the possibility of the floor price exceeding the price cap “is creating a dartboard for people to criticize the justness and reasonableness” of MOPR floor prices. But she said it was unlikely to happen. “Why would anyone use forward-looking [prices] if it would make their MOPR floor price higher?”
‘Irrational’ FERC Ruling on Maintenance
Monitor Joe Bowring gave a short presentation on the IMM’s ACR template and discussed the development of E&AS offsets, including the treatment of major maintenance.
Bowring cited what he called the “unintended consequences” resulting from an April 2019 FERC order requiring that major maintenance costs be allowed in energy offers and no longer included in net ACR calculations (ER19–210). Bowring said the “irrational definition of major maintenance” was made at PJM’s request and over the IMM’s objection. (See FERC to PJM: Clarify Allowable Costs for Energy Offers.)
“The FERC decision removed major maintenance from gross ACR, which would reduce net ACR if nothing else changed. Historical net revenues should not be reduced after the fact by subtracting major maintenance as PJM and Brattle propose. That would effectively mean that ACR was not reduced. Price-based offers were used in the calculation of historical net revenues. If participants wanted to include major maintenance in their energy offers, they would have done so,” Bowring explained after the meeting. “Similarly, for going-forward net revenues, there is no reason to assume that participants will include major maintenance in their energy offers. We have seen no evidence that they do.”
Reducing net revenue to reflect major maintenance would improperly assume that all generators include 100% of their maintenance costs in their offers, Bowring said. “We didn’t see any bump [in prices] after the FERC order. Forwards didn’t really change.”
“Arbitrarily adding major maintenance costs to energy offers will inappropriately reduce net revenues and increase net ACRs,” he added.
Bob O’Connell of Panda Power Funds said FERC’s policy might cause units to run even when LMPs are below their operating costs just to minimize maintenance expenses from start-ups, citing a “rule of thumb” that one start is equal to 20 base hours. That, he said, could suppress energy prices in off-peak hours.
Bowring said O’Connell’s scenario seemed logical but that there was no way for the Monitor to quantify such behavior in unit-specific ACR calculations.
“We put a list of items that shouldn’t be included in major maintenance in our filing, and FERC copy and pasted it in the definition of what should be” included, Bowring said.
‘Representative’ Resources
Brattle’s Michael Hagerty presented the consulting firm’s preliminary default ACR values.
Michael Hagerty, Brattle | The Brattle Group
The group listed costs it considered most representative of each technology along with “representative low” and “representative high” costs to provide a range PJM could consider in its filing. “Not the lowest of the low and the highest of the high,” Hagerty said.
The selection of the “representative” plant for each technology was based on several characteristics, including the distribution of plants by age, state, capacity and — for fuel-burning resources — post-combustion controls.
Hagerty said the firm identified the primary factors affecting cost across fleets and compared publicly available costs with those in a confidential generation project database from design firm Sargent & Lundy.
The “very significant range of plants within each technology … creates a bit of a challenge,” he said. “Our intent was to show what we see in the existing fleet and leave it to PJM to determine where they want to be on this scale.”
PJM Vice President of Market Services Adam Keech said it was too soon to say “what [costs] we think is reasonable.”
“We’re still digesting the data ourselves,” he added.
Brattle noted that its gross ACR values for nuclear units are about 12% lower than the Monitor’s largely because of lower capital cost assumptions and because it estimated that about $1/MWh of operations and maintenance costs should be accounted for in the estimate of net E&AS revenues. Bowring said the $1 reduction was inconsistent with the FERC order on maintenance.
Exelon’s Jason Barker said the Monitor’s characterization of what constitutes variable operations and maintenance (VOM) costs are “illogical and wrong.” Barker indicated that the nuclear capital costs referenced in the Nuclear Energy Institute data, upon which Brattle and the Monitor have relied, are not the classes of costs described in the FERC order.
“It’s not our characterization. It was FERC’s,” Bowring responded.
Energy Efficiency
Brattle calculated a net CONE of $230/MW-day (ICAP) for energy efficiency based on analysis of EE programs of four utilities in PJM: American Electric Power, Baltimore Gas and Electric, Commonwealth Edison and PPL.
It noted its net CONE for PJM EE was higher than estimates for ISO-NE, saying it was because of lower assumed wholesale energy prices in PJM ($29/MWh vs. $60/MWh in ISO-NE).
Brattle calculated net CONE by subtracting wholesale energy savings and transmission and distribution savings from gross CONE but did not consider any capacity savings.
PJM’s Jeff Bastian said capacity market benefits were not included for EE just as they were excluded from the calculations for generating resources.
“This is a load-side resource,” responded Bruce Campbell of CPower Energy Management. “It’s different than a generator.”
Tom Rutigliano of the Natural Resources Defense Council said Brattle appeared to be “vastly undervaluing” EE, saying it should be assessed from the point of view of the asset owner. In addition to including capacity benefits, that means energy savings should be valued at the retail — not wholesale — rate, he said.
“This stuns me that you simply ignore the capacity benefit at the customer level,” Campbell added. “You recognize the energy savings, but you don’t recognize the capacity savings. That just seems inconsistent to me.”
The three-hour meeting ended with a presentation by Michael Borgatti of Gabel Associates on how resources seeking unit-specific price floors would document their actual costs. “The fundamental rule in the Tariff is you have to be able to provide the same level of detail and support as in [PJM’s] CONE study. That is a reasonable standard,” he said.
Borgatti used an example of a 100-MW single-axis tracking solar PV array to identify what he said are errors in PJM’s assumptions. Correcting PJM’s assumptions on useful life (30 years, not 20), construction duration (nine months), weighted average cost of capital (7.7%, not 8.2%) and capacity value (60%, not 42%) reduced the gross CONE from $290/MW-day to $168/MW-day, he said.
Separately, he offered a Lazard proxy that set gross CONE at $143/MW-day, which he said represented “what you should expect market participants to” submit. “There’s a delta there [between $168 and $143], but it’s not significant,” he said.
With a $213/MW-day E&AS offset, he added, net CONE is zero.
Gabel Associates says correcting errors in PJM’s assumptions on useful life, construction duration, weighted average cost of capital (WACC) and capacity factor reduced the gross CONE for a 100-MW single-axis tracking solar PV array from $290/MW-day to $168/MW-day. | Gabel Associates
MIC Chair Lisa Morelli said Borgatti’s presentation would inform PJM’s compliance filing and future discussions on MOPR procedures. She joined Keech in apologizing that some materials for Friday’s meeting were not posted until just hours beforehand.
“You are … getting real-time updates of the latest and greatest PJM thinking,” she said. “It’s a pretty heavy lift within the 90-day compliance [deadline]. You’re seeing a race to the finish.”
Next Meeting
The next scheduled discussion on MOPR will be the MIC’s regular meeting March 11. Morelli said the afternoon would be reserved for MOPR, “if not more.”
SAN FRANCISCO — The former president of the California Public Utilities Commission told a gathering of energy lawyers Friday that common assumptions about the future of renewable energy and electrification need to be re-examined.
Michael Picker, who left the commission in summer 2019, was replaced by Marybel Batjer. Since then, Picker said he’s been working for Gov. Gavin Newsom, putting together an energy roadmap for the state as it tries to reach its ambitious renewable energy and greenhouse gas reduction goals by midcentury. (See Retiring CPUC President Still Has Lots to Say.)
His research has led him to new thinking about reliability and resilience, he told the Western Chapter of the Energy Bar Association at its annual meeting. Picker was the keynote speaker, and his thought-provoking presentation was discussed throughout the day’s proceedings.
For instance, Picker said the idea that the state’s biggest utilities are opposed to clean energy, while community choice aggregators are more progressive, doesn’t pan out in the math.
The state’s investor-owned utilities — the “much maligned” Pacific Gas and Electric, Southern California Edison and San Diego Gas & Electric — had achieved renewable portfolio compliance of 40%, 36% and 41%, respectively, by the end of 2018, he said.
“So that’s not bad progress since the goal was 30% by 2020,” Picker said. “And if you look at the forward compliance, each of them expects to be at 52% or above by 2024.”
Under Senate Bill 100, passed in 2018, the IOUs are expected to achieve primary reliance on clean energy sources by 2045.
Community choice aggregators (CCAs), most of which promise clean energy to retail customers and will become the majority of load-serving entities in coming decades, are falling behind, he said. They’ve proven more reliant on short-term contracts with out-of-state generators, with transmission constraints between source and sink, he said.
The IOUs, with more capital available, have been more successful in signing long-term contracts with in-state generators, whereas the “smaller entities [such as CCAs] with thinner capitalization have had a harder time being able to make those investments in long-term contracts,” he said. (See Calif. Lawmakers Reveal Growing Divisions over CCAs.)
Another issue, Pickers said, is that time-of-day demand from residential and commercial customers is merging.
California’s aerospace and automobile manufacturing economy died away, he said. Those industries used electricity around the clock, working three shifts every 24 hours. Now the state has a lot of “computational-based industries” that mirror household demand, with peaks about 200 hours out of the year, mainly after 5 p.m. on weekdays, he said.
“Who wants to build a power plant that’s only going to be selling electricity for 200 hours per year?” Picker said. “And how do you do that with solar if some of that demand is in the evenings after the effective capacity of solar starts to decline as the sun’s going down to the horizon?”
Rethinking EVs
Picker also noted that there’s a common misconception that generators are responsible for the bulk of greenhouse gas emissions. Electricity generation is responsible for 15% of carbon emissions, whereas transportation is responsible for 40%, he said.
State law requires a reduction in greenhouse gases by 40% below 1990 levels by 2030.
“As the electricity supply gets cleaner, it’s harder to reach that 2030 goal simply on the backs of the electric industry,” Picker said. “We have to address transportation.”
Statutes set a goal of having 2.5 million electric vehicles on California’s roads by 2025, he said. But planners tend to focus on individual ownership of EVs.
“There’s an implicit assumption amongst many of the planners that transportation is going to look the same 20 years from now as 20 years before,” he said. “Most of the policy … is focused on single ownership cars.”
In some urban areas, including Sacramento, more EVs are being charged and parked under car-sharing programs. The cars are taken to central locations where they’re charged at night, when demand is lowest, and distributed throughout the cities during the day.
Why, then, are government planners focused on owners charging cars in their garages? Picker asked.
“Why wouldn’t [car sharing] be the public policy priority rather than people installing [charging stations] in their homes?” he said.
Another point: As more Western states adopt renewable energy goals, the hydroelectric power generated in the Pacific Northwest will become a more coveted commodity, Picker said. And limited transmission will result in greater congestion, he said.
Electricity is becoming devalued as a commodity, while poles and power lines are generating greater revenues, he said.
The focus of policies has been on reducing greenhouse gases, but climate change will require greater resilience, which Picker said is another term for adaptation to changing circumstances.
“What I’m arguing,” Picker said, “is that we’re going to see more and more focus on adaptation.”
FOLSOM, Calif. — As he prepares to leave CAISO this summer, CEO Steve Berberich said a regional transmission organization is essential for maximizing renewable energy use across the West, but that it won’t coalesce under the ISO unless California lawmakers admit other states to its Board of Governors.
California’s governor appoints the five members of CAISO’s board, and the State Senate confirms the appointments. The idea that heavily Democratic California could dictate energy policy to the more conservative states of the Interior West has proven the major obstacle to forming an RTO under CAISO. Similarly, California politicians don’t like the idea of sharing authority over the ISO with coal-burning states such as Arizona and Wyoming.
Asked if he could foresee one or more Western RTOs forming in the future, Berberich replied, “I think it’s an imperative.”
In an interview with RTO Insider at CAISO’s suburban Sacramento headquarters last week, Berberich addressed the question of Western regionalization and talked about his impending retirement from the ISO.
CAISO’s Western Energy Imbalance Market allows real-time trading across state lines, and a proposal to expand it to a day-ahead market could enhance its value, Berberich said. But whether the regionalization effort can move beyond the EIM is problematic, he said.
“There is some desire of those in the West to have an RTO, and I fully respect the fact that some of the out-of-state people are certainly not interested in joining the California ISO’s RTO because of our governance,” he said. “I believe that it’s in California’s best interest to have a regional RTO, and that it be this RTO that is extended. However, I believe that the possibility does exist that other RTOs will form in the West eventually.”
Rocky Mountain states, for instance, could band together, leaving out the West’s coastal states, he said.
“It’s absolutely essential for high levels of renewables to have a regional grid,” Berberich said. “And I take note [that] … Iowa sometimes can meet 100% of its load with its wind fleet. Why? Because they’re part of MISO, and because MISO is such a giant footprint, they can absorb that kind of movement. In Europe, they run the day-ahead market across the entire continent, and they leverage each other’s assets. That’s how you have to do it.”
Although California could go it alone, it could achieve lower energy costs and higher carbon reductions in an RTO with other states, he said. (See Can Calif. Go All Green Without a Western RTO?)
That will only happen if other states are represented on the CAISO board, Berberich said. Even states with similar carbon-reduction and renewable-energy goals, such as Oregon and Washington, won’t join a CAISO RTO without a say in its governance, he said.
“If this ISO is to become the Western RTO, the governance has to change,” Berberich said.
That will be a tough sell in the State Capitol. Lawmakers have already rejected efforts to alter CAISO’s governance structure, most recently with a bill that languished in 2018. (See Western RTO Proponents Vow to Keep Trying.)
“Ultimately, I respect that the policymakers downtown in Sacramento are going to have to make this decision,” Berberich said. “It won’t be ours to make.”
‘The Right Time’
Berberich, 56, a Missouri native, earned business degrees from the University of Tulsa and worked in finance, technology and utilities, including a stint at the former TXU Corp. when it entered the newly deregulated Texas energy market in the early 2000s.
He came to CAISO 15 years ago, serving as vice president of technology, chief financial officer and chief operating officer before taking the helm as president and CEO nine years ago. Berberich earned nearly $1.5 million in 2017 according to CAISO’s Form 990 filing as a nonprofit organization with the Internal Revenue Service.
The announcement came soon after the retirements of two other CAISO leaders in January. Keith Casey, vice president of market and infrastructure development, and Nancy Traweek, executive director of system operations, both retired after more than two decades at the ISO. (See CAISO Announces Leadership Changes.)
The series of high-level retirements are coincidental, each driven by personal circumstances, Berberich said.
“I think it’s the right time for me,” he said, explaining that CEOs and the organizations they lead both need a change every decade or so.
Berberich said he and his wife are planning to move to Dallas to be near their grandchildren. He said he’s not done working but hasn’t decided his next move yet.
The ISO has begun a nationwide search for his successor.
Restoring Trust
Recounting his accomplishments as CEO, Berberich said, “First and foremost, it’s showing the world how you can operate a grid with large amounts of renewables on it and do it in such a way that it’s reliable and efficient and effective — and I think we’ve done that.”
Peaks of wind and solar on CAISO’s system have reached more than 70% and total renewables serving demand topped out at more than 80% on May 15, 2019.
| CAISO
“I can remember when people were concerned about 20% renewables on the grid,” Berberich said. He looked at the board in CAISO’s control room last Tuesday around noon and said, “Right now we’re at 54% on the grid.”
Challenges lie ahead, he said, including serving peak and residual-peak load as the sun sets and solar goes offline, he said. CAISO planners predict potential shortfalls starting in 2021. (See CAISO, CPUC Warn of ‘Reliability Emergency’.)
“EVs are either a marriage made in heaven or a marriage made in hell,” he said.
Another major accomplishment, Berberich said, is the restoration of trust following California’s energy crisis of 2000-2001 and the creation of the EIM, which is on track to have significant participation from entities in every Western state by 2023.
“The EIM has shown that we have established credibility and trust in the region, which was sorely damaged during the energy crisis, and I think being able to turn that around completely to the fact that they would trust us to participate in our market is a big change,” Berberich said.
He said he’s melancholy about leaving CAISO and hopes to be remembered by its staff as a good leader.
“The proudest thing I have here is the people and the culture that we’ve been able to develop at the ISO to embrace the changes facing us,” he said. “We have an amazing group of people here, and I’m just simply humbled to have been able to be part of that.”
