Champlain Hudson Power Express said Tuesday it has closed on the financing needed to build its roughly $6 billion underground transmission line linking Quebec and New York City.
All major permits for the 340-mile U.S. portion of the 1,250-MW transmission line are in place, and construction will begin this fall in New York, CHPE said. Government permits for the 36-mile Canadian portion of the project are anticipated in summer 2023, and completion is projected in spring 2026.
Along with construction costs, the project price tag includes tens of millions of dollars for community benefit projects over the next several decades.
“The project financing announced today is an important step toward starting construction and beginning to realize the tremendous economic and environmental benefits this project will provide to residents, organizations and municipalities throughout the state,” Donald Jessome, CEO of TDI-USA Holdings, CHPE’s parent, said in a news release Tuesday. “We look forward to watching our community partners move forward with vital projects that will improve the communities they live and work in, and to soon begin delivering clean, renewable energy to New York City.”
CHPE has been in the works for more than a decade: It was first proposed in 2010, and it received approval from the New York Public Service Commission in 2013.
It is an important part of the state’s decarbonization strategy, as it will bring more than 1 GW of zero-emission hydroelectric power to a region that now relies heavily on fossil-generated electricity.
Dominion Energy (NYSE:D) on Friday filed a settlement agreement with the Virginia attorney general and other stakeholders that proposes an alternative to the performance requirement ordered by the State Corporation Commission (SCC) for the company’s $9.8 billion Coastal Virginia Offshore Wind (CVOW) project.
The group proposes to replace a 42% capacity performance guarantee, imposed by the SCC as a condition of its approval of the project, with a process through which the company explains any capacity shortfalls and the commission determines remedies. The company would be required to “provide a detailed explanation of the factors contributing to any deficiency” causing the project’s net capacity factor to fall below 42% on a three-year rolling average. The commission would then determine whether the shortfall “resulted from the unreasonable or imprudent actions of the company” and could impose a remedy addressing incremental energy or other costs.
Dominion CEO Robert Blue had called the performance mandate “untenable” and said it would require the company “to financially guarantee the weather, among other factors beyond its control, for the life of the project.” In an Aug. 22 petition for reconsideration, the company said it could be forced to terminate all development of the project if the requirement was not lifted. (See Dominion CEO: SCC Order for OSW Performance Guarantee ‘Untenable’.)
“Given the now significantly de-risked status of the project’s development, and given its continued ‘on-budget’ status, we feel that this settlement reflects a balanced sharing of financial impacts in what we currently see as unlikely scenarios of material delays or cost overruns,” Blue said in a statement on the agreement, which included the Sierra Club, Walmart (NYSE:WMT)
and environmental advocacy organization Appalachian Voices.
University of Virginia environmental law professor Cale Jaffe, who worked with Sierra on the settlement, said the proposed agreement addresses their concerns with the performance guarantee by leaving the door open to a precedent being set for fossil fuel generators being subject to the same requirements that offshore wind may be held to. He noted that Dominion’s Wise County coal plant has been operating well below its estimated capacity factor and has been steadily declining, leaving ratepayers with a large capital cost.
“We were very concerned about asymmetric treatment between new renewable energy … and older fossil fuel generation. … So one point we wanted to make sure was to raise concerns of any asymmetric treatment of renewable resources as compared to fossil,” he said.
The proposal would also avoid the possibility of making the project so onerous as to make development impossible, he said, which would come into conflict with the statutory demands of the Virginia Clean Economy Act, which is explicit in designating that CVOW is in the public interest.
The agreement, however, would not resolve Sierra’s original concern in the project: ensuring that the development considers the historically disadvantaged communities of Hampton Roads. Jaffe said the club will continue pushing for those interests to be included in Dominion’s economic plan, in the form of considering local and minority-owned businesses for hiring employees.
“There would be roughly 900 construction jobs, another 1,100 operation jobs … and we wanted to make sure diversity, equity, and inclusion was a part of that,” Jaffe said.
Agreement Includes ‘Unprecedented Consumer Protections’
In a statement on the filing, Attorney General Jason Miyares said the agreement includes “unprecedented consumer protections for Virginians” with cost sharing on project overruns and a cost cap on construction expenses.
“I am pleased that we have achieved consumer protections never seen before in modern Virginia history. For the first time, Dominion has significant skin in the game to ensure that the project is delivered on budget. Should the project run materially overbudget, it will come out of Dominion’s pocket, not consumers’,” Miyares said.
Under the proposed cost-sharing arrangement, customers would pay the first $500 million of costs above $9.8 billion, followed by an even split for the following $1 billion. Any costs above $11.3 billion will be paid entirely by Dominion; though if the project rises above $13.7 billion, it would go before the SCC to make a determination of viability and potential further cost allocation.
“This cost-sharing and cost-cap agreement means that Dominion will potentially have to pay almost $3 billion if the project runs over budget. Ensuring that the project remains on budget is crucial to ensuring it is also built on time,” Miyares said.
The agreement also states that Dominion “shall take all reasonable steps to ensure that customers receive the full and complete benefits of the Inflation Reduction Act of 2022” and not make any elections under the legislation that would reduce the benefit to customers. It also stipulates that if the completed project produces less than 2,587 MW, the cost-sharing schedule would also decrease on a per-megawatt prorated basis.
Dominion said work has continued to keep the project on schedule, which calls for construction to be complete in late 2026, and 90% of costs are expected to be fixed by the end of the first quarter of next year, up from 75% currently.
“The settlement agreement provides a balanced and reasonable approach that supports continued investment in CVOW to meet the commonwealth’s public policy and economic development priorities and the needs of Dominion Energy Virginia’s 2.7 million customers representing more than 5 million people and businesses,” the company said.
Appalachian Voices Virginia Policy Director Peter Anderson said the proposal creates an alternative to the SCC order for controlling the project’s construction risks and bringing down the presumption of reasonable costs ratepayers could be responsible for in the event of overruns. He also believes the agreement balances the interests of all the parties involved in the development, particularly by ensuring that the company bears some risk alongside customers.
“At this point it’s up to the commission as to whether they think it’s in the best interests of ratepayers,” he said.
California’s statewide greenhouse gas emissions dropped 8.7% in 2020, a “historic” decline that’s largely due to the impact of the COVID-19 pandemic, according to a new report.
The data are included in “California Greenhouse Gas Emissions for 2000 to 2020,” a greenhouse gas inventory released last week by the California Air Resources Board (CARB).
CARB said the drop in GHG emissions in 2020 was the largest percentage decrease in the more than two decades that the state has been tracking GHG emissions. Previously, the largest decline occurred between 2008 and 2009, when GHG emissions fell 6% during the Great Recession.
In 2019, the state’s GHG emissions fell 1.7%, following an increase of less than 1% in 2018. (SeeCalif. GHGs Decline 1.7% in 2019.)
The “historic plummet in emissions” in 2020 was due to the pandemic, according to CARB, which cautioned the public to view the results as an outlier.
“Economic recovery from the pandemic may result in emissions increases over the next few years,” CARB said in its report. “As such, the total 2020 reported emissions are likely an anomaly, and any near-term increases in annual emissions should be considered in the context of the pandemic.”
Transportation Emissions
California’s 2020 GHG emissions totaled 369.2 million metric tons (MMT) of CO2 equivalent (CO2e), 35.3 MMT less than 2019 levels.
When analyzed by sector, the largest decline was in transportation, which saw a 16% decrease in GHG emissions or a drop of 27 MMT of CO2e. Transportation remained the largest contributor to the state’s GHG inventory, accounting for 37% of the total.
CARB said the 16% decrease in transportation emissions was likely due to shelter-in-place orders issued in 2020 and an associated decrease in driving.
Other factors are the 18% growth during 2020 in the number of battery electric vehicles in the state and increases in fuel-efficiency of vehicles. In addition, heavy-duty trucks are using an increasing percentage of bio- and renewable diesel fuel, which accounted for 21% of diesel fuel sold in the state in 2020.
GHG emissions also decreased in the industrial sector, with a drop of 7 MMT of CO2e, or 9%. Decreased emissions from oil and gas production, as well as refining and hydrogen production, contributed to the sector’s results.
In the commercial and residential sector, GHG emissions fell by 1.7 MMT, which CARB attributed to a relatively warm winter and a slowdown in commercial activity due to the pandemic.
Electricity Sector
One sector that did not see a substantial drop in GHG emissions in 2020 was electricity, which remained near 2019 levels of about 60 MMT of CO2e. That’s 16% of the state’s total emissions.
GHG emissions from California’s electricity sector. | CARB
Emissions from in-state generation increased in 2020, CARB said, as more natural gas was used to make up for reduced availability of hydropower. But emissions from electricity imported from outside of California fell in 2020, as the state continued a trend of importing a greater share of low-GHG electricity.
In another likely impact of the pandemic, the state’s gross domestic product (GDP) fell by about 2.8% during 2020. But GHG emissions per GDP unit decreased in California that year by 6.1%, which CARB said “demonstrat[es] the effectiveness of California’s long-term climate programs to decarbonize industry, energy and transportation.”
The state’s GHG emissions per capita also fell in 2020, dropping to 9.3 metric tons of CO2e per person compared to 13.1 metric tons per person in 2006.
California Assembly Bill 32 of 2006 set a target of reducing the state’s GHG emissions to 1990 levels by 2020. The state previously reported meeting that goal four years early, in 2016. GHG emissions in 1990 were 431 MMT.
But while preparing the latest edition of the GHG inventory, CARB discovered and corrected a “data discrepancy” that affected past years’ figures, the agency said. The revised data show that the state hit the AB 32 target in 2014 rather than 2016, according to CARB.
California still must meet a more stringent target set by Senate Bill 32 of 2016. The bill requires a reduction of GHG emissions to 40% below 1990 levels by 2030.
In addition, a draft climate change scoping plan that CARB released this year sets a statewide goal of carbon-neutrality by 2045. (See Critics Tear into CARB Draft Climate Change Plan.) The agency expects to finalize the plan by the end of the year.
The clean energy industry experienced its slowest quarter in three years this summer, an industry group reported Wednesday.
The American Clean Power Association said the federal Inflation Reduction Act — passed in August — holds promise for future growth. But the industry was held back in the third quarter by supply chain constraints, trade and tariff issues, and uncertainty over tax policy.
Clean power projects totaling 14.2 GW capacity were delayed in the third quarter, and more than half of them had been delayed in the second quarter, as well. ACP said it is aware of 36.2 GW of delayed projects and 3.5 GW of terminated or canceled projects.
For the quarter, new utility-scale projects totaling 3.4 GW were installed, 22% less than in the third quarter of 2021.
Wind power installations were down 78% and solar down 23%. The exception was battery storage, which is having its best year on record.
JC Sandberg, interim CEO of ACP, said policy and regulatory issues continue to hamper growth.
“The solar market has faced repeated delays as companies struggle to obtain panels as a result of an opaque and slow-moving process at U.S. Customs and Border Protection,” Sandberg said in a news release. “Policy uncertainty around tax incentives constrained wind development, underscoring the near-term need for clear guidance from the Treasury Department so the industry can deliver on the promise of the IRA. Storage was the one bright spot for the industry and had its second-best quarter on record. The aggressive deployment of storage continues to drive down consumer energy costs and enhance grid reliability.”
Sandberg said the Inflation Reduction Act should be a major catalyst for the clean energy industry.
“ACP anticipates that the IRA will give industry the tools it needs to more than triple annual installations of wind, solar, and battery storage by the end of the decade. We expect the IRA to deliver 550 GW of new capacity by 2030, representing $600 billion in capital investment and growing the clean power workforce to nearly a million strong by 2030.”
Some highlights of the report:
Between July and September, 4.6 GW of clean energy projects entered advanced development and 2.5 GW began construction. In total, 93 GW was in advanced development and 39 GW was under construction by the end of the quarter.
Solar accounts for 63% of delays, wind 23% and battery storage 14%. Detained panel shipments are the biggest cause of delays for solar projects, and wind installations are most frequently hampered by supply chain disruptions and grid interconnection delays.
Power purchase agreements for green energy totaled 7.2 GW for the third quarter, and the wind and solar market-averaged national price index reached a new high: $45.93 per MWh, 10% more than the previous quarter and 34% higher than a year earlier.
Texas remains the leader in clean power, with 149.39 GW operational, 11.2 GW under construction, and 12.6 GW in advanced development, each metric the highest among the 50 states. Its third quarter installation total was 1.27 GW, second only to California’s 1.4 GW.
Xcel Energy said Monday that it intends to retire its Tolk Generating Station in West Texas four years ahead of schedule, clearing the way to exit coal usage by the end of 2030.
Xcel said winding down Tolk’s operations at its two units, with a combined capacity of 1,067 MW, early will save ratepayers more than $70 million. Tolk supplies parts of Texas and New Mexico with power. The plant faces a rapidly depleting supply of groundwater for its operations.
Xcel originally agreed to cut the operating life of Tolk from 2037 to 2032 in a 2020 stipulation over a rate increase with the New Mexico Public Regulation Commission. Under the agreement, Xcel also committed to studying at least one scenario where it would retire the plant before 2030. New Mexico has a goal to reach 100% carbon-free electricity by 2045.
The utility said it will soon file a revised retirement date with New Mexico regulators and put the plan to Texas regulators in February.
Xcel said it will continue flexible operations at Tolk, running the plant “when natural gas prices are high while managing limited remaining water resources.” It also said it will run Tolk’s currently installed synchronous condensers beyond 2028 to help ensure grid reliability.
The utility said it will substitute Tolk’s output with a “diverse mix of replacement generation, including wind and solar.”
“For more than 40 years, the dedicated employees at Tolk Generating Station have provided reliable and safe service to our Texas and New Mexico customers and communities,” said Adrian Rodriguez, president of Xcel Energy New Mexico and Texas. “While we maximize replacement generation in the region, we’re also committed to transition our employees into new roles as needed, something we’ve done successfully at other Xcel Energy plants.”
Xcel said Tolk’s accelerated retirement will help meet its goal to reduce carbon emissions 80% by 2030, when its Comanche 3 coal unit, its last coal burner is retired. The company plans to generate 100% carbon-free electricity by midcentury.
“As the first energy provider in the nation to set ambitious goals for addressing all the ways our customers use energy — electricity, heating and transportation — we are always striving to provide our customers cleaner energy resources, while saving them money,” Xcel Energy CEO Bob Frenzel said in a statement. “Advancing the retirement of coal operations at Tolk Station demonstrates our commitment to our clean energy strategy, while ensuring our customers and communities have reliable, affordable and safe service.”
MISO plans to spend $364.2 million throughout 2023, a 3.2% decrease from this year’s budget.
The RTO plans to spend $310.5 million in base operating expenses, $18.2 million in other operating expenses and $35.5 million in project investments, which include its ongoing effort to replace its market platform.
The Audit and Finance Committee of the MISO Board of Directors gave the preliminary budget unanimous support during a Tuesday teleconference. The full board will hold a vote on the proposed budget in early December.
The grid operator remains concerned about employee salary hikes it might have to institute. It intends to spend about $28 million in base operating expenses, a 10% increase over 2022 and said the increase is necessary to onboard more staff to safeguard reliability.
“A lot of these are intellectual efforts,” CFO Melissa Brown explained to board members. She said “wage pressures to attract the talent we need” remain a risk to staying within next year’s budget confines, noting “ripples” from upping salaries caused the most disruption to the 2022 budget. (See “High employee turnover concerns leadership,” MISO Board Week Briefs: Sept. 12-15, 2022.)
However, MISO said it can more than offset the additional spending with a 68% ($38.5 million) decrease in its other expenses category because of higher rates earning more interest income. Other operating expenses includes capital labor, capital interest and other income losses.
Brown said overall, the grid operator expects to collect a $0.44/MWh tariff rate from its members in 2023, lower than its $0.45/MWh rate in 2022.
Alliant Energy’s Mitch Myhre, who chairs the stakeholder-led Finance Subcommittee, said members are concerned over real-world pressures that could impact the 2023 budget. He said MISO could find itself spending $8 million more than expected if it continues to have difficulties maintaining its talent pool and called for staff to “actively manage” the situation.
“It is important that MISO is a judicious and conscientious steward of funds received from its members and remain vigilant against material budget increases or overages,” Myhre said.
Entergy will have to pay SERC Reliability $60,000 in penalties for violating NERC’s reliability standards, according to NERC’s Spreadsheet Notice of Penalty for September approved by FERC last week (NP22-32).
NERC submitted the Spreadsheet NOP on Sept. 29; in addition to the sanctions against Entergy, the document also details a settlement between ReliabilityFirst and American Electric Power (AEP) carrying no monetary penalty. The commission said on Friday that it would not further review the settlements, leaving the Entergy penalties intact.
Also approved on Friday was a separate settlement involving violations of NERC’s Critical Infrastructure Protection (CIP) standards (NP22-34) for which details have not been released in accordance with FERC’s policy on critical energy infrastructure information, along with a settlement between National Grid USA and the Northeast Power Coordinating Council (NP22-33). (See National Grid to Pay $512k for Standards Violations.)
Entergy Faulted for Maintenance, Ratings Mishaps
SERC’s settlement with Entergy concerns infringements of PRC-005-6 (Protection system, automatic reclosing, and sudden pressure relaying maintenance) and FAC-008-3 (Facility ratings). The entity self-reported both violations after discovering them in 2019, though they began in 2016 and 2017 respectively.
The relevant portion of PRC-005-6 lays out the schedule by which transmission owners, generator owners and distribution providers must maintain the equipment to which the standard applies. Entergy disclosed to SERC that it had missed the mandatory maintenance times on several components.
Among the facilities affected was the underfrequency panel at Entergy’s Turnerville substation near Plaquemine, La. Installed in 2010, the panel should have undergone maintenance on its protective relay within six years, according to the standard, but Entergy said that during an internal audit staff discovered this had not been done because the flag for the panel in its automated maintenance tracking system had been deactivated by an unidentified person.
Similarly, the utility failed to perform maintenance on batteries at the McAdams and Cleveland substations in Mississippi that was required within 18 months of their activation in June 2016 and June 2017, respectively. Again, in both cases the maintenance was skipped because the flag in Entergy’s automated system was disabled.
SERC attributed all three instances to “ineffective internal controls,” blaming Entergy for failing to “require approval for disabling maintenance tasks” in its substation work management system (SWMS). Following the discovery of the issues, Entergy performed an extent of condition review on the SWMS to find any other disabled maintenance flags that might develop into noncompliance; none were revealed. The regional entity said no harm is known to have occurred as a result of the violation.
Entergy’s FAC-008-3 violations were also discovered in 2019 but were unrelated to the PRC-005-6 violations. They concern requirement R6 of the standard, which requires that each TO and GO have facility ratings for their solely- and jointly-owned facilities that are “consistent with the associated facility ratings methodology.”
In August 2019, Entergy discovered an active alarm at its Hartburg substation in east Texas, caused by a failure of a cooling system. The failure had begun in March of that year, but operational personnel failed to schedule maintenance or to lower the rating of the substation — even though the cooling failure required a 20.5% derate.
Following this discovery, Entergy performed an extent of condition review to find any other conditions on the system requiring a temporary rerating. Five more were found; in each case personnel at the utility received alarms of the problems, but “the alarms were set as a low priority and personnel failed to update the facility ratings.” Entergy admitted it was “unaware as to why the alarms were originally set to low priority.”
According to SERC, the root cause of the issue was “inadequate training,” particularly on the part of the Entergy personnel that set alarm priorities, who had not been trained on the importance of the cooling systems and their role in facility ratings. This led other personnel to dismiss the alarms and focus on other tasks that seemed more important. Entergy responded to the issue by updating all alarms to the correct priority and establishing annual training to ensure staff are aware of the components that affect rating of transformers.
In both the PRC-005-6 and the FAC-008-3 violations SERC noted prior noncompliance history. The RE considered the PRC-005-6 history to be an aggravating factor in the penalty determination because the extent of condition review conducted in that case should have revealed the violations covered in this settlement. SERC said these issues also call into question the effectiveness of the mitigation plan of the previous violation, which focused heavily on the ability to disable maintenance flags in the SWMS.
ReliabilityFirst’s settlement with AEP (acting as an agent for several utilities including Appalachian Power Company, Ohio Power Company, Wheeling Power Company and others) concerns violations of COM-002-4 (Operating personnel communications protocols).
The entity reported to RF in October 2020 that it was in noncompliance with requirement R6 of the standard, which details the appropriate response to an operating instruction during an emergency. Specifically, utilities that receive oral two-party, person-to-person operating instructions during an emergency must either repeat the instruction and receive confirmation from the issuer that they understood it, or request that the issuer repeat the instruction.
According to the Spreadsheet NOP, two of AEP’s internal communications during a system event in 2019 were found to be noncompliant with the requirement because operators had “failed to execute three-part communication,” referring to the prescribed responses. RF identified the root case as “lack of process adherence and discipline,” and described the risk posed as moderate.
While the RE noted that failure to communicate properly increases the risk of failure to understand the instruction, it also acknowledged that these were the only two instances of improper communication out of 25 communications that occurred during the event.
RF said it processed the violation as a Spreadsheet NOP instead of a lower-level infraction in order to highlight the importance of proper communication procedure during an emergency. The RE pointed out that unclear communication “has contributed to significant events … that led to instability and cascading outages, including the 2003 Northeast Blackout and the Florida Blackout of 2008.” However, based on AEP’s self-reporting and cooperation in this incident, RF decided not to levy a monetary penalty for its infraction of the standard.
PJM CEO Manu Asthana Warns of Potential Generation Shortfalls
CAMBRIDGE, Md. — PJM CEO Manu Asthana said 40 GW in planned retirements and lagging construction of new generation is raising questions about the long-term reliability of the grid.
“We cannot take the reliability that we enjoy in our region for granted through this energy transition; we have to take concrete steps to ensure that it will continue,” Asthana said during his keynote address for the 2022 Annual Meeting of Members prior to the convening of the Markets and Reliability Committee Oct. 24.
He said about 40 GW of generation is expected to retire by 2030, mostly due to policy decisions rather than economics, leaving PJM without a way to incentivize the units to remain online. On top of that, data centers are expected to add 10 to 15 GW of load, with an unknown amount of growth from electrification.
Approximately 30 GW worth of new interconnection service agreements have been signed this year and there’s an additional 250 GW in the interconnection queue. However, the new generation is lagging the pace of installation that has been anticipated, Asthana said. Of the 30 GW of ISAs signed this year, only 1.5 GW has been built so far.
If the pace of constructing new generation doesn’t ramp up, he said it could lead to more reliance on demand response — with curtailments becoming more commonplace than many DR participants signed up for.
“We have time, but we don’t have time to waste,” he said. “We need to take action to ensure we retain an adequate supply of dispatchable generation through the transition.”
The stakeholder process has proven itself through the challenges of the past several years, Asthana said, and will be essential to navigating the clean energy transition as well.
“I still firmly believe that the way to solve the really complex problems of the energy transition is together as a stakeholder body. Not because it’s the quickest way to get there … but because it’s the best way to get to a resilient, durable and lasting set of solutions.”
Black Start Fuel Requirements Advance to Members Committee
PJM stakeholders endorsed a slate of revisions to the tariff and several manuals to reduce the risk of black start generators being offline due to fuel unavailability. The joint PJM, Brookfield Renewable and D.C. Office of the People’s Counsel package received 94% support in the sector-weighted vote.
The proposal, which is set to go before the Members Committee next month, creates a new category of “fuel assured” generators and requires at least one such unit in each transmission zone. The criteria to qualify as a fuel assured unit vary based on the resource type, including connections to multiple interstate gas pipelines, on-site fuel storage and dual-fuel capability.
PJM Senior Engineer Dan Bennett said the effort will create a methodological approach to looking at black start reliability. “We want to make sure this service is compensated fairly and recognized for what it brings to the grid,” Bennett said.
Black start resources whose unavailability during a blackout would cause the projected zonal restoration times to increase by 10 hours or more were identified as “high impact” sites with possible mitigation strategies laid out. The proposal calls for $28,175,000 in additional black start annual revenue for mitigation of the high-impact sites.
Calpine’s David “Scarp” Scarpignato said the requirement of one fuel-assured BSR per transmission zone may be insufficient, raising the possibility of a generator being offline or damaged during a blackout. He also noted that having penalties for fuel assured resources which fail to meet the requirements, but none for non-assured generators could discourage participation in the higher tier.
Joe Bowring, president of Independent Market Monitor Monitoring Analytics, said the proposal could result in overpayments as some BSRs which would qualify as fuel assured elect not to seek that designation, forcing PJM to enroll an additional fuel assured generator. He has also questioned the value of having non-assured resources such as intermittent generators providing black start.
Monitoring Analytics’ own package, which would have prohibited intermittent resources other than run-of-river hydro from enrolling as BSRs, did not receive the support of the Operating Committee and Market Implementation Committee. Bowring did, however, thank PJM for incorporating some of his suggestions into the joint package and said that overall it’s a proposal that provides a needed solution.
Stakeholders Narrowly Reject Demand Response Problem Statement and Issue Charge
The MRC narrowly rejected an initiative to consider the use of statistical sampling for interval-metered residential customer participation as demand response in wholesale markets. The problem statement received 48% sector-weighted support, just shy of the 50% required. (See “Stakeholders Endorse Prohibiting Gas Infrastructure Participation in DR,” PJM Market Implementation Committee Briefs: Oct. 6.)
CPower’s Ken Schisler said the requirement that curtailment service providers use customer meter data for measurement and verification is “an unreasonable barrier for residential metering.” Obtaining access to the data from electric distribution companies remains a challenge and once that data is received, Schisler said CSPs must manage hundreds of thousands of data points when calculating winter peak load.
He also raised the possibility of security issues related to holding large volumes of residential electric usage data, saying that privacy concerns could be greater for personal versus industrial data.
Greg Poulos, executive director of the Consumer Advocates of the PJM States (CAPS), said the proposal offered an opportunity to receive information about barriers to the usage of smart meter data and noted that the adoption of a problem statement would not necessitate the adoption of any solutions examined.
The electric distributor sector had the strongest opposition to the proposal, joined by transmission and generator owners. End use customers unanimously supported the proposal and other suppliers had mixed support.
Alex Stern, of Public Service Electric and Gas, told RTO Insider he believes the MRC was right to oppose PJM becoming involved in residential demand response, which he believes should be addressed by state legislators and regulators before the RTO examines its own rules.
“We really need to respect the states and consider the policy issues, including but not limited to privacy — respecting the privacy of customers, as well as the … rights and responsibilities of states versus PJM,” he said.
Bowring also told the MRC that he believes access to meter data is a state policy issue and said he worries that PJM allowing statistical sampling as a workaround to issues in obtaining that data would create a disincentive for states and CSPs to find a more direct solution.
Paul Sotkiewicz of E-Cubed Policy Associates said the usage of statistical sampling could introduce inaccuracies in the markets and questioned why metering for demand response should be treated any differently from the requirements that generators are held to. “It opens up a can of worms we shouldn’t even be talking about.”
Support for Circuit Breaker Remains Mixed
Stakeholders remained divided on several proposals to impose a circuit breaker to limit the price and duration of high energy prices. None of the seven packages produced by the Energy Price Formation Senior Task Force received 50% support over the status quo in two task force polls, with a proposal from Calpine receiving the highest at 34%.
Presenting the joint stakeholder package, which received 14% support in the polls, Adrien Ford of Old Dominion Electric Cooperative said price spikes can be helpful to encourage generators to respond to issues the grid is facing. However, sustained high prices can result in load paying for tens of millions in higher rates every day that prices remain elevated and a risk of cascading market defaults.
Under the joint package, the circuit breaker would be triggered if the average LMP was above $1,000 for a rolling 24-hour period or above $850 for a rolling 168-hour interval. PJM would also be permitted to trigger a circuit breaker response but could not block one under the proposal.
The circuit breaker would remain in effect until the price cap had not been reached for five consecutive business days.
The proposal would also include administrative adders to provide cost recovery if the cost to generate power exceeds the circuit breaker price cap. Ford said the current rules require generators to go before FERC to seek cost recovery; the joint stakeholder language would shift the decision to PJM instead.
Bowring said that a circuit breaker should not suppress the market price below fundamentals like the cost of gas. Nor should it artificially increase prices by including any administrative adders, like Operating Reserve Demand Curve penalties or transmission constraint penalty factors, he said.
The Calpine proposal would cap the energy component of the LMP at $2,000 when the circuit breaker is triggered; generators would be paid uplift if the LMP is too low to cover their costs. The trigger would be 90 hours of non-consecutive shortage events since June 1, followed by any subsequent event during that delivery year lasting three or more hours. The circuit breaker would continue until the shortage event has ended.
Scarpignato said the $850 price cap under the joint stakeholder proposal would likely be below the cost of gas during many emergencies, while Ford said allowing prices to go as high as the $5,700 per MWh — which is the highest they can go under cost-based offers, reserve shortages and a $2,000/MWh transmission constraint penalty factor — would result in $61 billion in energy costs for a typical winter load or nearly $40 billion without the TCPF.
Jason Barker of Constellation and Sotkiewicz both said they could not support any of the current proposals and urged further discussion to find a compromise package. The MRC is scheduled to consider endorsing a package at its next meeting.
The MRC reviewed a proposal to provide PJM with added flexibility to modify the transmission constraint penalty factor when transmission upgrades are already underway. The PJM proposal aims to provide a solution to an issue identified in 2020, after one of just three transmission lines into Virginia’s Northern Neck peninsula was put on outage for a planned upgrade.
The outage caused price fluctuations that pushed the TCPF to its default of $2,000/MWh in the real-time energy market. Since the completion of the upgrades would resolve the issue and it wouldn’t be possible for new generation to be added prior to the work being finished, PJM successfully argued to FERC that the design of the penalty factor created “unjust and unreasonable energy market rates” for consumers. (See FERC Approves Pause of PJM Tx Constraint Penalty Factor in Va.)
Bowring argued that while PJM’s filing proposal addressed a real issue, its proposal would allow the RTO to subjectively determine penalty factors and does not address why penalty factors are triggered so often. Bowring said the penalty factors increased average PJM prices 11.2% in the first half of 2021 and 6.1% in the first half of 2022. Bowring stated that PJM reduces transmission line ratings by 5% and triggers these transmission constraint penalty factors unnecessarily.
A second IMM proposal failed to garner significant support over the PJM package and the status quo in an EPFSTF poll. The IMM’s alternative would broaden the trigger criteria and use a different methodology for the circuit breaker.
The PJM proposal is scheduled to be considered for endorsement by the MRC at its next meeting.
Two Proposals Remain on Variable Operations and Maintenance Costs
The MRC continued discussion of two competing packages to streamline the accounting of variable operations and maintenance costs.
The PJM proposalwould create default adders for minor maintenance and operating costs as an alternative to generators submitting unit-specific information and would provide definitions of major maintenance and minor maintenance for more clarity on which costs fall into each.
The Constellation package mirrors the PJM language with the exception of removing the refueling and associated maintenance from variable costs, with Barker saying those expenses should be considered part of the unit’s capacity offer, rather than its cost-based energy offer. He said such operations are “fixed” costs that don’t vary with run time.
“Defining planned outage costs as a component of VOM will require a significant annual VOM accounting for all nuclear units; akin to developing an ACR for each unit each year,” Constellation’s presentation said.
The Market Implementation Committee endorsed the PJM package with 70% support at its Sept. 7 meeting, with Constellation’s advancing as an alternative with 54% support. (See “Two Alternatives on VOM Advance to MRC,” PJM Market Implementation Committee Briefs: Sept. 7, 2022.)
Stern said PSEG supports Constellation’s language because it aligns with efforts to preserve nuclear power as a zero emission resource.
Bowring and Sotkiewicz, however, said the package would create a special carveout for one type of generation, with the latter asking if Barker would support an amendment to include time-based operations from other resource types. Barker said such a change would be too major for him to accept as a friendly amendment and would require additional stakeholder input.
Reworked Language on Critical Gas Infrastructure Participation in Demand Response Presented
PJM gave an overview of changes made to the language of a slate of Operating Agreement, Reliability Assurance Agreement and manual revisions to prohibit critical gas infrastructure from participating in demand response programs. Following MIC feedback that the definition of the infrastructure to be affected could be vague, staff removed the word “significantly” from the phrase “which if curtailed, will significantly impact the delivery of natural gas to bulk-power system natural gas-fired generation. (See “Stakeholders Endorse Prohibiting Gas Infrastructure Participation in DR,” PJM Market Implementation Committee Briefs: Oct. 6.)
The timeline for scheduling of future votes on the package has also been changed, with a vote at the Members Committee moved to December to avoid having the MRC and MC voting on the measure on the same day.
SPP’s effort to improve its congestion-hedging processes appears to be gaining traction with its stakeholders, thanks to a recommended hybrid approach that first focuses on equitably allocating congestion rights instruments and then increases the pool of awards available.
Staff presented its proposal to SPP’s Markets and Operations Policy Committee Oct. 11 and then again last week during the RTO’s quarterly joint stakeholder briefing, which stretched over two days. They were expected to bring a final recommendation to the board but asked that a vote be delayed until the directors meet again in January. (See SPP Markets and Operations Policy Committee Briefs: Oct. 10-11, 2022.)
In setting the stage for Day 2 of the discussion, COO Lanny Nickell used a mixed metaphor to explain staff’s two-part proposal to improve congestion hedges.
Nickell said that aligning the models will require five or six different changes on the process’ market-design side and then modifying transmission planning.
“I see those two things working together as one; we’re trying to create better balance, more equity on the market side and then increasing the amount of congestion hedges that might be available,” he said.
“Think about this as being a big pizza pie. Today, on the market side, you get one bite at the apple. We take the whole pie, we throw it out, the ravenous wolves all come charging in and they’d get as much as they can get, but there’s always somebody left hungry,” he said.
“Instead of throwing out the whole pie and letting the hungriest and the biggest do whatever they can to get as much as they can, let’s split that up into five different pieces. Let’s throw out a piece at a time. Everybody comes in and gets what they can, and you throw out the next piece, the theory being that by splitting things up into multiple pieces and giving people multiple chances, you’re more likely to have nobody left hungry. What we’re trying to do on the transmission side is increasing the size of the pie so that the pieces you throw out are even bigger than what they were before.”
“I understand this better. It’s not perfect, but I don’t know anyone that gets everything they want out of the [current] process,” Nebraska Public Power District CEO Tom Kent said.
“I think the staff has come up with a pretty unique and creative solution to the problem,” American Electric Power’s Richard Ross said. As chair of the Market Working Group, Ross has overseen several years of stakeholder efforts to address the situation.
“I think AEP is probably going to be close to neutral as an overall portfolio,” he said, “but the important thing is this aligns the congestion instrument with the congestion cost so that folks can see things and secure things directly rather than having to rely on the slush bucket at the end to hope they get fulfilled. This is doing something different … and it’s a pretty creative idea.”
If handled properly, Ross said, the improved process will help wind-rich utilities export their excess power out of the region, a recurring topic over the past few years.
EDP Renewables’ David Mindham said his company has struggled to gain auction revenue rights. He said congestion costs of $70/MWh have hampered wind developers’ ability to send power eastward to other regions.
“To put [it] in perspective, the cost of exporting that energy is two to three times the levelized cost of actually selling that generation to an entity outside of SPP,” Mindham said. “There’s no hedge for us. I think I can speak for the [wind energy] industry when I say none of us are even considering another export deal until this is fixed. It’s just it’s way too expensive.”
“What [staff] has advanced is a fairly comprehensive and solid concept in terms of moving forward,” Board of Directors Chair Larry Altenbaumer said. “We still need to work through the stakeholder process. This is not a final product here. There’s work to be done, but I do believe from my standpoint that it is responsive to the path forward that I was looking for anyway.”
JTIQ Studies to Replace AFS Studies?
Antoine Lucas, SPP’s vice president of engineering, said staff’s work with MISO to unclog interconnection queues and facilitate transmission along the RTOs’ seam could replace SPP’s affected system study (AFS) process.
The studies are conducted to determine whether generators seeking to interconnect in one RTO require transmission upgrades on the other side of the seam.
Lucas said the joint targeted interconnection queue study benefits will improve cost certainty for the RTOs’ generator interconnection requests, provide interconnection customers with AFS costs before cluster studies, and eliminate unknown AFS network upgrades and AFS study costs.
“We’re looking to use this process as a springboard into replacing the affected system studies. This aligns with where the industry is heading and also optimizes upgrades along the seam,” he said. “Rather than a [generator interconnection] customer identifying the interconnection and then upgrades made from bottom up, we would step back and look at an optimal set of projects.”
RSC Membership Turnover
The Regional State Committee honored several departing members during its Oct. 24 business meeting, including its longest-serving state regulator, Oklahoma Corporation Commission Chair Dana Murphy. A former RSC president, Murphy has been on the committee since 2011.
Incoming RSC president Andrew French, KCC | SPP
“Eleven years of time — you just blink your eyes and then it’s gone,” Murphy said. She will be replaced by the OCC’s Todd Hiett.
Jefferson Byrd, who is running for land commissioner in New Mexico, is also stepping down. Ted Thomas previously stepped away after resigning from the Arkansas commission. (See Arkansas PSC’s Thomas Makes Way for His Successor.)
The RSC also approved its Nomination Committee’s choices for next year’s officers. Kansas’ Andrew French will succeed Randel Christmann as president, with Iowa’s Geri Huser serving as vice president and Texas’ Will McAdams as secretary and treasurer.
In other actions, the committee approved:
RR497, which installs as a business practice the Project Cost Working Group’s oversight for applicable transmission projects that are funded through direct assignment of cost;
RR499, which adds new language to the planning criteria concerning terminology and their definitions, new capability and new operational testing requirements, out-of-season capability testing, capability and operational testing for new or upgraded units, and accreditation for thermal and hydro units;
RR508, which allows load-responsible entities to use deliverable capacity in meeting their winter season obligation;
RR516, which codifies the increase in SPP’s planning reserve margin from 12% to 15%.
The RSC also approved a clean audit of its 2021 financial statements.
SLC Pancaking Strawman Still in Flux
Murphy, who leads the RSC’s representation on the Seams Liaison Committee, a joint group with the Organization of MISO States to develop coordinated seams policies, reviewed with the committee an SLC working group’s proposed strawman for rate pancaking.
The Rate Pancaking Working Group in August listed several recommendations for treatment of unreserved use charges and emergency ties on the RTOs’ seams, improving the ability to obtain congestion hedges for procuring firm transmission, eliminating or reducing rate pancaking for long-term contracts, and eliminating interregional projects could cause unintended rate pancaking issues from interregional projects. (See MISO, SPP Regulators Finish Pancaking Strawman.)
Murphy said her SLC co-chair, Missouri’s Ryan Silvey, updated the OMS in September and requested feedback from the commissioners. She said he had not received that input when she last talked with him in October.
FERC Chair Richard Glick made his first in-person visit to SPP’s Arkansas headquarters last week, joining the grid operator’s stakeholders for their regular quarterly governance meeting.
The trip wasn’t Glick’s first to Arkansas. He served as former U.S. Sen. Dale Bumpers’ (D-Arkansas) legislative director and chief counsel for seven years, which brought him to The Natural State several times.
“The first question I would always get was, ‘You’re not from here, are you?’” Glick, a son of the North, said during the meeting.
He watched from the sidelines as the Board of Directors and the Regional State Committee, comprised of SPP’s state regulators, conducted their business in meetings that were closed to non-rostered members. Glick came away impressed with the RSC’s deliberations on resource adequacy.
“It was a real education because there’s a lot of other regions that have different approaches to state input and state stakeholder processes, and this is definitely unique,” he said. Nodding to SPP’s expanding Western market services, Glick added, “I can see why that’s attractive to others … especially in the West.”
Glick said SPP’s approach to state regulatory input will play a role as the RTO competes with CAISO to offer market services in the Western Interconnection.
“I’m pretty sure everyone would probably agree that eventually, there’s going to be at least one if not more than one RTO developed in the West. It’s certainly moving in that direction, and you all are playing a significant role,” he told stakeholders. “I think just providing an alternative to the California ISO, a structure which is obviously hobbled by the way that the ISO deals with independence or doesn’t have independence in terms of [its] board relationship. I think … the Regional State Committee approach is something that’s very attractive to a lot of the state regulators.”
Glick stressed the importance of accrediting generating resources’ capacity — and not just that of intermittent resources — to maintain grid reliability. He noted that in recent years “more traditional generating plants” have shut down when they should have been available, mostly because of extreme weather.
“It’s something that everyone needs to think about and be much more precise in how we define and accredit capacity,” he said.
Glick said FERC has devoted two years of technical conferences and internal discussions about the best way to structure markets going forward, given the challenges of ensuring reliability and the transition to clean energy.
“One of the questions is [whether] the markets are currently operating in a way that really achieves or maximizes the benefits associated with the transition,” he said. “We’ve had discussions about capacity markets, about ancillary services, about energy markets and other market reforms as well, and the one recurring theme that comes up in all of them is flexibility, the need for more flexibility as we go forward. It can be flexible natural gas; it can be storage; it could be other technologies as well.
“When I first came to FERC … at the beginning of the Trump administration, there was a lot of discussion about, ‘We need more baseload generation, we need to subsidize baseload generation,” Glick said. “To me, that’s the debate that’s kind of not really relevant for today. Today, the relevance to me is how do we incentivize flexibility? I don’t anticipate the commission coming up with anything in the near future on that issue, but it’s something I think we still think about and wanted to move on at some point in the future.”
$245M Operating Budget Approved
The board approved SPP’s 2023 operating budget, net revenue requirement and capital budget following unanimous endorsement by the Members Committee.
The $245.6 million budget is a 6.2% increase over the current year — about two-thirds less than last year’s 17.7% — with salaries and benefits representing the largest share of growth. SPP instituted a one-time, across-the-board raise for staff this year to compensate for inflation.
American Electric Power’s Richard Ross raised concerns that SPP is “too ambitious with our activities that are not a part of our core functions.” Ross often refers to those functions as the grid operator’s “food and shelter” responsibility.
“I’m concerned that we are too ambitious with our activities that are not part of our core functions, in particular, the Western expansion,” he said, citing “recent studies” that indicate the current footprint will see “minimal” benefits from the effort. “I think we need to strongly evaluate whether or not we need to continue the major push that we’re under and whether or not that is truly in the best interest of the core functions of SPP in the long-term.”
“It’s definitely a known item, and there is focus on how that is going to get addressed, because resourcing is critical,” CEO Barbara Sugg responded.
She said SPP has onboarded 81 new staffers this year, but that the turnover rate remains high. She said leadership is taking steps to recruit the “best and the brightest, but also to increase retention.”
The net revenue requirement (NRR) will rise 4.7%, from $176.3 million to $184, Finance Committee Chair Susan Certoma said. SPP’s tariff limits the NRR to a ratio of estimated annual transmission usage, capped at $0.465/MWh. That rate has been set at $0.448/MWh for 2023 but is projected to peak at $0.494/MWh in 2025 before decreasing.
CFO Dunn Retires
Directors and members honored SPP CFO Tom Dunn, who is retiring after 21 years on Dec. 2.
“So, there’s still plenty of time to harass him,” Sugg said.
She said SPP’s headcount increased by 500 employees and its operating budget by $175 million under Dunn’s leadership, and he secured more than $400 million in financing to fund the RTO’s growth while maintaining the lowest cost of service by any system operator.
“Tom has been an invaluable resource to me as well as to all of SPP. I’m thrilled that Tom hung in there with me as the new CEO,” Sugg said. “He has taught me so much about his area of responsibility, but he’s also such an asset to the executive team … who can present different alternatives and suggestions and just kind of help us think out of the box a little bit, which I think is a tremendous asset for all of our executives.”
At first reluctant to speak after the board’s resolution, Dunn recalled one of his first staff meetings. Former CEO Nick Brown asked him to explain finance to the employees. Dunn complied.
“I spent 30 minutes, and [Brown] never invited me to do it again,” he said. “I enjoyed my time at SPP. It’s the best career move I’ve ever made.”
Membership Elects 2 New Directors
The RTO’s membership elected two new directors and one incumbent to the board during SPP’s Annual Meeting of Members.
Joining the board are former ISO-NE general counsel Ray Hepper and Steve Wright, a former Bonneville Power Administration CEO and general manager of Washington’s Chelan County Public Utility District. Bronwen Bastone was elected to a second three-year term.
Wright’s term is effective immediately, as he replaces long-time director Julian Brix, who recently retired from the board. He gives SPP a second director with experience in the Western Interconnection in addition to John Cupparo, which could come in handy as the RTO expands its Western services.
Board chair Larry Altenbaumer reads a resolution honoring six-year director Mark Crisson (right). | SPP
Wright said in a press release that he hopes to “strengthen the bridge” to SPP’s potential Western members. “SPP is at the center of our nation’s ambitious efforts to attain a reliable, affordable and clean electric power system,” he said.
Hepper’s term will begin Jan. 1. He was elected to ERCOT’s board in 2020 but only served a few weeks before the 2021 winter storm came within minutes of collapsing the Texas grid. After several days of outages, Texans directed their ire at the ISO’s out-of-state independent directors, who also resigned.
The SPP board will undergo several other changes next year. Current chair Larry Altenbaumer, who has been on the board since 2005 and has one year left on his term, will step aside in favor of Certoma. Elizabeth Moore will replace Certoma as vice chair.
Mark Crisson is also retiring after six years on the board. The board and members honored Crisson with a standing ovation and a resolution recognizing his service.
“I told Mark it’s been an honor for me to serve with someone like him. … He is perhaps one of the most quietly effective individuals you will encounter,” Altenbaumer said. “He is a very straightforward individual, and if he disagrees with you, he will very constructively let you know that he disagrees with you. I really value that in terms of his role as a board member and the guidance that he sometimes shared with me, even when it wasn’t guidance.”
The membership also elected six new members and six incumbents to the 22-person Members Committee.
Joining the committee for the first time are EDP Renewables’ David Mindham (Independent Power Producer/Marketer segment); Tri-State Generation and Transmission Association’s Mary Ann Zehr (Cooperative); Arkansas Electric Cooperative Corporation’s Buddy Hasten (Cooperative); Google Energy’s Will Conkling (Large Retail); American Clean Power Association’s Daniel Hall (Alternative Power/Public Interest); and Southwestern Public Service/Xcel Energy’s Adrian Rodriguez (Investor-owned Utility).
Re-elected to the committee are American Electric Power’s Peggy Simmons (Investor-owned Utility); Northwestern Energy’s Bleau LaFave (Investor-owned Utility); City Utilities of Springfield’s (Mo.) Chris Jones (Municipal); Dogwood Energy’s Rob Janssen (IPP/Marketer); ITC Great Plains’ Brett Leopold (Independent Transmission Company); and Basin Electric Power Cooperative’s Tom Christensen (Cooperative).
Board Approves 2022 ITP, Consent Agenda
The board approved staff’s 2022 Integrated Transmission Plan, a reliability-only portfolio. The 17-project, $35.4 million plan solves 25 system needs in rebuilding 11 miles of transmission but will not result in any new transmission.
Its unanimously approved consent agenda included chairs for the following stakeholder groups: Credit Practices Working Group, Caleb Head (Northeast Texas Electric Cooperative); System Protection & Control Advisory Group, Chris Angland (Omaha Public Power District); Project Cost Working Group, Brian Johnson (AEP); and Market Working Group, Richard Ross (AEP).
The agenda included the Corporate Governance Committee’s nominations for several committee assignments: Golden Spread Electric Cooperative’s Mike Wise to the Finance Committee; GridLiance High Plains’ Noman Williams to the Human Resources Committee; and AEP’s Ross, Basin Electric’s Christensen, NextEra Energy Resources’ Matt Pawlowski, and Golden Spread’s Natasha Henderson to the Strategic Planning Committee.
It also included several modified and withdrawn notifications to construct, an amended and restated Western Joint Dispatch Agreement to facilitate three Black Hills Corp. subsidiaries’ 2023 membership into the Western Energy Imbalance Service market, and six revision requests previously endorsed by MOPC:
RR499: Adds new language to the planning criteria concerning terminology and their definitions, new capability and new operational testing requirements, out-of-season capability testing, capability and operational testing for new or upgraded units, and accreditation for thermal and hydro units.
RR508: Allows LREs to use deliverable capacity to meet their winter season obligation.
RR512: Requires LREs to submit used and unused capacity on behind-the-meter resources that have qualified as accredited capacity that can be used to respond to emergency conditions.
RR514: Updates the operating constraint and spin violation relaxation limits by increasing the values of all operating reserve constraints not subject to market-to-market coordination to $1,500
RR516: Codifies the increase of the planning reserve margin from 12% to 15%.
RR520: Gives the balancing authority greater ability to forecast and measure non-registered, available demand response by analyzing data submitted daily from affected LREs.
