MISO stakeholders continue to voice frustration over two transmission projects included in both MISO’s long-range planning and its interregional Joint Targeted Interconnection Queue (JTIQ) study with SPP.
Multiple stakeholders during Tuesday’s Planning Advisory Committee meeting asked why the RTO continues to show the projects on both its long-range and JTIQ maps. (See MISO Long-range Tx Plan Overlaps with SPP Study.)
Andy Witmeier, the grid operator’s director of resource utilization, said a long-range allocation mechanism is in place while MISO and SPP are just beginning cost-sharing negotiations for JTIQ projects. (See MISO, SPP Regulators to Engage on Tx Cost Allocation.)
Witmeier said while MISO is keeping its options open, it’s almost certain that the two recommended lines in both plans will end up in the long-range analysis. “The benefits to MISO far exceed the costs. The benefits to SPP are small,” he said.
Comparison of projects in MISO’s long-range transmission plan (left) and MISO and SPP’s JTIQ study. The overlapping projects are in the Dakotas and Minnesota. | MISO and SPP
MISO’s Jarred Miland said staff is finalizing long-range project recommendations and will have the first of four portfolios ready for the Board of Directors’ approval in June.
The RTO has said repeatedly that its long-range plan takes precedence over the JTIQ’s project proposals.
“Shouldn’t there be some way of discussing the [project] hierarchy?” energy consultant Kavita Maini asked.
Maini said that MISO should devise some way to allocate a portion of costs to SPP because it knows the other RTO will benefit from the two projects. Other stakeholders chimed in, asking staff to find some way to ensure SPP’s load shoulders some costs, even if they are small.
Otter Tail Power’s Stacy Herbert, who also represents MISO’s transmission owners sector, said many stakeholders seem to mistakenly assume that the two JTIQ projects will move ahead despite the minimal benefit to SPP. She pointed out that historically, the two grid operators don’t ultimately agree on potential projects.
“Projects that move forward are those that have a more even sharing of benefits,” Herbert said. She also said that SPP could share in the long-term project costs through export charges once they are built.
Clean Grid Alliance’s Natalie McIntire asked that the RTOs quickly schedule their JTIQ meetings this year so stakeholders have notice when the next discussions will occur.
The results of PJM’s 2022/23 Base Residual Auction were not competitive, according to a report released last week by the RTO’s Independent Market Monitor.
The 141-page report, coming nearly eight months after PJM announced the results, concluded that the noncompetitive nature of the auction came from “economic withholding by resources” that used offers consistent with the net cost of new entry (CONE) times the “expected average balancing ratio” offer cap, but not consistent with competitive offers based on the “correctly calculated” offer cap.
The Monitor concluded that market prices were “significantly affected by other flaws” in the capacity market rules and in PJM’s application of the rules, including the shape of the variable resource requirement (VRR) curve, the “overstatement” of the capacity of intermittent resources, the treatment of demand response, the minimum offer price rule (MOPR), the inclusion of energy efficiency and EE addback rules.
It also found that, although it played a smaller role in the 2022/23 auction compared to previous auctions, the rules “permitted the exercise of market power” without mitigation for seasonal resources “through uplift payments for noncompetitive offers, rather than through higher prices.”
“Although the impact was small in the 2022/23 auction, the issue should be addressed immediately in order to prevent the impact from increasing and because the solution is simple,” the Monitor said.
PJM’s capacity prices dropped significantly for delivery year 2022/23, falling by nearly two-thirds to $50/MW-day. Overall, the BRA, held May 19 to 25, cleared 144,477 MW of resources for the June 1, 2022, through May 31, 2023, delivery year, costing $3.9 billion, which was $4.4 billion less than the 2018 auction for 2021/22, after an adjustment for an increase in entities choosing to skip the auction by using the fixed resource requirement (FRR). (See Capacity Prices Drop Sharply in PJM Auction.)
Findings
The Monitor found that the 139,666.7 MW of cleared and uplift generation and DR for the entire RTO resulted in a reserve margin of 21.1% and a net excess of 7,660.2 MW over the reliability requirement, which is adjusted for FRR and price-responsive demand (PRD) of 132,006.5 MW. The net excess decreased by 530.1 MW from the net excess of 8,190.3 MW in the 2021/22 BRA.
A scenario summary of RPM revenue in PJM’s 2022/23 Base Residual Auction | Monitoring Analytics
The downward sloping shape of the VRR curve had a “significant impact” on the auction results, the IMM said, resulting in more capacity cleared in the market than would have cleared with a vertical demand curve. If PJM had used a vertical demand curve, it said, total capacity market revenues for the 2022/23 BRA would have been $2.65 billion, a decrease of $1.25 billion (32.1%) compared to the actual results.
“From another perspective, clearing the auction using a downward sloping VRR curve resulted in a 47.3% increase in RPM [Reliability Pricing Model] revenues for the 2022/23 RPM BRA compared to what RPM revenues would have been with a vertical demand curve set equal to the reliability requirement,” the Monitor said.
Accuracy of the peak load forecast also had a significant impact on the results, the IMM said, showing that the forecast for the third incremental auction has been on average 4.3% lower than the peak load forecast for the corresponding BRA for the auctions between the 2017/18 and 2021/22 delivery years. Using the lower peak load forecast, the total capacity market revenues for the 2022/23 BRA would have been $3 billion, a decrease of about $900 million (22.4%) compared to the actual results.
A scenario summary of cleared UCAP in PJM’s 2022/23 Base Residual Auction | Monitoring Analytics
The IMM said an increase in the Commonwealth Edison capacity emergency transfer limit (CETL) of 1,265 MW, or 22.7%, from its 2021/22 level also resulted in an increase of $128 million (3.3%) in revenues.
Dominion Energy Virginia’s election of the FRR lowered PJM’s reliability requirement by 18,233.8 MW. The IMM said that if Dominion had participated in the BRA, total capacity market revenues would have been $4.38 billion and that, excluding FRR resources, total revenues for the rest of the PJM capacity market would have been $4 billion, an increase of $92 million (2.4%) compared to the actual results.
Finally, the Monitor said that if no offers for DR were included in the BRA, total capacity market revenues would be $750 million higher, a 19.2% increase compared to the actual results.
Recommendations
The report included nearly two dozen recommendations for changes to the capacity auction.
The Monitor said PJM should evaluate the shape of the VRR curve because the current shape “directly results in load paying substantially more for capacity than load would pay with a vertical demand curve.” Excess capacity procured in a BRA should not be sold back in any incremental auction “at much lower prices,” it said, asserting that the sales suppress prices in IAs and “provide inefficient incentives for demand resource offer behavior.”
“Given PJM’s assertions of the benefits of over-procuring capacity, it has never been explained why load should pay a high price for capacity in a BRA and sell it back at very low prices in an IA,” the Monitor said. “Such sales are inconsistent with PJM’s assertion that additional capacity purchases have value.”
The IMM said an “enforcement of a consistent definition of capacity resource” is needed by PJM. It recommended that the tariff requirement be “enhanced” to require a capacity resource to be a physical resource and “should apply at the time of auctions and should also constitute a commitment to be physical in the relevant delivery year.”
The requirement to be a physical resource is not currently applied to DR and EE, the Monitor said, both of which are permitted to submit marketing plans rather than evidence of physical resources in the BRA. “The requirement to be a physical resource should be applied to all resource types, including planned generation, demand resources, energy efficiency and imports.”
ERCOT’s legal woes intensified Wednesday, with a Texas appeals court ruling against the grid operator’s long-held claim of sovereign immunity from civil litigation and blame being laid on Gov. Greg Abbott in a U.S. bankruptcy court for the high market prices that contributed to several electric providers going under following the February 2021 winter storm.
The Fifth District Court of Appeals in a 12-1 ruling found that the grid operator’s immunity claim has no basis in Texas law. The case is destined for review by the Supreme Court of Texas. The high court last year avoided making a determination on ERCOT’s claim to sovereign immunity. (See Texas Supremes Sidestep Ruling on ERCOT Lawsuit Shield.)
“The Supreme Court has not extended sovereign immunity to a purely private entity neither chartered nor created by the state, and this court will not create new precedent by extending sovereign immunity to ERCOT,” Justice Erin Nowell wrote in the opinion (05-18-00611-CV).
ERCOT’s Bill Magness (left) and Dan Woodfin speak to the press after the February 2021 winter storm. | ERCOT
Meanwhile in Houston, former ERCOT CEO Bill Magness testified that he was following Abbott’s orders when he directed wholesale power prices to remain at their $9,000/MWh price cap for 33 additional hours. That resulted in $16 billion in market charges that the grid operator’s Independent Market Monitor said were incorrect. (See Texas PUC Won’t Reprice $16B Error.)
Magness said he was told by former Public Utility Commission Chair DeAnn Walker that Abbott wanted the commission and ERCOT to do everything possible to prevent further outages, even as generators were thawing out and returning to service.
Walker followed Magness to the stand Wednesday. While she didn’t exactly corroborate Magness’ testimony, she did say Abbott had told her to “get the power back on” and keep it on. Walker spent several days at ERCOT’s main operations center in Taylor, where she was joined by Abbott adviser Ryland Ramos.
According to Magness’ log of contemporaneous notes, tweeted by Houston Chronicle investigative reporter Jay Root, Walker said Abbott had told her it was “imperative” that the outages not resume. “She was sent to make sure that did not happen, and to come up with solutions to potential problems that could send the system back into outages,” Magness wrote.
Abbott has disputed the account. In statements to the media, Abbott’s gubernatorial campaign has said that he only “instructed everyone involved that they must do what was needed to keep the power on and to prevent the loss of life.”
ERCOT decline to respond to the developments, saying it can’t comment on pending or active litigation.
At issue in the proceeding before the U.S. Bankruptcy Court for the Southern District of Texas is $1.9 billion in market charges ERCOT assigned to Brazos Electric Power Cooperative during the high-price period last February. Brazos is not disputing how much energy it bought to compensate for its own plants that did not run, but it argues it should owe about $800 million (21-03863).
The cooperative filed for Chapter 11 bankruptcy last March when it became evident it wouldn’t be able to pay the billions it owed. As of December, ERCOT said Brazos was still $1.89 billion short to the market. (See ERCOT’s Brazos Electric Declares Bankruptcy.)
Attorney Charles Gibbs, who represents Brazos’ largest member, CoServ Electric, popped in to the Infocast ERCOT Market Summit last week to deliver a brief update on the case.
“This will play out over the next few years. That’s the financial overhang of the storm,” he said.
Gibbs predicted that the judge overseeing the case, David R. Jones, will likely find in favor of Brazos. He said Jones may find the charges are not a legal good, or associated with priority claims, but noted that what took place during the storm was hardly the ordinary course of business.
“It can’t be a charge incurred during the ordinary course of business,” Gibbs said.
What happens if the ruling goes against ERCOT? he was asked.
“How does ERCOT pay? They’re a clearinghouse,” Gibbs said. “What assets do they have?”
The Fifth District ruling only adds to the grid operator’s legal problems. If upheld by the Texas high court, it would open the door to hundreds of lawsuits from Texas citizens seeking compensation for family members who died and property damage.
Attorney Majed Nachawati, with Fears Nachawati, said in a statement to RTO Insider that he looks forward to getting justice for his clients.
“We remain hopeful that state and federal prosecutors will hold the power companies and corrupt politicians accountable in the criminal justice system as well,” he said. “The public demands accountability, and we all must do our part to eliminate corruption and greed that harms everyone.”
The appeals court ruling stems from a lawsuit filed by energy investment company Panda Power Funds over $2.2 billion it said in invested to build three power plants in Texas. Panda said the decision was based on ERCOT projections that indicated energy supply shortages for years to come. The company has alleged the grid operator committed fraud and that Panda is selling power for less than what it expected because of the erroneous projection.
Three newly proposed call areas off the Oregon coast mean offshore wind could be a multistate affair in the West, requiring integrated planning and transmission, panelists said at Thursday’s annual meeting of the Energy Bar Association’s Western Chapter.
The U.S. Bureau of Ocean Energy Management (BOEM) identified the Oregon call areas Thursday, shortly before the meeting. Last year, BOEM said it would offer leases in two offshore wind areas in Northern and Central California, the first offshore wind developments on the West Coast.
“The growing Pacific Coast scale of this, which has just been expanded [with that day’s BOEM announcement] … sets in motion a whole set of speculation about coordination across the region,” said Adam Stern, executive director of Offshore Wind California.
The three large areas off the coast of southern Oregon could support up to 17 GW of generating capacity total. BOEM said in a presentation last week it intends to consider 3 GW for “near-term commercial development.” The presentation, which first identified the proposed call areas, was published Thursday in preparation for Friday’s meeting of the BOEM Oregon Intergovernmental Renewable Energy Task Force.
Five study areas off California’s north and central coasts could potentially support 21 GW of offshore wind, according to a study published in 2020 by the National Renewable Energy Laboratory (NREL). BOEM ultimately decided to pursue commercial development of 4.6 GW: 3 GW in the Morro Bay Call Area off the Central California coast, and 1.6 GW in the Humboldt Call Area off the Northern California coast. (See BOEM to Offer Leases for Calif. Offshore Wind.)
Three newly identified call areas off the Southern Oregon Coast could eventually generate 17 GW. | BOEM
The northernmost point of the Humboldt Call Area and the southern boundary of Oregon’s Brookings Call Area are about 60 miles apart.
An auction for the California’s first offshore wind leases is expected this fall, pending approval by the state Coastal Commission.
The auction will be like last week’s sale of six leases in the New York Bight, which drew competitive bids totaling nearly $4.4 billion. It was the “nation’s highest-grossing competitive offshore energy lease sale in history, including oil and gas leases,” the U.S. Interior Department said in a news release. (See related story, Fierce Bidding Pushes NY Bight Auction to $4.37 Billion.)
“These results are a major milestone towards achieving the Biden-Harris administration’s goal of reaching 30 GW of offshore wind energy by 2030,” the department said.
The New York auction’s high prices are potential harbingers of lease prices in California, EBA panelists said.
Ports Problematic
California, however, is different from the East Coast in several ways, including the need for more expensive floating wind turbines for its deeper waters and a lack of port infrastructure to build and support offshore wind farms, panelists noted.
“The ports are a huge issue in California,” said Ella Foley Gannon, a partner at law firm Morgan Lewis in San Francisco. “Our ports are not well situated to these wind areas.”
The NREL study found “distance to port” in California would be a major driver of construction, operation and maintenance costs for offshore wind farms. Major ports in Los Angeles, the San Francisco Bay Area and San Diego are either too distant, unsuitable or both.
Floating wind turbines can be assembled in port and towed to sea, saving time and money, but bridges in San Francisco and San Diego create obstacles, it noted. “The Golden Gate Bridge, for example, has an air draft limit of 67 meters, rendering all of the San Francisco Bay ports unsuitable for floating wind turbine assembly,” it said.
Expanding and improving lesser ports that are closer to the wind areas is one possibility, but that will require large upfront investments.
Theodore Paradise, executive vice president for strategy at Anbaric, a developer of offshore transmission, said the West Coast will need infrastructure more like the East Coast’s to attract top-dollar bids.
“I think part of what we’re seeing in the New York Bight today is a tipping point around confidence over infrastructure,” Paradise said.
The East Coast had public-private partnerships emerge to develop port facilities, he said.
New Jersey is building the New Jersey Wind Port, which can serve the New York Bight and other East Coast wind development areas. The state appropriated $400 million for the first phase of the project, including channel dredging and establishing marshalling and manufacturing sites. Private companies such as Siemens Gamesa Renewable Energy have applied to be tenants.
California Gov. Gavin Newsom’s fiscal year 2023 budget includes $45 million for port development, but far more will be needed, panelists said. The $1.2 trillion infrastructure bill signed by President Biden in November contains $17 billion for port upgrades, some of which could go toward development for offshore wind, they said.
‘Planning Big’
Another factor is transmission, which is more cost-effective when built to encompass larger offshore wind areas, they said. In Germany and the Netherlands, projects are being planned on a large scale with 2-GW cables, they said.
Early experience with smaller East Coast projects created a “spaghetti of cables across the ocean floor,” costing far more to develop and more per megawatt, Paradise said. California and Oregon could learn from that experience and develop state or regional transmission plans, he said.
He likened offshore transmission to the Texas Competitive Renewable Energy Zones transmission project, which transports wind energy from West Texas and the Texas Panhandle to population centers in the eastern part of the state.
CAISO recently included offshore wind in its inaugural 20-year transmission plan, a positive step, panelists said. The ISO said the state needs approximately $8 billion for 500-kV and HVDC lines to carry 7 to 13 GW of offshore wind to major urban areas. (See CAISO Sees $30B Need for Tx Development.)
“I think a key thing is planning big and planning for scale,” OSW California’s Stern said. “We need to achieve a state-based supply chain in order for this to create the jobs and other benefits associated with offshore wind. And that’s only going to happen if there are high targets and there is a supporting infrastructure investment that the state of California can make in its ports, in its grid and in some of the other resources that will be needed to make this possible.”
The latest report from the U.N. Intergovernmental Panel on Climate Change (IPCC) carries a stark and urgent warning: The intensifying impacts of climate change are outpacing nature’s and societies’ abilities to adapt to or mitigate them.
Further, the report says, humans’ reactions — or lack of reactions — to climate change can increase the vulnerabilities already being caused by “the dynamic interactions among climate-related hazards.”
In the U.S., higher temperatures could “increase power system costs by about $50 billion by the year 2050,” the report says.
Heat waves could trigger soaring power prices in spot markets, with heavy impacts for low-income and disadvantaged consumers, the report says. Similarly, disruptions to weather patterns can also affect demand peaks and curves as residential and commercial customers respond to short-term “weather shocks” and longer-term changes.
“The energy system is really integral to thinking about the entire climate change issue,” said Delavane Diaz, a project manager at the Electric Power Research Institute (EPRI), who worked on the IPCC report.
Electricity systems can be especially vulnerable to extreme weather events, Diaz said.
“Depending on the climate impact driver, whether it’s extreme heat or flooding or wildfire, it can affect all elements of the system,” she said, from upstream fuel supplies to generation to consumption patterns.
Other power system vulnerabilities identified in the report include:
the impact of drought on water supplies, not only for hydropower generation but for the cooling systems needed for fossil fuel plants;
reduced output from photovoltaic solar panels in high and extreme heat as well as the potential need for additional cleaning of panels because of wind-blown sand. Rising temperatures could result in a 1% decrease in solar power production per year until 2049, the report says;
potential damage to distribution and transmission lines caused by extreme weather events, resulting in longer and more frequent power outages, with disadvantaged communities disproportionately affected.
“Increases in windstorm frequency and intensity increase the risk of direct damage to overhead lines and pylons,” the report says. “Where the mode of failure is recorded, transmission pylons are seen to be more susceptible to wind damage, whilst distribution pylons are more likely to be affected by treefall and debris.”
Climate-resilient Development
The IPCC report’s 3,675 pages are largely focused on the environmental impacts of climate change and the cascading effects that disruptions in one sector can have across others.
“This report recognizes the interdependence of climate, biodiversity and people and integrates natural, social and economic sciences more strongly than earlier IPCC assessments,” IPCC Chair Hoesung Lee said. “It emphasizes the urgency of immediate and more ambitious action to address climate risks. Half measures are no longer an option.”
For example, the report predicts that ongoing climate-related disruptions to supply chains and trade will cause “large market and non-market damages” to the North American economy.
The report’s big-picture solution is a call for “climate-resilient development,” which Diaz described as “kind of integrating both the climate impacts and the potential for adaptation responses into the same planning process.”
“So, when you think about the electric power system, we want to be able to plan for future conditions in terms of maybe the temperature distribution shifting or the frequency of extreme events maybe increasing,” she said. “It’s both accounting for the changes that are linked to climate change at the same time as integrating adaptation options, which could include changes to the technologies themselves or the way that they are operated.”
Debra Roberts, co-chair of the IPCC working group that produced the report, also stressed the importance of holistic solutions. “Tackling all these different challenges involves everyone — governments, the private sector, civil society — working together to prioritize risk reduction, as well as equity and justice, in decision-making and investment,” Roberts said.
“By bringing together scientific and technological know-how as well as Indigenous and local knowledge, solutions will be more effective,” she said.
Limits to Adaption
Environmental groups echoed the reports warnings and its call to action.
“Even small increases in warming can multiply harmful impacts in the future,” said Daniel Bresette, executive director of the Environmental and Energy Study Institute.“But that does not mean our situation is hopeless. We have a small window of time to act, so we need to act now.”
Cherelle Blazer, senior director of the Sierra Club’s International Climate and Policy Campaign, called on Congress to pass strong climate legislation — without specifically mentioning the stalled Build Back Better Act.
“Each day that passes without Congress passing legislation investing in climate, jobs and justice is another day of needless stress and suffering for millions of people in the U.S. and abroad,” Blazer said. “There are limits to adaptation, and a stark pivot away from the fossil fuel economy to clean, renewable energy is required.”
At the same time, Diaz believes that the U.S. energy sector should not only look at the future through a climate lens, but should also include factors like decarbonization policy, technological innovation and socio-economic trends.
“It’s not to say that climate change isn’t a priority, but it really needs to be looked at in an integrated setting because these factors can interact with each other,” she said. “Simply trying to impose a future climate projection on the current system misses all of these other elements.”
The Biden administration’s decision to make hydrogen key to decarbonizing the economy appears likely to pause the fierce competition for new industry among some states, including Ohio, Pennsylvania and West Virginia, three Rustbelt states in northern Appalachia.
The three states in February launched their own preliminary initiatives in preparation for the U.S. Department of Energy’s competitive bidding process for hydrogen manufacturing hubs, set for later this spring.
A Pittsburgh-based alliance of shale gas companies and heavy industry, including Ohio-based Marathon Petroleum, announced its formation on Feb. 3 to local business media on letterhead of shale gas company EQT. The group committed to working “with stakeholders on a shared vision for a low-carbon and hydrogen industrial hub in Ohio, Pennsylvania and West Virginia.”
Other members of the alliance are Norwegian energy company Equinor, GE Gas Power, Mitsubishi Power Americas, U.S. Steel and Shell Polymers, which is building a polyethylene plant 30 miles from Pittsburgh, cracking ethane molecules extracted from natural gas. Ohio was a runner up in the competition for the cracker plant.
On Feb. 9, the Ohio Clean Hydrogen Hub Alliance, an organization with 70 members including Dominion Energy Ohio and Columbia Gas of Ohio, announced it intended to compete to convince DOE to put a hydrogen hub in Ohio. The alliance had been organized by the Stark Area Regional Transit Authority (SARTA) — a public transit company with a fleet that includes 20 emission-free hydrogen fuel cell buses — and the Midwest Hydrogen Center of Excellence at Cleveland State University.
But by the end of last week, participating industries — and state government representatives from the three states — attended a phone conference initiated by the Battelle Institute, a global research and development organization headquartered in Columbus, Ohio, that is familiar with and to DOE because it manages nine federal laboratories.
DOE has $8 billion authorized by the Infrastructure Investment and Jobs Act to foster the development of four regional hydrogen hubs, including two regions with heavy natural gas development. That makes northern Appalachia, with its Marcellus and Utica shale plays, a qualified candidate.
The region produced 32.5 Bcfd in 2020 and averaged 31.9 Bcfd in the first half of 2021, more than any other region, according to the Energy Information Administration. DOE intends to accelerate the production of so-called “blue” hydrogen, produced by steam reformation of methane with the resulting carbon dioxide either used commercially or sequestered permanently in geological formations.
The cost of blue hydrogen is currently a fraction of the cost of green hydrogen, produced with renewable power through electrolysis. In addition to the $8 billion to foster the creation of regional hydrogen hubs, the infrastructure law authorizes DOE to spend another $1 billion to accelerate hydrogen electrolysis programs and $500 million for hydrogen manufacturing and recycling initiatives. The department refers to both blue and green hydrogen as “clean hydrogen.”
“Clean hydrogen is key to cleaning up American manufacturing and slashing emissions from carbon-intensive materials like steel and cement while creating good-paying jobs for American workers,” U.S. Secretary of Energy Jennifer Granholm said in a Feb. 15 statement announcing a request for information from the public that it will use in its creation of the hydrogen hub program. That input is due Mar. 8. Reponses to another RFI, on clean hydrogen manufacturing, recycling and electrolysis, are due Mar. 29.
AUSTIN, Texas — The state’s top electricity regulator, Public Utility Commission Chair Peter Lake, last week addressed the “ambiguity” over the second round of changes at ERCOT meant to address shortfalls in the grid’s performance during last February’s devastating winter storm.
Delivering the keynote address during Infocast’s ERCOT Market Summit on Feb. 23-25, Lake said the commission will develop two “products”: a load-serving entity reliability mechanism (LSERM) and a backstop reliability service (BRS).
“It’s not a contest; it’s not a debate. We did all that,” he said, referencing last year’s series of PUC workshops on market changes. “We will develop those products and build them out.”
However, Lake said the PUC will not accept any version of the proposals “sight unseen.” He promised “a lot” of stakeholder engagement “to ensure we get those right.” He promised to bring in consultants of the “highest caliber” to analyze the products’ different versions and help develop a “turnkey product” for ERCOT’s implementation.
“The commission is committed to adopting those proposals,” Lake said.
He said the LSE reliability product will capture the best features of five different similar mechanisms. LSEs would be subject to a formal reliability standard and be subject to penalties for nonperformance to ensure they have sufficient resources meet this standard.
“All put the obligation on the retail market, not the centralized administrative entity of ERCOT,” Lake said. “We believe the market is much better at procuring than a centralized governmental body. We will make it fungible, as easily integrated into the market as possible.
“We obviously want clear performance standards. We want forward pricing signals, for both investment and future generation of any kind and any form,” he said.
Lake brought up what he refers to as ERCOT’s “blue sky problem”: those normal 75-degree days when wind and solar drop off and put the grid in a “near crisis” condition.
“A lot of that is due to the intermittency of our renewable fleet,” he said. “We’ve been very deliberate as a commission to say we’re going to address the strength and drawbacks, pros and cons, of each resource. One of [renewables’] drawbacks is they’re not dispatchable. You can’t turn them on on-demand.
“Those two problems, the blue-sky problem and extreme weather problem, that’s what we’ve been addressing in the market design.”
Market Participants Respond to Lake
Lake’s failure to include wind and solar resources among the PUC’s dispatchable desired generation types, which also included hydrogen and geothermal, did not go unnoticed by some attendees.
Speaking on the panel following the chairman’s comments, Erika Bierschbach, Austin Energy’s vice president of energy market operations and resource planning, asked, “Do you want to incentivize future technology or some of those from the past?
“Some of those things out there … are just keeping things on support,” she said.
Fellow panelist Resmi Surendran, with Shell Energy, put in a plug for energy storage.
“ERCOT should say what is the quality and the quantity of the megawatts that are needed, and anyone who wants to provide them, can provide them,” she said. “Batteries can provide a lot of functions.”
Vistra’s Ned Bonskowski, senior director of Texas regulatory policy, addressed Lake’s move away from the ERCOT market’s previous “crisis-based” model, where prices jumped during supply-scarcity conditions.
The grid operator’s conservative operations approach to managing the system by securing up to 8 GW of reserves at times has effectively dampened prices. Bonskowski said prices have largely stayed below $75/MW until an approaching cold front last week resulted in prices briefly hitting $4,000/MWh at one point.
“A very conservative operating theory … means more reserves are sitting there, which is more supply for relatively the same amount of demand. That tends to push prices down and you end up with a soft cap at $75,” Bonskowksi said. ”We’re in a period right now that’s pretty perilous from a market redesign standpoint. We got that little beacon of light this morning from what the market design ought to look like. Market participants had said they would like to see that sooner, but we understand this needs to be a robust process.”
A New ‘Policeman of Electricity’
Barksdale English, who directs the PUC’s Division of Compliance and Enforcement, said there is a new sheriff in town when it comes to enforcing the commission’s rules on weatherization, one of the key changes that came out of last winter’s storm.
“Or, as my daughter likes to say, I am the policeman of electricity,” he said.
New rules required generators and transmission providers to file winter readiness reports by Dec. 1 for each of their units and their facilities, respectively. Eight companies failed to meet the deadline, with PUC staff recommending $7.68 million in administrative fees. (See “PUC Docks 8 Generators,” Texas PUC Chair Lake: ‘The Lights Will Stay On’.)
“The [state] legislature made it abundantly clear that they wanted, and their constituents wanted, their commission to take a different approach to the regulatory regime around preparing resources and facilities for extreme weather. One of the ways they signaled that was by changing rules around maximum penalties,” English said.
“The commissioners, when they discussed it, made it abundantly clear that: a) they expect their staff to use the full range of that penalty authority to signal to the rest of the industry and citizens of Texas that we took that mandate from the legislature pretty seriously, and b) to use it as a stick to get folks to do their best to get in compliance with the rule,” he said.
An audience member asked English why one 4.4-MW resource was assessed a $1.1 million penalty.
“If I allow one person with 4 MW to be out of compliance, I’ll have a bunch,” he said. “We have to treat everyone fairly and treat it seriously. If I don’t take that outage seriously, how can I take the next one seriously?”
The Supreme Court’s liberal wing defended EPA’s authority to impose “beyond-the-fence-line” regulations on power plants Monday, while conservative justices provided fewer signals on their leanings during oral arguments in a challenge by the coal industry and 20 states.
The arguments focused on EPA’s authority to regulate greenhouse gas emissions under the Clean Air Act and whether the Clean Power Plan (CPP), proposed by the Obama administration, was nullified in January 2021 when the D.C. Circuit Court of Appeals rejected the Trump administration’s replacement, the Affordable Clean Energy (ACE) rule.
The D.C. Circuit’s 2-1 ruling vacated the ACE rule and remanded it to EPA for further action. (See DC Circuit Rejects Trump ACE Rule.)
West Virginia Solicitor General Lindsay See | The Federalist Society
West Virginia Solicitor General Lindsay See told the court Monday that Section 111 of the Clean Air Act directed EPA to “partner with the states to regulate [emissions] on a source-specific level.” But the D.C. Circuit ruling went far beyond that, See said, violating the “major questions” doctrine — that Congress must be explicit in giving an administrative agency the power to make “decisions of vast economic and political significance.”
“Electricity generation is a pervasive and essential aspect of modern life and squarely within the states’ traditional zone” of authority, she said. “Yet EPA can now regulate in ways that cost billions of dollars, affect thousands of businesses and are designed to address an issue with worldwide effect. This is major policymaking power under any definition.”
The court agreed to consider the matter in October, consolidating four challenges and saying it would hear one hour of oral arguments (West Virginia v. EPA, 20-1530). But — perhaps reflecting the case’s potential implications beyond EPA’s authority — Chief Justice John Roberts allowed the arguments to stretch on for two hours. Observers have said a ruling that concludes EPA lacks authority to decide matters of “vast economic and political significance” could have a wide impact on administrative law.
Nothing to See Here
Justices Stephen Breyer, Elena Kagan and Sonia Sotomayor asked most of the questions during the session, with Clarence Thomas and Samuel Alito leading the questioning by the conservative wing.
U.S. Solicitor General Elizabeth Prelogar | Justice Department
U.S. Solicitor General Elizabeth Prelogar said the court should reject the challenge because EPA has no plans to resurrect the CPP. “Petitioners aren’t harmed by the status quo,” she said. EPA expects to issue a replacement Notice of Proposed Rulemaking by the end of 2022, with a final rule likely about a year later, she said.
Prelogar also contended there is no “major question” at stake. “For all their criticisms of the CPP, we know that it wouldn’t have had major consequences. The industry achieved the CPP’s emission limits a decade ahead of schedule and in the absence of any federal regulation,” she said.
But See said the D.C. Circuit’s ruling vacated both the ACE rule and the Trump administration’s repeal of the CPP.
“We’re injured by a judgment that brings back to life a rule that hurts us and it takes off the books a rule that benefits us,” she said. She added that EPA’s brief indicated “that they might enact the very same provision, and they have told you nothing different here today. … Even though nationwide, the emission levels have been largely met for the Clean Power Plan, 20 states have not met them.
“This is an area where the parties need certainty,” she added. “The states and regulated parties make decisions decades in advance.”
‘Fence Line’ Arguments
The CPP sought to cut power sector carbon emissions by 32% by 2030, compared with 2005 levels, through “generation shifting”: substituting coal-fired generation with natural gas and renewables. The challengers say that EPA’s authority to regulate power plants is limited to steps individual plants can make “inside the fence line.”
Justice Stephen Breyer | Supreme Court
But Breyer, Kagan and Sotomayor said they disagreed with that interpretation, noting that Section 111(d) empowers EPA to impose standards “for any existing source” based on limits “achievable through the application of the best system of emission reduction” that has been “adequately demonstrated.”
Breyer said he agreed that Congress did not give EPA authority to impose regulations that would change “the economic system of the United States.”
“But you want to jump from there to the idea that [regulation] has to be plant by plant,” he told See. “It’s easy for me to think of a system that they might choose that isn’t plant by plant or isn’t within the fence, but isn’t really a big deal.” For example, he said EPA could order PJM to add a carbon fee to its security-constrained economic dispatch, which selects generation in least-cost merit order.
Justice Elena Kagan | Supreme Court
Kagan said an inside-the-fence regulation“can be very small, or it can be catastrophic.”
“There are inside-the-fence technological fixes that could drive the entire coal industry out of business tomorrow. And an outside-the-fence rule could be very small, or it could be very large,” she added. It “bears no necessary relationship to whether a rule is major in your sense of expensive, costly, destructive to the coal industry.”
See responded that the law’s requirement that EPA must use systems that lead to achievable emission reductions that are adequately demonstrated suggests Congress intended “source-specific” requirements. “They don’t make sense when EPA is regulated at a grid-wide or nationwide level,” she said.
“‘System’ is a broad word,” she acknowledged. “But Congress paired it with limits. … The D.C. Circuit’s interpretation of the statute doesn’t give EPA any place where it has to stop. The fact that it puts self-imposed handcuffs on in the Clean Power Plan does not mean it would need to do that in the next rule.”
Justice Sonia Sotomayor | Supreme Court
Kagan responded: “It does give EPA a place to stop, because the statute also says you have to consider cost and you have to consider various other factors. … It very clearly says that there are other constraints that have to be considered to impose reasonable limits.”
“I agree with you if we are talking about measures that a particular source can take, because then you would be able to look at cost and make a reasoned determination,” See countered. “But if EPA is looking at the national, or grid-wide level, and if it’s dealing with an issue as massive as climate change, it’s hard to see what cost wouldn’t be justified. So that cost limit isn’t really serving as a limiting factor.”
Cooperative Federalism
Justice Clarence Thomas | Supreme Court
Kagan said the statute’s reference to “system” suggests that Congress intended to give EPA flexibility, “understanding that this was an area that was going to move very fast [and] has lots of technical components to it; that it wanted to give the agency flexibility to regulate as times changed, as circumstances changed, as economic impacts changed, or things that they couldn’t possibly have known at the time” changed.
West Virginia’s interpretation, she said, would undermine the notion of “cooperative federalism.”
“If the state decides, ‘This is what we want to do. … We actually think it’s less costly than some of the inside-the-fence alternatives,’ your reading essentially says, ‘Too bad.’”
Prelogar referenced a brief by utilities including Consolidated Edison, Exelon and National Grid supporting EPA’s position.
She said a system that involves carbon capture and sequestration paired with trading would allow plants to decide whether to make the carbon-capture investments to reduce emissions low enough to generate trading credits while others would find it more cost effective to buy credits.
“The system is … reducing emissions across the source category as a whole; it’s just doing so in a very cost-effective way, which I think explains why the power plants by and large are on our side in this case,” she said. “They want that kind of flexibility because this is business as usual for them.”
See said “it’s a false argument” to contend that giving EPA more options is better for states. “The Clean Power Plan set an aggressive system that said that there were options for the state, but really, there weren’t, because states couldn’t actually have other options other than generation shifting and reduced output.”
Conservatives Appear Wary of Broad Ruling
Justice Samuel Alito | Supreme Court
Alito made his suspicion of EPA’s power clear, telling Prelogar, “If you take the arguments about climate change seriously … so long as the costs are not absolutely crushing for the society, I don’t know why EPA can’t go even a lot further than it did in the CPP.”
But none of the conservative judges said they thought the D.C. Circuit had erred in rejecting the ACE rule. And there was little indication that they saw the case as a forum for a sweeping ruling on the major-questions doctrine.
Justice Neil Gorsuch said Prelogar “makes a strong argument that states are not harmed here because, under the current state of affairs, there is no rule in place.”
Justice Amy Coney Barrett distinguished the case from the court’s September ruling that the Centers for Disease Control and Prevention lacked power to order a moratorium on evictions during the COVID-19 pandemic. That case, she said, concerned whether “the CDC can regulate the landlord-tenant relationship.”
In the current case, she said, “if we’re thinking about EPA regulating greenhouse gases, well, there’s a match between the regulation and the agency’s wheelhouse, right?”
Justice Brett Kavanaugh noted the electric utilities’ argument that cap-and-trade systems are more flexible and better than command-and-control rules. “I think those are all — you know, those are solid arguments that we … need to consider.”
Stakeholders expressed concerns at last week’s Markets and Reliability Committee meeting over a PJM plan to address the extension of a temporary change to maximum emergency status for gas combustion turbines and steam generators.
Chris Pilong, of PJM’s operations planning department, reviewed proposed revisions to Manual 13: Emergency Operations in a problem statement and issue charge. To address concerns with fuel security and new emission standards in states that emerged in recent months, Pilong said, PJM made a temporary change to section 6.4 of Manual 13 in a “note” to modify the remaining hours under which a resource may be offered as maximum emergency generation.
The changes, which were endorsed in October, state that PJM may request a generation owner to move steam units, which are mostly coal-fired, into the maximum emergency category if their remaining run time falls below 240 hours, or 10 days. The units could be restricted from operating during that time unless required to meet reliability needs for the grid. (See Global Fuel Supply Prompts PJM Manual Changes.)
Units could remain in maximum emergency status until their fuel inventory rose above 21 days, or 504 hours, Pilong said, and the designation would only be implemented to address concerns with local or regional reliability resulting from fuel supply shortages. The previous run-hour threshold for maximum emergency was 32 hours.
Pilong said the manual change is set to expire April 1, but it needs to be extended to give PJM and stakeholders more time to work on a permanent solution. Additional work is being requested to take place under a new problem statement and issue charge titled “Max Emergency Changes for Resource Limitations.”
The issue charge calls for reviewing and modifying existing rules in response to concerns with the fuel and non-fuel supply chain, as well as the increasing environmental restrictions on generators that are creating challenges with managing run hours. Pilong said PJM wants to spend four months working on the issue in the Operating Committee and have a solution in advance of the summer 2022 peak period.
“We want to allow PJM and stakeholders to take a step back and take a more detailed look at Manual 13 and make sure we have the right changes and have those discussions,” Pilong said.
Susan Bruce, counsel to the PJM Industrial Customer Coalition (ICC), said she was concerned over what units the rules will apply to. It will be important for PJM and stakeholders to “take a big picture view” in discussions for any changes, she said.
“There are some really big issues that are going to be within this work effort that have implications for the nature of capacity,” Bruce said. “We don’t want to make decisions here that have ramifications in other places or that the work goes by the wayside because of efforts in other task forces.”
Independent Market Monitor Joe Bowring said stakeholders should keep in mind scenarios in which a lack of fuel or other consumables resulted from contractual issues that were theoretically controllable by the generation owner and how those situations should be treated differently compared to supply chain issues.
Bowring also requested clarification of what PJM intends to include in the definition of “running for reliability” in the issue charge.
Pilong indicated that PJM will respond to the requests.
John Rohrbach, representing Southern Maryland Electric Cooperative, said resources following PJM’s dispatch while also trying to preserve themselves for a reliability event and reserve run hours could experience a “conundrum” through the language in the issue charge.
“It can create a challenge for a resource to guess when there’s going to be an event and to take itself out to procure fuel in advance of a switching event,” Rohrbach said.
Pilong said Rohrbach’s point is included in the expected deliverables of the issue charge for education on existing tariff language regarding unit eligibility and any practices and analysis for scheduling resources in max emergency.
Stakeholders will vote on the issue charges at the March 23 MRC meeting.
CCSTF Sunset
Melissa Pilong of PJM presented a first read of the Capacity Capability Senior Task Force’s (CCSTF) sunset. Pilong also presented the final report of the task force’s work completed.
The task force was originally created in March 2020 to consider using effective load-carrying capability (ELCC) to set the capacity value of limited-duration resources such as battery storage.
Stakeholders ultimately endorsed a joint proposal in September 2020 to use the ELCC method to calculate the capacity value of limited-duration, intermittent and combination (limited-duration plus intermittent) resources. FERC approved PJM’s proposal in August. (See FERC Accepts PJM ELCC Tariff Revisions.)
Pilong said work originally endorsed by stakeholders for a second phase of discussions has been moved to the Resource Adequacy Senior Task Force. The additional work includes a discussion of other rules or rule changes that may be necessary for limited-duration resources to participate in energy and ancillary service markets.
“It just made sense with all of the work that paralleled a lot of the efforts,” Pilong said.
The committee will be asked to endorse the task force sunset at its March meeting.
Example of a pseudo-modeled combined-cycle unit. | PJM
Hauske said market sellers can model a combined cycle generation unit as multiple “pseudo units” that are made up of a single combustion turbine and a portion of a steam turbine. But he said the potential exists for one or more of the pseudo-modeled units to operate for a period beyond the minimum run time parameter limit compared to an identical non-pseudo-modeled combined cycle unit if the market units of a pseudo-modeled combined cycle unit are dispatched at different times because the steam turbine takes extra time to reach operative levels.
Hauske said the proposed solution calls for adding language to Manual 11 to require market sellers to update the minimum run time of any subsequent pseudo-modeled unit to remove the associated steam turbine start-up time included in the parameter limit when it’s dispatched.
PJM removed language calling for “hourly” updates of the minimum run time parameter in order to avoid creating a “compliance trap” for market sellers who have several pseudo-modeled combined cycle units.
Hauske said PJM wants to have a final endorsement by the March 23 MRC meeting because the RTO’s unit-specific parameter adjustment process started Monday. PJM must provide a determination on the requests by April 15.
PJM will provide guidance developed in the initiative to any pseudo-modeled combined cycle unit requesting an adjustment the review period, Hauske said, or to existing pseudo-modeled combined cycle units with an approved unit-specific minimum run time parameter.
Manual 18 Revisions
Jeff Bastian, senior consultant in PJM’s market operations department, provided a first read of revisions to Manual 18: PJM Capacity Market to conform with several recent FERC orders. The changes from the orders included:
revisions to the application of the minimum offer price rule, which became effective by operation of law in September when the commission deadlocked (ER21-2582);
an October compliance filing to amend several sections of Attachment DD of the tariff establishing a replacement market seller offer cap (EL19-47);
restored tariff provisions restoring the prior backward-looking energy and ancillary services (E&AS) offset for the 2023/24 Base Residual Auction and beyond (EL19-58); and
the removal of the 10% cost adder for the reference resource used to establish the variable resource requirement curve (ER19-105).
Bastian said language in section 3.3.2 was updated to reflect that the net E&AS of the reference resource combustion turbine will be calculated using the forward-looking methodology with application of the 10% adder for only the 2022/23 delivery year. The net E&AS will be determined using the historical approach and without application of the 10% adder for all other delivery years.
The revisions also delete language in section 5.4.5.2 describing the consequences of accepting a state subsidy after electing the competitive exemption or certifying that a resource is not state-subsidized.
“These are all conforming changes and the changes are all to be made effective with the 2023/24 BRA, which is scheduled to be conducted very shortly,” Bastian said.
A final vote on the changes is scheduled for the March 23 MRC meeting.
Manual First Reads
PJM staff presented several manual changes resulting from the periodic review for first reads. They included:
Manual 13: Emergency Operations with a review of the language that added columns with winter values for estimated peak load and estimated load reduction in the voltage reduction summary table.
Manual 37: Reliability Coordination with a review of the language that corrected Silver Run Electric to properly show as a transmission owner in Attachment A of the manual.
MRC Consent Agenda
Members unanimously endorsed two manual revisions as part of the MRC consent agenda, the only voting items at the meeting. They included:
conforming revisions to Manual 27: Open Access Transmission Tariff Accounting related to a recent FERC order in response to industrial customers’ protest of PJM’s proposed revisions to its administrative rates. The revisions included reorganized wording to distinguish between administrative rates and pass-through rates, and a new section to only be reconciliation for transmission owner scheduling system control and dispatch service.
revisions to Manual 40: Training and Certification Requirements resulting from the periodic review. The change included the addition of Maureen Curley as manager of PJM’s state and member training department. Curley replaced Michael Sitarchyk who retired as manager earlier this year.
MC Consent Agenda
Stakeholders unanimously endorsed one set of revisions clarifying fuel-cost policy standards in Manual 15 and Schedule 2 penalty language of the Operating Agreement as part of the consent agenda at last week’s Members Committee meeting.
The changes require that generation unit market sellers verify that all intraday offer triggers are specified in the unit’s fuel-cost policy. The Manual 15 updates include changes to the intraday update triggers. Fuel-cost policies will require providing a fuel price that can be calculated by the Monitor or PJM “after the fact with the same data available to the generation owner at the time the decision was made and documentation for that data from a public or a private source.”
The proposal was endorsed at the January MRC meeting and will take effect upon approval by the PJM Board of Managers and FERC. (See “Fuel-cost Policy Standard Clarifications Endorsed,” PJM MRC/MC Briefs: Jan. 26, 2022.)
If history is any guide, any attempt to form a West-wide RTO would seem doomed to failure. But now the creation of such a market appears almost inevitable.
In the two and a half decades since the first try at creating an organized market in the Western Interconnection, multiple initiatives have faltered as utilities and their state regulators resisted the idea of turning over control of the grid to a central operator.
Now CAISO, SPP and the Western Power Pool (formerly the Northwest Power Pool) simultaneously maneuver to organize the Western electricity sector, and conditions finally seem ripe for change.
That was the view shared by the four industry insiders speaking during the first panel of a virtual conference hosted by the Western chapter of the Energy Bar Association on Thursday.
“The West has had plenty of fits and starts in this area over the last two decades or so, but there are several things that are happening today that I think are likely to make this time different,” panel moderator Brian Cole, general manager of resource management at Arizona Public Service, said in opening the panel. “These include the need for clean energy integration, reliability and affordability, not to mention some state mandates that require [adoption of organized] markets in those particular states by the end of the decade.”
Providing a rundown of the West’s failed efforts was former Bonneville Power Administration (BPA) executive Steve Kerns, now senior technical adviser for the Public Generating Pool, an association of 11 publicly owned utilities in the Pacific Northwest. He tallied off IndeGo (1995-1998), RTO West (2000-2004), Grid West (2004-2006) and NWPP’s MC initiative (2012-2016), which sputtered in the face of growing interest in CAISO’s lower-cost Western Energy Imbalance Market (WEIM).
CAISO’s three-year attempt to regionalize its own market stalled in 2018 after stakeholders and California legislators failed to resolve concerns over the ISO’s governance, which is subject to oversight by California officials. (See CAISO Expansion Bill Dies in Committee.)
Kerns pointed out that organized electricity market design is fundamentally rooted in NERC’s Reliability Functional Model, which envisions market structures that employ shared transmission planning, a single tariff and transmission service provider (TSP), a single balancing authority and a central market operator.
But implementing those has proved challenging in the West, Kerns said. For instance, shared transmission planning introduces the problem of how to allocate costs for new projects that may provide uneven benefits. Similarly, a single tariff will likely result in cost shifts for existing transmission, forcing some entities to fund transmission from which they derive no benefit.
Additionally, one of the region’s largest transmission owners, BPA, faces statutory restrictions on transmission cost sharing, as well as on its ability to cede control of its lines to another TSP.
Furthermore, the NERC model’s call for a single BA has long cut across the desire for local control in a region with dozens of BAs of varying size. Finally, as Kerns noted, the estimated cost of standing up a central operator has caused “sticker shock” among stakeholders, as in the case of the NWPP MC effort.
‘Dramatic Shift’
But the changing energy landscape in the West could erode much of the resistance to an RTO, Kerns said.
Like Cole, Kerns pointed to the favorable impact of state clean energy policies, which simultaneously drive deployment of variable renewable resources and retirement of fossil fuel plants but also increase stress on the grid and raise concerns about regional resource adequacy.
“There’s also been an increase in independent power producers that are developing renewable generation at locations distant from load centers that require substantial investments in transmission,” along with a growth in large power users that seek to be served by renewables, Kerns said.
In the Northwest, the power industry confronts a trend of decreased flexibility from the region’s massive hydroelectric network, which is subject to greater operational restrictions to protect endangered species while at the same undergoing changes in streamflow patterns because of climate change.
Lastly there’s the “missing money” problem, Kerns said. “This is the perception that there are inadequate incentives for market participants to develop capacity resources that will provide sufficient capacity and energy to meet demand. And the belief is that if you create an organized market with the correct price signals, that could help resolve that issue.”
Phil Pettingill, director of regional integration at CAISO, agreed with his fellow panelists that a “dramatic shift” to renewables in the Western Interconnection has sparked renewed interest in a Western RTO.
“What we’ve already seen is wholesale electric markets can really, really help in terms of the integration of these renewables,” Pettingill said. “In this footprint, we have now about [38] balancing areas, and so they’re all operating basically independently, and one of the benefits we have with wholesale market is [to] actually start to integrate that operation and look at being able to facilitate a much more efficient dispatch in the system.”
And while a real-time market such as the WEIM provides a foothold, Pettingill noted that real-time transactions represent less than 5% of the energy delivered in CAISO, indicating the “value” of adding day-ahead trading to the market, as the ISO is planning to do with its extended day-ahead market (EDAM) initiative.
“It is in the day-ahead where we actually decide which generation resources will be put online, in order to match or work with the renewable fleet that’s now expanding,” he said. “It also gives us an opportunity then to optimize the transmission that’s being used across that larger footprint, because multiple balancing areas across multiple states are now working together.”
Because they often operate at zero marginal cost, renewables are typically dispatched ahead of other, greenhouse gas-emitting resources.
“So it’s not only the economic benefit, but also the environmental benefits that come from the success of the Western Energy Imbalance Market,” Pettingill said.
The West will ultimately “land” with an RTO, Pettingill thinks, “but that’s down the road. If there’s one thing we’ve seen in the Western Interconnection, things go incrementally.”
That incrementalism will entail “layering” new services onto the WEIM, such as EDAM, eventually leading up to inclusion of transmission planning in a full RTO, he said.
Competitive Field
A layered approach is what SPP envisions for the Markets+ program it plans to offer on top of other services it’s already providing in the West.
SPP is currently reliability coordinator for 11 entities in the Western Interconnection, and its Western Energy Imbalance Service (WEIS) has seven participants, many of whom plan to join the full RTO. In addition, the Western Power Pool last year selected SPP to operate the Western Resource Adequacy Program (WRAP), whose reach will extend across much of the West when it launches its nonbinding RA program later this year. (See NWPP Rebrands as Western Power Pool.)
Like CAISO’s EDAM, SPP’s Markets+ will add a voluntary day-ahead option to the RTO’s WEIS, Kara Fornstrom, SPP director of state regulatory policy, explained. Markets+ will also be made available to participants in the WRAP, putting it in direct competition with the WEIM.
“If you’re in the EIM and want to join Markets+, you’ll have to leave the EIM to do so,” Fornstrom said.
In developing Markets+, Fornstrom said, SPP identified three “buckets” that it thinks rekindled the West’s interest in “market evolution”: economics, reliability and the need to integrate clean energy resources. She touted SPP’s experience in the third category.
“SPP was the first RTO to have wind as our primary fuel resource. … Last year it was 36% of our total,” she said. “We’ve got all of that energy into our system — a lot of it — because of our transmission availability, data transmission planning and our investment in transmission, along with our established cost allocation principles.”
All three panelists agreed that governance remains a key impediment to forming a full RTO in the West, but Fornstrom, a Wyoming Public Service Commissioner before joining SPP, sees a positive development on that front.
“I think it’s hard to overstate the positive impacts that the WRAP governance structure has made for the West,” Fornstrom said, referring to the progress WPP and its stakeholders have made in developing the program’s oversight bodies. “It’s helped us come to the first time [of] being able to do something on a wide regional basis. And that really should not be overlooked.”
Comparison of projects in MISO’s long-range transmission plan (left) and MISO and SPP’s JTIQ study. The overlapping projects are in the Dakotas and Minnesota. | MISO and SPP
