Page 1112 – RTO Insider

April 14, 2020

Methane Levels Hit All-time High

By Rich Heidorn Jr.

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.

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 g lobal w arming p otential (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.”

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.

April 14, 2020

New Pa. Generator Hedging Gas Prices with Ethane

By Michael Yoder

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.

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.

April 14, 2020

ERCOT Sees Little Effect on Demand from COVID-19

By Tom Kleckner

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.

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.

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.)

“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.)

April 12, 2020March 12, 2025

PowerOptions CEO Navigates New Job amid Crisis

By Michael Kuser

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.

April 12, 2020

MISO Exploring Emergency Pricing, Forward Market

By Amanda Durish Cook

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.”

MISO emergency pricing — Michaela Flagg, MISO | © *RTO Insider*

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.

April 12, 2020

MISO Considers COVID-19 Queue Waivers

By Amanda Durish Cook

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.

MISO COVID-19 Queue Waivers — Chris Supino, MISO | © *RTO Insider*

“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.

April 12, 2020

COVID-19 Transforming MISO Load, Outage Schedules

By Amanda Durish Cook

The MISO footprint sank deeper into the COVID-19 twilight zone in early April, with demand flattening further and some maintenance outages frozen until some semblance of normalcy is restored.

As the coronavirus pandemic wears on, the RTO is experiencing lower loads that no longer follow a sharp uptick in demand in the morning or evening. MISO said the usual morning peak at about 9 a.m. has given way to a gentler bump in demand around noon that holds steady until the evening, when it gradually drops off. (See MISO Deepens Insights into Pandemic Impact.)

But MISO now says the slight morning and evening bumps have become even flatter in early April.

“The evening peak is now almost nonexistent,” MISO Director of Central Region Operations Ron Arness told stakeholders on a Market Subcommittee teleconference Thursday. “As people started staying home more, we began to see a shift in our load profile. … But then as we got into further restrictions and less activity in more and more areas in the country, we started to see a bigger deviation.”

MISO’s deviation from its historical load trends currently stands at about 8% for the first week of April.

“We continue to track it,” Arness told stakeholders. “We see that load continues to tweak down.”

MISO load COVID-19 — MISO load deviations because of the coronavirus pandemic | *MISO*

Arness said MISO South so far is the least impacted by different load shapes during the pandemic.

Independent Market Monitor David Patton said his analysis of the impacts are “on the same page” as MISO’s.

Skeleton work crews at some generation and transmission sites continue to delay some planned maintenance outages, Arness reported. MISO continues to assert that outage delays and reschedules aren’t a threat to reliability.

MISO said it has received 33 requests to move or cancel planned transmission outages since the pandemic took hold, representing about 10% of planned transmission outages. Arness said only some of those reschedules are related to COVID-19 restrictions. Half the outage reschedules will be moved to May and the first part of June; the other half have been canceled.

On the generation side, 30 generator outages representing about 16 GW will be moved from their original dates; all are pandemic-related. Arness said about a third of these will be rescheduled in the fall; another third are “still determining their reschedule plans.”

Arness said MISO is working with transmission and generation owners to reschedule outages, being careful to avoid clustering them around the summer peak.

“Again, we don’t see any big alarms when the COVID-19 [emergency] lifts,” Arness said, adding that MISO has seen “very few” reschedules to June.

“It is a dynamic situation, and we’ll continue to monitor it,” he added.

Stakeholders asked if MISO might become jammed up with outages come fall. Arness said he’s discussing the possibility with the RTO’s outage coordination team.

Stakeholders also asked if MISO would grant amnesty to members that violate the 120-day outage notice requirement because of the pandemic-related scheduling. Arness said members should contact their assigned outage coordinators to discuss their rescheduling needs.

April 9, 2020

MISO Offers Concession on LMR Capacity Credit Plan

By Amanda Durish Cook

MISO is offering stakeholders a compromise on one of two resource adequacy proposals it will file with FERC next month, removing a provision that would eliminate capacity credits for slow-response load-modifying resources (LMRs).

Zakaria Joundi, MISO’s recently appointed director of resource adequacy coordination, acknowledged he’s entering his new role as the RTO completes a contentious proposal. Nevertheless, he called the LMR measure “a step in the right direction” for MISO.

But several stakeholders on a Resource Adequacy Subcommittee teleconference Wednesday blasted the filings as poorly supported and questioned their need. The proposals include measures to reduce capacity accreditation for LMRs based on their actual ability to mitigate reliability issues and require resources to procure transmission deliverability to their full installed capacity levels before receiving full capacity credits. (See MISO Prepares Deliverability, LMR Accreditation Filings.)

The proposals are set to take effect in time for the 2021/22 Planning Resource Auction.

LMR Accreditation Alterations

MISO said employing an LMR accreditation “based on lead times and call capacity” will lead to more reliable operations.

The RTO plans to base an LMR’s capacity accreditation on the smaller of either an average of its actual availability over a three-year period or its tested availability. LMRs that can respond more often and with shorter lead times will receive a larger capacity credit, while those that can respond to 10 or more calls in a year will receive full capacity credit. (See MISO Pursues Leaner LMR Accreditation.)

MISO LMR Capacity Credit — MISO’s new proposal for LMR capacity credit | *MISO*

But MISO said it will put a two-year hold on its plan to eliminate capacity credits for LMRs that cannot be ready to reduce load within six hours.

Instead, the RTO now proposes that LMRs with lead times greater than six hours but less than or equal to 12 hours receive a 50% capacity credit if they can respond to at least 10 calls in a year. MISO said the compromise should only be effective until 2023, when the RTO will again seek a 0% capacity credit for the long-lead resources.

MISO has previously said that LMRs needing more than six hours’ notice don’t help mitigate emergency conditions, when time is of the essence.

The proposal still calls for demand response resources to receive a 100% credit if they can be available within six hours or less to 10 calls or more in a year, while resources that can respond to five to nine calls would receive an 80% accreditation. Behind-the-meter generation (BTMG) that can deploy with notice of six hours or less and respond to five or more calls in a year would also receive a 100% capacity credit. MISO staff explained that BTMG accreditation requirements are more lenient because their credits are already reduced by a forced outage rate.

Stiffer Capacity Deliverability

MISO is holding firm on a provision that would eliminate capacity resources’ ability to demonstrate full deliverability by way of unforced capacity (UCAP) levels, plucking full capacity credits from resources that use a UCAP-based determination. Instead, the gold standard in capacity deliverability would be resources that can procure firm transmission up to their installed capacity (ICAP) levels.

The RTO’s Tariff requires capacity resources to demonstrate capacity deliverability by having network resource interconnection service (NRIS), which stipulates that the entire ICAP of the resources must be deliverable. However, the Tariff also allows resources to demonstrate deliverability by securing energy resource interconnection service (ERIS) and procuring firm transmission service up to their UCAP levels, which tend to be about 5 to 10% below full ICAP levels. MISO’s Independent Market Monitor has contended that the RTO doesn’t properly account for capacity deliverability because its loss-of-load expectation study assumes that all capacity resources are fully deliverable on an ICAP basis.

MISO has said that while it would not require planning resources to procure full transmission service up to their ICAP levels, resources that are only partially deliverable would not receive full capacity credits. The RTO said it would be fine for conventional generators to opt not to purchase additional transmission service and settle for fewer zonal resource credits.

“There will be impacted entities,” Joundi said of the stricter deliverability requirement. He conceded that it may be expensive for some resources to secure firm transmission service up to their ICAP levels.

Customized Energy Solutions’ Ted Kuhn asked if MISO has determined a course of action if FERC rejects either the LMR capacity accreditation or ICAP deliverability proposals.

“Although it’s a policy to never answer a hypothetical, this depends on the reaction from FERC,” MISO Executive Director of Market Operations Shawn McFarlane said. He said the RTO would only rework the proposal if FERC indicates there’s a “tremendously fatal flaw” in the LMR filing. It would, however, have enough time to pursue a “two-step” process with FERC, he said, meaning a refiling to correct small concerns, if the commission has them.

However, McFarlane said the proposals at this point aren’t open to further stakeholder suggestions.

Opposition

Some stakeholders remain opposed to both measures, with most pushback against the LMR measure. Critics say MISO hasn’t made a convincing argument that the LMR accreditation process needs more rules.

Customized Energy Solutions’ David Sapper, representing MISO load-serving entities, said the RTO hasn’t demonstrated that its proposals will make capacity more abundant or available.

“MISO has neither clearly defined a problem with LMR contribution to resource adequacy nor demonstrated benefits from its proposed solutions that outweigh expected high costs of the solutions,” Sapper said.

He pointed out that it was only a little more than a year ago that MISO got permission to require its LMRs to offer capacity in less than 12 hours and in accordance with a seasonal availability report. (See MISO LMR Capacity Rules Get FERC Approval.)

“It’s not clear why MISO is not letting the new processes work,” Sapper said, adding that the RTO’s six-hour lead time benchmark “will drive at least some” LMRs from the PRA.

Sapper advanced a motion that the subcommittee formally oppose the LMR filing — which it will put to an email vote.

McFarlane said the number of LMRs registering as capacity resources within the footprint only continues to increase, as do the number of emergency events. He said the uptick in both means MISO doesn’t have the luxury of waiting longer to propose new rules.

Staff also said the first FERC filing regarding LMRs was always intended to be a stopgap as MISO worked on a fuller solution.

“We think the 50% accreditation, especially in the next PRA, is a drastic change,” Michigan Public Service Commission staff member Bonnie Janssen said.

WPPI Energy’s Steve Leovy said he remains dissatisfied with the solution and what he perceives as rigidness on MISO’s part to change the proposal on stakeholder advice.

“We were careening towards a solution that I felt was pretty clear at the outset,” Leovy said, adding that he remains concerned about “shocks to MISO’s resource adequacy” as a result of the reductions in LMR capacity credits.

“What I’ve seen is a sharpshooter approach where [MISO] singles out a certain resource and just picks on it when there are other things it could do,” Kuhn said.

April 9, 2020March 12, 2025

Trader Challenges PJM FTR Forfeiture Rules

By Rich Heidorn Jr.

A financial transmission rights trader has filed a new challenge to the way PJM and its Independent Market Monitor prevent gaming, saying it is “so broad that it captures competitive market conduct and leads to less efficient market outcomes.”

XO Energy, of Landenberg, Pa., asked FERC to order PJM to change its FTR forfeiture rule or abandon it and adopt “a structured market monitoring approach” like the one used by MISO (EL20-41). The company said it exited PJM’s virtual market in December after getting hit with $4.3 million in forfeitures.

FTRs allow load-serving entities to hedge the risk of transmission congestion costs; they also allow financial traders to arbitrage day-ahead and real-time congestion.

Ten largest positive and negative FTR target allocations summed by sink: 2019/2020 | Monitoring Analytics

PJM implemented the forfeiture rule to prevent market participants from using virtual transactions to create congestion that benefits their FTR positions. The FTR holder forfeits the profit from its FTR when it submits an increment offer (INCs) or decrement bid (DECs) at or near an FTR location that results in a higher LMP spread in the day-ahead market than in real time.

In January 2017, FERC ordered PJM to change how it implements the forfeiture rule, saying the RTO’s focus on individual transactions failed to capture the impact of a market participant’s overall portfolio of virtual transactions on a constraint (EL14-37). (See FERC Orders Portfolio Approach for PJM FTR Forfeiture Rule.)

PJM filed Tariff revisions in April and June 2017 describing its new approach (ER17-1433). In September 2017, PJM began billing forfeitures based on its new approach, XO said, despite the fact that the commission has never acted on it.

Financial Leverage Test

To encourage legitimate hedging while preventing manipulation, XO said PJM’s forfeiture rule should be changed to identify when participants that hold physical assets and engage in virtual transactions have a leveraged portfolio — when the net benefits to the participant’s FTRs exceed the net losses of its virtual transactions on a given constraint.

“A critical defect of the FTR forfeiture rule is that … it fails to consider whether a market participant has financial leverage, rendering the rule unjust and unreasonable,” XO said. “If financial leverage does not exist, further scrutiny of a market participant’s activity is unnecessary.”

XO said the rule also must require the Monitor to determine the participant’s intent.

Monthly FTR forfeitures for physical and financial participants | Monitoring Analytics

“There is no such thing as a properly designed automatic forfeiture rule; any forfeiture rule should only relinquish profits from conduct that, if combined with sufficient credible evidence of intent, would constitute a potential violation,” XO said. “In Order 670, the commission found that a fundamental component of any alleged manipulation claim is whether the market participant acted with sufficient scienter or intent.

“Although the presence of financial leverage can be easily determined, a comprehensive, fact-specific examination is necessary to identify sufficient evidence of intent.”

Although PJM and CAISO use forfeiture rules, XO said MISO, NYISO, SPP and ISO-NE “use their market monitoring function to provide surveillance in lieu of a rule that oftentimes captures rational economic behavior.”

XO complained that market participants lack access to the data on which forfeiture determinations are made and that the assessments are made more than two months after the activity in question. “The current FTR forfeiture rule has resulted in market inefficiencies by penalizing financial market participants whose virtual activity is profitable. In addition, market participants with physical positions are unable to hedge their physical load or generation positions.”

PJM did not respond to questions about the complaint.

Monitor Joe Bowring said in an email that “the complaint rehashes old and discredited arguments in an effort to overturn a rule which efficiently and effectively protects the markets from manipulation. … It would be a waste of the commission’s, PJM’s and stakeholders’ time to proceed.”

Leaving the Markets

In 2019, XO said, it forfeited $4.3 million, while its gross FTR revenue was only $1.4 million, resulting in a net loss of $2.9 million.

As a result, XO said it withdrew from the virtual market in December 2019. It said Exelon and NextEra Energy Marketing stopped virtual trading also. NextEra did not reply to a request for comment on the complaint Thursday. Exelon declined to comment.

Exelon raised concerns similar to XO’s complaint in a problem statement in February 2018, and it backed a proposal to change the FTR impact threshold from PJM’s “penny test” to one of FTR flows of 10% or more across a constraint.

The Markets and Reliability Committee declined to adopt the proposal in April 2019. (See “Load Interests Block FTR Rule Changes,” PJM MRC/MC Briefs: April 25, 2019.)

April 9, 2020

ERCOT Stakeholders Dig into Real-Time Co-optimization

By Tom Kleckner

ERCOT stakeholders have begun the arduous process of reviewing and commenting on the protocol changes the grid operator has drafted to add real-time co-optimization (RTC) to its energy-only market.

Members of the Real-Time Co-optimization Task Force and other interested stakeholders began walking through staff’s initial set of protocol revision requests during a conference call Wednesday. The goal is to reach consensus and secure the changes’ approval before the year is out.

The task is not without consequence for staff and stakeholders.

Staff have drafted seven Nodal Protocol revision requests (NPRRs) and two other changes, using language the RTCTF developed last year as a starting point. The task force’s key principles were approved by ERCOT’s Board of Directors in February. (See “Real-Time Co-optimization Team Finalizes Scope,” ERCOT Board of Directors Briefs: Feb. 11, 2020.)

The revisions take up 549 pages, 248 alone for NPRR1010. The changes align the language related to the adjustment period (for trades, self-schedules and resource commitments) and real-time operations with the upcoming RTC terminology and operating environment.

ERCOT Real-Time Co-optimization — Matt Mereness, ERCOT | © *RTO Insider*

“That’ll be the pain point,” predicted ERCOT’s Matt Mereness, the task force’s chair.

During the call, stakeholders debated the more efficient methods of reviewing the language. Some called for going NPRR by NPRR, but others agreed with staff’s recommendation to review the NPRRs by areas of common processes.

“To me, we would be a whole lot better off if we took [individual NPRRs] … and go through the whole darn thing top to bottom,” consultant Floyd Trefny said. “The problem is when you break it up in all these pieces and try to put it back together again, it seems like it’s going to fall apart. That’s what concerns me.”

Mereness responded by saying it would be “embarrassing” to say how many hours staff spent on devising the review process. ERCOT’s approach, he said, would place the right subject-matter experts in the same room at the same time.

“We’re seeing the efficiencies of the stakeholders having the right people in the room,” Mereness said.

Comments Encouraged

Staff said they welcomed formal comments through the revision request process. They also encouraged market participants to send red-lined revisions to the task force for its consideration.

ERCOT has scheduled nine meetings for the group to finalize the revisions, culminating in a number of Technical Advisory Committee subcommittee meetings in October. The TAC would then be given a chance to endorse the NPRRs in November, with the board taking them up in December.

“For the task force’s purposes, anyone at any time has the right to make comments,” Mereness said. “We don’t want to create so much structure that we can’t move forward. TAC will be the place to get unstuck.”

Mereness said ERCOT would “consider” adding changes if they save stakeholders money, but he wouldn’t guarantee changes outside the team’s scope would be accepted.

“We’re laser-beamed in how to get real-time co-optimization in successfully,” Mereness said. “We have to keep that laser-beam focus on getting through those 549 pages. If something is wrong, let us know. We’ve done our best to keep us in a good structural place.”

The delivery schedule remains aligned with upgrades to ERCOT’s Energy Management System, scheduled to go live in May 2024.

ERCOT is projecting it will cost $50 million to $55 million to add the RTC tool, which procures both energy and ancillary services every five minutes, to the market.

The nine revision requests the task force is working on:

NPRR1007: Updates the protocols for the ERCOT system’s management activities to address changes associated with RTC’s implementation.
NPRR1008: Updates day-ahead operations’ protocols.
NPRR1009: Updates transmission security analysis and reliability unit commitment to address RTC’s changes.
NPRR1010: Updates protocols to account for RTC’s changes to the adjustment period and real-time operations.
NPRR1011: Updates protocols on performance monitoring.
NPRR1012: Updates protocols on settlement and billing for RTC’s implementation.
NPRR1013: Updates the protected information provisions, definitions and acronyms; market participants’ registration and qualification; and market suspension and restart.
NOGRR211: The Nodal Operating Guide revision request updates language related to supplemental ancillary service markets, ancillary service deployment, and ancillary service responsibilities and obligations.
OBDRR020: The other binding document revision request updates the methodology for setting maximum shadow prices for network and power balance constraints to address changes associated with RTC’s implementation.