MISO will ask FERC to waive a specific generation interconnection queue requirement to assist developers whose projects face construction preparation delays in the face of the COVID-19 pandemic.
The RTO will request a “limited FERC waiver” of its June 25 deadline for developers to demonstrate site control for projects entering MISO South’s 2020 interconnection cycle, Manager of Probabilistic Resource Studies Ryan Westphal told listeners on a Planning Advisory Committee call Wednesday. MISO has settled on a 60-day extension of the deadline.
Westphal said the chief concern of most interconnection customers is how they will meet deadlines to show exclusive land use for generation projects during the pandemic. MISO’s next site control deadline doesn’t occur until September, when the 2020 MISO West batch of projects enter the queue.
“There’s still uncertainty of when some states and localities will lift restrictions,” he said. “We’re looking at the near future and can go back to FERC to extend waivers as necessary.”
Westphal said the request specifically applies to the site control deadline and would not affect other queue deadlines. However, he said, additional waivers “are on the table” if the pandemic wears on and groups of interconnection customers encounter similar obstacles. (See MISO Considers COVID-19 Queue Waivers.) “At least” two interconnection customers have reached out to MISO to discuss special circumstances affecting their projects, he said.
MISO will not hold a call to discuss the finalized filing with stakeholders and will file in the “next two weeks,” Westphal said.
Virginia Gov. Ralph Northam (D) on Sunday signed into law landmark legislation committing the state to closing most of its coal-fired generation by 2024 and making it the first Southern state to adopt a 100% clean energy standard.
Gov. Ralph Northam | NGA
“These new clean energy laws propel Virginia to leadership among the states in fighting climate change,” Northam said in a statement. “They advance environmental justice and help create clean energy jobs. In Virginia, we are proving that a clean environment and a strong economy go hand-in-hand.”
The Virginia Clean Economy Act (House Bill 1526 and Senate Bill 851) creates a CO2 cap-and-trade program to reduce emissions from power plants and amends the Clean Energy and Community Flood Preparedness Act, which committed the state to joining the Regional Greenhouse Gas Initiative (RGGI).
The legislation is a stunning turnaround for Virginia’s energy policy, spurred by Democrats’ takeover of the House of Delegates and the Senate in November. Last year’s budget approved by Republicans, Northam noted, prohibited Virginia from joining RGGI.
The new law:
Replaces the existing voluntary renewable portfolio standard program with a mandatory RPS that applies to electric utilities and licensed competitive suppliers. It requires Dominion Energy Virginia to be 100% carbon-free by 2045 and Appalachian Power by 2050.
Sets an energy efficiency resource standard and requires a third-party review of whether energy companies meet savings goals.
Establishes 5,200 MW of offshore wind as “in the public interest,” up from 16 MW. It requires Dominion to prioritize hiring local workers from historically disadvantaged communities for the offshore project and to work with the state on apprenticeship and job training programs. Dominion must include an environmental and fisheries mitigation plan in its construction.
Establishes that 16,100 MW of solar and onshore wind is “in the public interest” and expands net metering for rooftop solar. It sets an energy storage target of 2,400 MW by Dec. 31, 2035.
Removes a provision declaring that planning and development activities for new nuclear generation facilities are in the public interest.
“By joining RGGI, Virginia will take part in a proven, market-based program for reducing carbon pollution in a manner that protects consumers,” Northam said. The Department of Environmental Quality will create and run an auction program to sell allowances into a market-based trading program.
Two coal-fired units totaling 1,015 MW at Dominion Virginia Power’s Chesterfield Power Station are scheduled to retire in May 2023. | Dominion Energy
Revenues from the sale of allowances will be distributed by the Department of Mines, Minerals and Energy to low-income, disability, veteran and age-qualifying energy efficiency programs; additional energy efficiency measures for public facilities; coastal resilience efforts; and administrative costs.
The State Corporation Commission will be prevented from issuing a certificate for public convenience and necessity for any investor-owned utility to own, operate or construct a generator that emits carbon until the General Assembly receives the state Air Pollution Control Board’s report on how to achieve 100% carbon-free electricity generation by 2050 and whether the legislature should ban new generation units that emit carbon. The report is due Jan. 1, 2021.
Utility applications to construct a new generating facility will include the social cost of carbon, as determined by the commission, as a cost adder.
Tri-State Generation and Transmission Association said Monday it has entered into a withdrawal agreement with Delta-Montrose Electric Association (DMEA), sticking to the terms of a 2019 settlement.
Westminster, Colo.-based Tri-State said DMEA will pay $88.5 million, including $26 million to purchase facilities, and forfeit another $48 million in patronage capital to leave the cooperative, effective June 30. The agreement is subject to certain conditions and approvals, including FERC’s.
DMEA is a rural electric distribution cooperative that serves about 28,000 member-owners in western Colorado. The co-op sought to sever ties with Tri-State after determining it could obtain cheaper and environmentally cleaner energy supplies from other sources.
Tri-State and DMEA last year agreed to part ways in a settlement agreement that allows for DMEA’s purchase of certain assets and facilities, the termination of certain existing contracts between the two entities, and assignment by Tri-State of its wholesale electric service contract to a third-party provider.
Tri-State and DMEA will also enter into new contracts for the continued operation of transmission and telecommunications systems.
“The withdrawal agreement aligns with our settlement,” Tri-State CEO Duane Highley said.
DMEA’s forfeiture of the current balance of its patronage capital is not included in the payment. All Tri-State members have a patronage capital account, which represents each member’s ownership in the co-op.
Tri-State, a member of SPP’s Western Interconnection Energy Imbalance Service set to go live in February, has 46 members, including DMEA.
Kit Carson Electric Cooperative left Tri-State in 2016. Two other Tri-State cooperatives, United Power and La Plata Electric Association, are seeking termination-fee information through proceedings at the Colorado Public Utilities Commission.
The Tri-State board of directors on Friday approved a formula for standardizing the fee charged to members if they break their power-supply contract and leave the organization.
The California Energy Commission boosted the state’s efforts to electrify buildings and improve the efficiency of electric appliances last week when it approved electrification and green energy ordinances in seven cities and required that swimming pool pump motors — a significant energy user in homes and hotels — become more efficient.
California has nearly 1.2 million swimming pools, more than one-fifth of all pools in the U.S., according to real estate data tracking firm Metrostudy. Replacing older burnt-out motors with high-efficiency ones eventually will save 451 GWh/year, the commission estimated.
“To put that amount of savings into perspective, that’s enough electricity to power the entire fleet of trains operated by BART, the Bay Area Rapid Transit train system — serving San Francisco, Oakland and many of the cities on the way to San Jose — for a year,” Noah Horowitz, the director of the Natural Resources Defense Council’s Center for Energy Efficiency Standards, wrote in a blog post praising the move.
The new California rules bolster national energy efficiency standards for pool pumps that take effect in 2021, the NRDC said.
Pacifica is one of seven cities that adopted building electrification or green-energy plans approved by the California Energy Commission. | U.S. Army Corps of Engineers
In its April 8 meeting, the CEC also approved municipal rules for building electrification and energy efficiency in new construction that exceed current state standards.
The communities include Cupertino, the Silicon Valley suburb where Apple has its headquarters. The city of 60,000 residents adopted an ordinance requiring that new buildings be all-electric. The nearby cities of Saratoga and Pacifica will require new single-family and many multifamily buildings to use electricity for heating and cooling systems and water heaters.
San Francisco, along with San Rafael and Mill Valley in Marin County, passed rules requiring new buildings and remodels to achieve high scores under green building certification programs, including Leadership in Energy and Environmental Design. Those requirements are expected to result in the installation of electric heating and cooling systems in place of those that use natural gas.
A Los Angeles ordinance approved by the CEC requires that all buildings install cool roofs for the “reduction of the heat-island effect.”
Achieving Zero Carbon
The cities join a growing number of local governments instituting aggressive changes to reduce fossil-fuel emissions for residential and commercial structures. Last year, Berkeley became the first city to ban natural gas in new construction as other cities weighed similar measures. (See West Coast Pushes for Building Electrification.)
The Public Utilities Commission recently devoted $200 million to jump-start electrification efforts, for “the purpose of decarbonizing California’s residential buildings in order to achieve California’s zero-emissions goals,” Commissioner Liane Randolph wrote in her proposed decision, which the commission adopted March 26.
The state’s twin goals of greatly reducing greenhouse gas emissions and relying wholly on renewable and nonpolluting energy by midcentury are driving the electrification effort. Advocates see vehicles and buildings as areas where fossil fuels can be eliminated.
The Hearst Castle’s Neptune Pool | California State Parks
The cities that have adopted green building and electrification efforts are primarily located in wealthier and politically liberal coastal California. Residents of the state’s more conservative interior have, in some cases, resisted such efforts. (See Bakersfield Balks at Electrification with CPUC.)
But the movement is expected to grow in coming years both through mandatory efforts and voluntary replacement of natural gas furnaces and water heaters with energy-efficient systems.
The Sacramento Municipal Utility District, for example, offers rebates of $1,500 to $4,000 to residents who upgrade to electric heat pumps for home heating and cooling and $2,500 rebates for those who install heat-pump water heaters. SMUD has also been encouraging the construction of all-electric homes.
“Customers with all-electric homes in SMUD’s service area are well positioned for a renewable energy economy and can typically save $400 compared to homes that rely on gas for space heating and hot water,” the utility said in a news release. “These homes will help community-owned SMUD meet its aggressive commitment to reach carbon neutrality by 2040 and surpass the state’s greenhouse gas reduction goals of 80% by 2050.”
Emissions of heat-trapping methane hit a new high in 2019, according to preliminary data from the National Oceanic and Atmospheric Administration.
The agency reported globally averaged atmospheric methane levels hit 1,874.7 parts per billion in December 2019, an increase of almost 0.5% from a year earlier and the second-largest annual increase in the last 20 years. NOAA cautioned that its analysis was preliminary; final numbers are expected in November.
After almost leveling off between 2000 and 2005, methane emissions have increased sharply since 2006, a period in which U.S. natural gas production has increased by more than 70%. | NOAA
Methane is emitted by cows, sheep, microbes in wetlands, and oil and gas wells. While it remains in the atmosphere for only about a decade, much less than CO2, it absorbs much more energy than CO2. Thus, EPA says methane’s global warming potential (GWP) is about 30 times that of carbon dioxide.
After almost leveling off between 2000 and 2005, methane emissions have increased sharply since 2006, a period in which U.S. natural gas production has increased by more than 70%, according to the Energy Information Administration.
Methane emissions from the oil and gas sector totaled almost 80 million tons in 2017, 6% of global energy sector greenhouse gas emissions, according to the International Energy Agency.
Because methane is valuable, IEA says almost half of the emissions from drilling could be captured at no net cost.
“Emissions remain high despite initial industry-led initiatives and government policies announced recently,” IEA said. “Implementing abatement options quickly and at scale remains a real challenge.”
ExxonMobil Field Trials
ExxonMobil announced last week it is conducting field trials of eight methane detection technologies, including satellite and aerial surveillance monitoring, at nearly 1,000 sites in Texas and New Mexico.
“The field tests are evaluating effectiveness and scalability of a range of next-generation detection technologies that, in addition to satellites, use drones, planes, helicopters, [and] ground-based mobile and fixed-position sensors. All technologies and deployment methods will be used to detect leaks and identify potential solutions that can be shared with other oil and gas operators,” the company said.
“We are already seeing the benefits of some of these technologies,” said Staale Gjervik, president of ExxonMobil subsidiary XTO Energy. “Through the trials, we have discovered methane sources that would otherwise not have been detected as efficiently or quickly under the current methods prescribed by regulations. The company is committed to immediately investigating and fixing methane emissions that are detected during the trial.”
ExxonMobil is running field tests of SeekOps’ methane detection technology, which uses drones. | SeekOps
The company said it reduced emissions by almost 20% in its U.S. unconventional operations between 2016 and 2019. It has made a corporate-wide commitment to reduce methane emissions by 15% and reduce flaring by 25% by the end of 2020.
In March, ExxonMobil proposed a regulatory model for reducing emissions.
The Trump administration in 2018 reversed proposed regulations to reduce leaking, venting and flaring of methane at drill sites on federal and tribal land and a requirement that companies monitor and repair methane leaks.
Dry natural gas production grew by 10% to a record 92.2 Bcfd in 2019 but is expected to drop slightly in 2020 and 2021 because of low prices, EIA said last week in in its Short-Term Energy Outlook. The agency also said its forecasts are “subject to heightened levels of uncertainty” because the impacts of the COVID-19 pandemic on energy markets are “still evolving.” (See related story, EIA: Renewable Capacity to Grow in 2020.)
The economic shutdown caused by the pandemic could reduce global carbon dioxide emissions by more than 5% this year, according to the Global Carbon Project. It would be biggest reduction since the end of World War II.
The Marcellus Shale formation has turned Pennsylvania into the nation’s No. 2 natural gas producer and made it a favorite spot for new gas-fired electric generation. Natural gas’s share of the state’s electric production more than doubled to 36% from 2010 to 2018.
But there is something different about the state’s newest generating plant. If natural gas prices rise from their current low prices, Competitive Power Ventures’ 1,050-MW Fairview Energy Center near Johnstown can add up to 25% ethane into its fuel mix — the first generation facility of its size in the world with that kind of flexibility, according to CPV.
CPV’s Fairview Energy Center | Competitive Power Ventures
Located on an 86-acre former brownfield site in Jackson Township, Cambria County, the General Electric-designed combined cycle plant successfully completed ethane testing in March and went into full combined operation this month.
Bill Lawson, senior engineer for new products at GE Gas Power, said customers have been seeking the ability to burn an array of gases to respond to fluctuating commodity prices. Lawson said GE began looking several years ago at shale gas and its byproducts, including ethane, that could serve in power generation.
“GE saw this trend developing early and focused technology development to broaden our fuel flexibility,” Lawson said.
Price Trends
Ethane, commonly referred to as a natural gas liquid, is a hydrocarbon that can be found underground in shale and coal beds. In addition to being burned as a fuel, ethane also is used to produce ethylene, a chemical used in the manufacturing of plastics, automotive antifreeze and detergent.
According to the Energy Information Administration, ethane prices tracked crude oil spot prices until 2008 but began to diverge as U.S. production growth from shale gas and tight oil formations overwhelmed ethane consumption by the domestic petrochemical industry. By 2012, ethane prices closely tracked natural gas prices, staying within $1/MMBtu of the Henry Hub natural gas spot price on a heating-value-equivalent basis.
Monthly average of close-of-day spot prices for natural gas and ethane 2002-2018. Natural gas is priced at Henry Hub; ethane is priced at Mt. Belvieu non-LST (Lone Star Terminal). | EIA
Since late 2017, EIA says, ethane demand has been growing because of increased petrochemical use and ethane export capacity. “As a result, ethane prices began to move away from their link to natural gas prices, and they are now bracketed by propane at the top and natural gas at the bottom of the range,” EIA said.
Ethane spot prices fell 17% from January to March this year — while natural gas prices dropped 11% and international crude oil fell about 46% — because of the economic slowdown from the COVID-19 pandemic.
Nearby Pipelines, Transmission
Natural gas for Fairview comes from the Enbridge Texas Eastern Transmission gas lines, about 1 mile north of the plant site. The ethane comes from Mariner East pipelines located on site. The plant also is adjacent to a 500-kV circuit that delivers its output to PJM, enough for 1 million homes and businesses.
CPV, which has ownership interests in 4.2 GW of generation in the U.S, partnered with Osaka Gas on the plant.
Jeff Ahrens, vice president of engineering and construction for CPV and the director of the $1 billion project, said the company wanted to incorporate ethane from an early stage in the plant’s development. While CPV had experience with the equipment and engineering needed for natural gas generators, adding ethane presented new challenges.
“It’s the first of its kind on this scale, so it required a lot of patience to make sure we did it right, make sure everything was designed correctly and look at all the different scenarios that the system needed to have to be reliable and safe for us,” Ahrens said. “Every step was somewhat new.”
Fairview was Ahrens’ second project for CPV, following the St. Charles Energy Center, a 745-MW combined cycle plant in Waldorf, Md., that went into operation in 2017.
Ahrens said one of the biggest challenges was that ethane comes to the plant in liquid form and requires vaporization to mix with the natural gas.
Natural gas is more buoyant than ethane, Ahrens said, so designs had to be created to find the right way to mix the two. The result was a GE vaporizer as large as a truck to mix the two fuels.
Fairview took nearly three years of development before construction began, requiring a team of hundreds of GE and CPV engineers, manufacturers, logistics exports and transportation workers.
“It required a lot of research, understanding [and] getting the right team members together who either had some experience or knew people who had experience, like petrochemical guys in the oil and gas industries,” Ahrens said.
While the COVID-19 pandemic has dampened industrial output and electricity load in much of the nation, ERCOT continues to set the pace for increases in demand.
The Texas grid operator, which has enjoyed fairly consistent 2% load growth in recent years, registered a new demand record for April when the system peaked at 55,180 MW on Wednesday during the hour ending at 5 p.m. CT. The preliminary operational data broke the previous mark of 53,846 MW, set in April 2017.
An ERCOT spokesperson attributed the record to the state’s higher-than-normal temperatures that pushed up demand during the day.
| ERCOT
According to the National Weather Service, temperatures in the Dallas/Fort Worth Metroplex hit 97 degrees Fahrenheit on April 8, setting a daily record high. The low temperature of 71 F set a record for the highest minimum temperature for the date.
The monthly record was the first of 2020 after ERCOT set nine during the past two years. March’s peak demand of 52,819 MW was down 13.1% from last year’s March high of 60,756 MW.
| ERCOT
The peak came as the nation’s electricity demand plunged to a 16-year low during the first week of the month. The Edison Electric Institute and energy traders cited closed offices, reduced industrial activity and mild weather for slowing demand.
The U.S. Energy Information Administration expects total U.S. power consumption to decline by 3% in 2020. (See related story, EIA: Renewable Capacity to Grow in 2020.)
ERCOT began monitoring the pandemic’s effect on load patterns in early March. Last week, the grid operator began providing weekly updates on the patterns on its Trending Topics webpage (under Presentations & Other).
It said there has been little effect on its daily peaks but that morning loads are 6 to 10% lower than what the forecast model would typically predict. (See “Texas Grid’s Weekly Energy Usage Down 2% in March,” ERCOT Technical Advisory Committee Briefs: April 1, 2020.)
Calvin Opheim, ERCOT | ERCOT
“The overall load reduction for the ERCOT region has leveled off over the past two weeks,” said Calvin Opheim, ERCOT manager of load forecasting and analysis. He said energy usage was down about 2% for the weeks of March 22 and 29.
ERCOT staff are using a backcast model in their analysis, comparing model results using actual weather versus actual hourly load. The difference between what actually occurs and what the model shows is referred to as a “model error.” The model was last updated in January and does not reflect the pandemic’s effect, making it a “pure model” for analyzing the difference between the model and actual outcomes. The pandemic is a component of the model error.
Before the pandemic, ERCOT had projected a record summer peak demand of more than 76,600 MW, a 3,500-MW increase over last year. It will release a final forecast in May. (See ERCOT Sees Summer Repeat: Record Peak, Tight Reserves.)
Before joining energy aggregator PowerOptions as president and CEO in January 2020, Heather March Takle took steps to upgrade the company’s IT functionality, especially communications.
Her decision meant the team of 10 employees was prepared to work remotely when the company started doing so March 8 in reaction to the worsening COVID-19 pandemic in Massachusetts and the rest of the country.
“COVID-19 has been quite a surprise and helped accelerate my learning curve,” Takle told RTO Insider in an interview.
The largest energy-buying consortium in New England, PowerOptions purchases $200 million in energy each year to serve nearly 500 nonprofit and public entities in Massachusetts, Connecticut and Rhode Island.
The firm provides energy cost savings and predictability to hospitals, schools, museums and other clients. Takle also advocates for her clients as an end-user sector member of the New England Power Pool and participant in ISO-NE planning processes.
A Nonprofit Helping Nonprofits
PowerOptions grew from a quasi-public agency in Massachusetts and became a fully private nonprofit a decade ago under the leadership of Cindy Arcate, whom Takle replaced as head of the company. It is funded by membership dues and payments from its energy suppliers, which are chosen through competitive solicitations. Direct Energy supplies the natural gas; Constellation Energy supplies the electricity; SunPower is the developer for its large-scale solar program; and Solect Energy is the developer for the small systems solar program. For the fiscal year that ended in June 2018, it reported revenues of almost $3.4 million and expenses of $3.5 million.
PowerOptions CEO and President Heather March Takle | PowerOptions
Takle, who previously held executive positions with Patriot Energy Group and Ameresco, was recruited from her own startup, 2ndPath Energy, which provided energy companies with strategic and development advice.
“Before coming in, I knew how strong the team was. … The surprising thing was not realizing how much of an impact the members’ missions would make on me,” Takle said. “I knew it conceptually, at a high level. The premise of being a nonprofit serving other nonprofits in that mission-driven basis is part of what attracted me to the role.”
In the first couple of months, her No. 1 goal was to meet as many members as possible.
“It’s a member-driven organization, so I need to understand and hear from them, so I’ve gotten to meet maybe a third of our members, and it’s really been fantastic to hear about their missions and to get pulled in,” she said. “The team did warn me that I’d start opening my checkbook because I want to start donating after having all these conversations.”
PowerOptions members include some of the organizations most affected by the coronavirus crisis, from shuttered schools to hospitals on the front lines. Some clients fall between the cracks in terms of defined missions.
“Senior living, for example. They’re not health care institutions — the assisted living and the independent living [facilities] — so what they’re dealing with is really difficult and tragic, and they’re not getting a lot of support from the state governments because they’re not designated as health care institutions,” Takle said.
Outreach Campaign
The new CEO has led her small firm on a campaign since the pandemic started, trying to figure out how they can help its members.
“Because as a nonprofit ourselves we care, so we decided two weeks ago to do an outreach campaign and just get on the phone and start calling, including myself, and that’s part of how I’ve been able to talk to a third of our members,” Takle said.
Some of the discussions concern energy needs that are particular to the current environment but also touch on topics outside of energy.
“We’re just trying to brainstorm how we can help. We haven’t announced it publicly yet, but we’ve been able to put together a philanthropic fund to support our members. We’re still in the detail planning stage of trying to figure out how that will get distributed out, but we’re going to try to support our members in what little way we can.
“Some of that will be financial, but I spent the weekend trying to find sources of supplies for masks and sanitizer. For some of our members, it’s not just the financial need, but for the ones on the health care side, it’s a personnel and supply need.
“We’re trying to be creative, because if it’s anything I learned in my first couple of months with this team, it’s that they will stop at nothing to support our members,” Takle said.
The company is planning to host a webinar focusing on changes in the energy market driven by the pandemic, as well as just general energy industry dynamics, such as oil and gas pricing.
“It’s been heartening to see, as usually happens in a crisis, the best of everyone, the creativity and the bonding that has come through, and the support for our members,” Takle said.
Renewable Dreaming
Long-term dreams for the organization include doing for renewable energy what it has done for electric and gas for its members.
“[That] might require some really unique partnerships with organizations outside of the nonprofit community. As an example, the Associated Industries of Massachusetts might be one such partner, though we haven’t discussed it with them. But we could be helping for-profits in that way, using the power of a consortium that’s larger than PowerOptions in order to drive down pricing, an opportunity to source renewable energy for much more than our own membership,” Takle said.
“Hopefully the message is well received that the ISO, NEPOOL and others remember that we’re there speaking on behalf of the end-users, and that we’ll be a consistent voice, one of the only voices there besides the attorneys general and the offices of consumer counsel.
“Of course, we’re speaking on behalf of governmental and nonprofit entities, but that kind of covers commercial and industrial as well, which there aren’t really specific voices for. We’ll be carrying on that legacy that Cindy was well known for.
“We will continue to advocate on behalf of our members for their needs, which includes lower costs, as well as, in the future, an ability to access renewable energy at efficient costs,” Takle said.
MISO is gearing up for a forward market mechanism and improvements to its scarcity and emergency pricing as market-side solutions under its yearslong resource availability and need (RAN) project.
Emergency pricing is often “inconsistent” with system conditions, MISO has concluded. During a Market Subcommittee teleconference Thursday, Market Design Adviser Michaela Flagg said the RTO’s shortage and emergency pricing has generally been inefficiently low.
In a now familiar refrain, Independent Market Monitor David Patton said MISO does not accurately price the “true value of energy when we’re tight.”
Suppressed prices during emergencies are prevalent in MISO South, Flagg said, because of a flaw in which the RTO’s pricing engine does not account for congestion from flows crossing the transmission constraint between the South and Midwest subregions. Accounting for that congestion is just one avenue MISO may pursue, she said.
Other solutions may include updating MISO’s value of lost load or changing the shape of the operating reserve demand curve.
“Prices should be high enough to reflect that MISO is running out of resources when it makes emergency declarations,” the RTO said.
Flagg said MISO will complete an evaluation of its emergency pricing by June and a scarcity pricing evaluation by December. Proposed solutions will follow the evaluations.
Director of Market Design Kevin Vannoy said MISO could stimulate imports and avoid making emergency purchases if it raises prices during scarcity events.
Customized Energy Solutions’ Ted Kuhn said MISO currently cannot compete for resources against neighboring RTOs, where prices can go as high as $8,000/MWh.
“At some point we’re going to have to match up on emergency pricing or ask FERC to join the bus,” Kuhn said at a Market Subcommittee meeting March 5.
Vannoy said MISO is also considering a forward market process that can guide commitment decisions before the day-ahead market is able.
“We definitely see that resource commitments and margins are becoming more challenging with lower operating margins and system volatility,” he said, noting that MISO’s must-run coal units have entered a retirement trend and lower LMPs incent fewer commitments.
“We definitely need more information earlier on capacity sufficiency and earlier than the day-ahead market,” Vannoy said, adding that long-lead units “are out of reach of the day-ahead market commitment.”
He said MISO is looking for members to provide input on what they look for to make unit commitment and availability decisions.
“For the most part, owners with long-lead and high-start-up-cost resources were making those decisions based on their own optimizations and their view of the market. Those decisions are becoming more and more challenging,” Vannoy said.
MISO is also experiencing an increase in emergency-only capacity as part of the overall portfolio, he said. Such resources require an emergency declaration before the RTO can access them.
But Madison Gas and Electric’s Megan Wisersky said MISO could encourage the construction of the more flexible generation it wants, saying insufficient transmission buildout in the footprint is restricting utilities’ ability to build new generation.
“It isn’t for grins that you see the growth in load-modifying resources. We as load-serving entities have to do something, and it takes years in the interconnection queue and some unknown dollar amount for network upgrades,” Wisersky said. “The easiest, fastest, cheapest thing we can do is put in demand-side resources.”
Scarcity and emergency pricing and a forward market mechanism comprise the market-side improvements in MISO’s multifaceted RAN effort. The changes under discussion include moving capacity resource accreditation and the capacity auction from an annual basis to a seasonal or subannual basis.
MISO Executive Vice President of Market and Grid Strategy Richard Doying said the RTO’s annual resource adequacy design is also open to further changes.
“Is it worth conducting [the auction] four times a year, or is there something else to provide that platform for liquidity and trading?” Doying asked rhetorically.
“We can all see the portfolios evolving. We’re not sure it’s an imperative for this change,” WPPI Energy economist Valy Goepfrich said.
MISO on Friday gathered interconnection and transmission customers in a special teleconference to discuss potential waivers of its queue requirements because of the ongoing COVID-19 pandemic.
Senior Corporate Counsel Chris Supino told call participants that MISO is “willing to consider seeking waivers” from FERC of some generator interconnection and agreement requirements to give extra time to parties navigating the queue under the cloud of the pandemic.
Supino asked interconnection customers and transmission owners to tell their pandemic-related impacts to MISO. The RTO said it’s exploring some deadline extensions related to satisfying site control requirements, temporarily relaxing deadlines around study deposits and extending time frames for facility studies.
“We understand it’s hard to get out to the land and talk to landowners,” Supino said of MISO’s requirement that customers demonstrate 100% site control 90 days before proposed projects enter the first of the three-part definitive planning phase of the queue for study.
Supino also said interconnection customers have expressed concerns over the “general availability of consultants, advisers and legal teams” during social distancing mandates. The limited accessibility of third-party contractors could delay critical aspects of generation projects, some stakeholders said.
Other stakeholders are asking MISO to extend its usual three-year grace period for projects to achieve commercial operation in generator interconnection agreements.
Supino said MISO wants to keep the waivers “reasonably limited” to the next few months to prevent cascading impacts to the queue.
“We are looking to address requirements that are an issue for a large portion of our stakeholders, or at least a substantial group,” he said. “We’re not looking for one-off circumstances. I know that many different things can happen with a project, and there might be temptation … but we want to keep this focused on the issue at hand here.”
Supino said customers who believe that special circumstances related to the pandemic are impacting their interconnection projects should “contact MISO to discuss their specific situation and why further waiver relief is needed.” He said stakeholder feedback so far appears reasonable, focused on “pushing deadlines out,” not weakening or rewriting queue requirements.
“We don’t want to over-relax requirements or cause problems for customers, or impact the next queue cycle,” he said, adding that MISO also doesn’t want to put renewable projects in jeopardy of not receiving production tax credits.
MISO has several queue deadlines looming in the next 90 days, including: a June 25 application deadline for a new cycle of project proposals; proof of site control for MISO South projects in the 2020 cycle; the first decision point on whether to remain in the queue and risk monetary penalties for the 2019 batch of South generation projects; and the second decision point for Central and East projects that entered the queue in 2018.
Staff so far said they haven’t fallen behind in the processing of applications or the study of interconnection requests. “We’ve successfully transitioned to most of our employees working from home,” Manager of Probabilistic Resource Studies Ryan Westphal told stakeholders.
NextEra Energy Resources’ John Dailey said interconnection customers beyond those entering the queue in June will be affected. He said interconnection customers planning to enter the queue over the remainder of the year had already been working on securing land.
WPPI Energy’s Steve Leovy cautioned MISO not to tie temporary queue extensions to any federal or state declarations, as the stages of the pandemic are quickly evolving. He instead urged the RTO to examine the “general circumstances” of the crisis.
Clean Grid Alliance’s Rhonda Peters thanked MISO for considering waivers and asked how quickly it could put them in place. Supino said that FERC has been processing pandemic-related waivers “very quickly.”
PJM has already filed a queue waiver to extend study deposit due dates, feasibility studies and reviews of new service requests and processing. NYISO has obtained a waiver of its notarization requirements.
MISO will discuss possible queue waivers with the Planning Advisory Committee during its April 15 conference call.
