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November 1, 2024

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Santee Cooper Joins SEEM

South Carolina state-owned electric and water utility South Carolina Public Service Authority (Santee Cooper) has agreed to join the Southeast Energy Exchange Market (SEEM), the company said Thursday.

The move adds Santee Cooper to the list of “founding members” of SEEM, which comprises nearly 20 utilities across 11 states including Southern Co., Dominion Energy South Carolina, LG&E and KU, the Tennessee Valley Authority and Duke Energy. SEEM’s members said last month they plan to launch the market in the third quarter this year. (See FERC Rejects SEEM Opponents’ Rehearing Requests.)

Santee Cooper’s embrace of SEEM shows the support the concept has gained in the energy industry since its supporters submitted the proposed agreement to FERC last February. Proponents say the planned expansion of bilateral trading across the Southeast will reduce trading friction through the introduction of automation, eliminating transmission rate pancaking and allowing 15-minute energy transactions, while also promoting the integration of renewable resources.

In a press release, Santee Cooper Deputy CEO Charlie Duckworth said the utility is “excited by the opportunities SEEM will offer our customers, including better capability for integrating renewables and savings from lower fuel costs and improved efficiencies.”

The SEEM agreement took effect in October after FERC — which at the time had just four commissioners after the departure of Neil Chatterjee — split 2-2 over whether to approve the measure. Because it had been more than 60 days since supporters’ response to FERC’s last deficiency letter, the measure automatically became enforceable under Section 205 of the Federal Power Act. (See SEEM to Move Ahead, Minus FERC Approval.)

Since then the commission has approved revisions to four of the participating utilities’ tariffs implementing the special transmission service used to deliver the market’s energy transactions. (See FERC Accepts Key Tariff Revisions to SEEM.) Members have also submitted further changes to the commission that would implement a series of “transparency enhancements” to the market. (See SEEM Members Embrace Market Changes.)

Santee Cooper is South Carolina’s largest power provider and the ultimate source of electricity for 2 million people across the state. The utility’s fate has been up in the air in recent years after losing billions in 2017 on a failed project to expand a nuclear power plant, which led the state to put it up for sale in 2019. Florida-based NextEra Energy put in the highest bid but withdrew its offer last April when it became clear that South Carolina lawmakers lacked the votes to approve the sale because of concerns that it would lead to layoffs and higher electric rates.

Instead of selling the utility, lawmakers voted through a package of measures that included removing nine of the 10 members of the utility’s board of directors and restricting severance pay for any terminated executives. The changes also gave state regulators more power over Santee Cooper by allowing them to review its future generation plans and power forecasts and to require public hearings and government oversight ahead of future rate increases.

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NEPOOL PC Approves Tariff Changes for Aggregated DERs

BOSTON — The NEPOOL Participants Committee on Thursday approved ISO-NE’s proposed tariff changes aimed at allowing distributed energy resource aggregations (DERA) to participate in the RTO’s markets. 

The changes, intended to comply with FERC Order 2222, would create two new market participation models for DERAs and tweak five existing ones. 

The proposal sets a minimum size of 100 kW for DERAs in all of the models and includes an opt-in provision which prohibits aggregation bids from distribution companies below 4 million MWh in annual sales unless the relevant retail regulatory authority signs off.

Participation models for DERAs (NEPOOL) Content.jpgISO-NE’s Order 2222 compliance filing would create two new market participation models for DERAs and tweak five existing ones.  | NEPOOL

It creates a four-stage registration process to allow a distribution utility to confirm the necessary capabilities to participate in a DERA. Other changes would amend Forward Capacity Market rules to allow DERAs to take part. 

The changes to the FCM would go into effect in the fourth quarter of 2022, and the others not until 2026. 

Advanced Energy Economy (AEE), which argued that the proposal fails to remove significant barriers to market participation for DERAs, submitted seven amendments while it was under consideration in the Markets Committee. But those were voted down and the group declined to bring the amendments to a vote again for this week’s PC meeting. (See Stakeholders Approve ISO-NE Order 2222 Compliance Plan)

AEE declined to comment on whether it will  advocate for changes once the proposal is under consideration by FERC. 

ISO-NE has until Feb. 2 to file the proposal. 

Billing, FCM Settlement Changes

The PC also voted Thursday on several other items, including changes to the way ISO-NE handles requests for billing adjustments. The requests will now have to be submitted via the AskISO system, instead of by email, because cybersecurity measures have “in some cases hampered receipt” of the requests, according to the RTO. 

The PC also approved a change to convert certain credits and charges associated with the FCM from a monthly settlement to a daily settlement. The proposal will reduce financial assurance for load serving entities and accelerate payments to resource providers, the RTO said. 

Consent agenda

The committee also approved: 

  • changes to Planning Procedure 10 (Planning Procedure to Support the Forward Capacity Market), including conforming changes for ER21-640, related to qualification of non-commercial resources in annual reconfiguration auctions, and ER19-343, related to the modeling of peaking generation in reliability reviews;
  • changes to Operating Procedure 16K (Transmission System Data – Submission of Short Circuit Data), part of a biennial review with minor updates to process flow diagram; and
  • changes to Operating Procedure 3 (Transmission Outage Scheduling), part of biennial review with minor edits and grammatical revisions.
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Youngkin Taps Trump’s Former EPA Chief to Head Virginia DNR

Andrew Wheeler, the former coal industry lobbyist who led EPA under former President Donald Trump, is now slated to head Virginia’s Department of Natural Resources.

Governor-elect Glenn Youngkin (R) nominated Wheeler to the post Wednesday, setting off a storm of criticism from Virginia Democrats and environmental advocates.

U.S. Rep. Don Beyer (D-Va.) tweeted that “Wheeler is one of the worst people the governor-elect could have chosen for the job.”

“Putting an anti-environment ideologue in this important position would be a far cry from the kind of consensus-based, pragmatic leadership the governor-elect promised,” Beyer said in an attached statement.

“This nomination is extremely disappointing,” seconded Sarah Francisco, director of the Southern Environmental Law Center’s Virginia office. “As a former head of EPA in the Trump administration and former coal industry lobbyist, Mr. Wheeler has a record of weakening fundamental safeguards for clean water and healthy air and opposing common-sense efforts to tackle climate change.”

Youngkin’s announcement of the nomination praised Wheeler’s “extensive experience and passion” and his dedication “to advancing sound environmental policies.”

Gov-elect Glenn Youngkin (Youngkin for Governor) FI.jpgGov.-elect Glenn Youngkin | Youngkin for Governor

Wheeler shares “my vision in finding new ways to innovate and use our natural resources to provide Virginia with a stable, dependable and growing power supply that will meet Virginia’s power demands without passing the costs on to the consumer,” Youngkin said.

Following his victory over Democrat Terry McAuliffe in November, Youngkin named Wheeler as part of his transition team, specifically as part of the Natural and Historic Resources group.

Under Virginia’s constitution, both houses of the General Assembly must confirm Wheeler and other potential cabinet members. While Wheeler may face little opposition in the Republican-led House of Delegates, he could hit a wall in the Senate, where Democrats still hold a 21-19 advantage.

Citing Wheeler’s “well established record from his time in the Trump administration,” Harry Godfrey, executive director of Virginia Advanced Energy Economy, said “it is vital that the Senate consider that record and determine whether it aligns with the policy direction that the General Assembly has established in recent years,” such as the Virginia Clean Economy Act (VCEA).

Sen. Scott Surovell (D) told the Virginia Mercury that while Senate Democrats have not discussed the nomination, “I think a lot of our members are going to have very serious concerns.”

Surovell also cautioned that “any Republican member who’s in any kind of competitive suburban seat would really need to think twice about voting for someone like [Wheeler] given where Virginia’s been leading on environmental policy.”

Wheeler’s nomination could be the first test of the Senate’s ability to push back on Youngkin’s efforts to slow the state’s progress toward the VCEA’s goal of a 100% clean energy supply by 2050. For example, the governor-elect has vowed to take Virginia out of the Regional Greenhouse Gas Initiative (RGGI) via an executive order. The initiative is a multistate carbon market aimed at cutting greenhouse gas emissions across 11 New England and Mid-Atlantic states.

A General Assembly vote approved the state’s membership in RGGI; any move by Youngkin to rescind that approval by executive order could also spark opposition. Similarly, the Senate is seen as a firewall to forestall any attempt to repeal the VCEA.

Wheeler’s Record

Wheeler’s environmental record goes back to his work as chief counsel for Sen. Jim Inhofe (R-Okla.), an outspoken climate change denier, from 1995 to 1997. He also worked a lobbyist for the coal industry from 2009 to 2017 at the law firm of Faegre Baker Daniels (now Faegre Drinker Biddle & Reath).

In 2018, when he was the EPA’s acting administrator, Wheeler drew criticism for discounting the findings of the National Climate Assessment, begun during the Obama administration, claiming the report “pushed” a worst-case scenario. During his confirmation hearings to be the official administrator in 2019, he skirted repeated questions from Democratic senators on his views on climate change.

When pressed by Sen. Bernie Sanders (I-Vt.), Wheeler called climate change “a global issue that must be addressed globally,” but not “the greatest crisis. … I consider it a huge issue that has to be addressed globally.” (See Dems Press Wheeler on Climate at Confirmation Hearing.)

Once confirmed, Wheeler weakened or rolled back a number of former President Barack Obama’s key environmental initiatives, such as the Clean Power Plan, aimed at reducing carbon emissions from power plants, and regulations requiring coal plants to clean up coal ash ponds. Working with the Department of Transportation, Wheeler’s EPA in 2020 also froze fuel efficiency standards to a fleet average of 32 mpg by 2026.

Current EPA Administrator Michael Regan recently issued new rules, resetting the target for 40 mpg by 2026. (See EPA Rules Will Slash Emissions, Rev up EV Market by 2026.)

‘Not the Right Fit for Virginia’

The Virginia chapter of the Sierra Club called on Youngkin to withdraw the nomination.

The “reckless” nomination “is proof that Youngkin is willing to sell out our communities and our clean air and water for corporate profits,” said Kate West, chapter head. “In lieu of withdrawal, Democrats must use their [Senate] majority to prevent one of the most dangerous appointments in our state’s history.”

Del. Dan Helmer (D) tweeted that Wheeler’s record at EPA is “disqualifying,” vowing to “fight this nomination tooth and nail.”

“Anyone with [Wheeler’s] record is simply not the right fit for Virginia,” said Kim Jemaine, Virginia director of the Chesapeake Climate Action Network Action Fund. “During his extensive career as a henchman for the coal industry and the Trump administration, Wheeler has made it clear that he is willing to risk the health and safety of Virginians in order to serve the interests of bad actors. We should take this record at face value.”

Youngkin’s nomination of Michael Rolband to head the Department of Environmental Quality, on the other hand, went without comment. Rolband appears to have a long history as an advocate for wetlands preservation and restoration. He founded Wetlands Studies and Solutions, an environmental and cultural resources analysis firm, as well as the Resources Protection Group, a wetlands conservation nonprofit.

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Dixie Fire Finding Inopportune for PG&E

The finding by state investigators this week that a Pacific Gas and Electric line sparked last year’s immense Dixie Fire arrived at an awkward time for the beleaguered utility, which is hoping to be released from five years of federal probation later this month.

The California Department of Forestry and Fire Protection said Tuesday its investigation had found that a tree falling onto a PG&E distribution line ignited the nearly 1-million-acre wildfire, the second largest in state history, which destroyed more than 1,300 structures and killed one person.  

“The Dixie Fire investigative report has been forwarded to the Butte County District Attorney’s Office” for possible criminal prosecution, Cal Fire said in a news release.

The finding was not a surprise. PG&E said soon after the fire began in mid-July that its line may have sparked the fire that burned for more than three months across the northern Sierra Nevada. (See PG&E Expects $1B in Costs from Dixie Fire.)

“As we shared in our public statement in Chico in July after the start of the Dixie Fire, a large tree struck one of our normally operating lines,” PG&E said Tuesday. “This tree was one of more than 8 million trees within strike distance to PG&E lines.”

Cal Fire rendered its conclusion one day after federal Judge William Alsup said in a hearing that he would consider extending PG&E’s probation beyond its current end date of Jan. 25 if federal prosecutors ask him to. The U.S. Attorney’s Office is expected to decide this week whether to file such a request, and Alsup scheduled a hearing on the matter for Monday.

Cal Fire’s findings regarding the Dixie Fire could weigh into a decision by the judge, who has been one of PG&E’s harshest critics.

In November, Alsup found that PG&E had likely violated its probation for felonies related to the 2010 San Bruno gas explosion by starting the 2019 Kincade Fire and the 2020 Zogg Fire. Cal Fire determined a tree that fell on a PG&E line started the Zogg Fire. The cause of the Kincade Fire remains under investigation. (See PG&E Likely Violated Probation, Judge Finds.)

County prosecutors have filed charges against PG&E in both cases, while the utility has denied it was criminally liable for either fire.

Also in November, the independent monitor appointed by the court to oversee PG&E during its probation said the utility needs to make substantial improvements in its efforts to prevent wildfires through vegetation management and grid hardening.

“Multiple years of horrific wildfires” started by PG&E equipment showed “its progress regarding wildfire mitigation obviously has been inadequate, and we doubt anyone would seriously dispute that, given the ongoing and profound safety issues in that area of operations,” the law firm Kirkland & Ellis, which the court appointed monitor, wrote in its report to Alsup.  

Fires started by PG&E equipment that failed or was struck by trees included the 2018 Camp Fire, which destroyed the town of Paradise and killed at least 84 people.

“Including the Camp Fire fatalities, over 110 people have died as a result of wildfires where CAL FIRE has determined PG&E equipment was involved since the San Bruno incident,” the monitor wrote.

Its reviews of PG&E safety practices showed the utility had missed thousands of dangerous trees near its lines and failed to detect worn or broken equipment. PG&E still has a vast backlog of problems to fix from a 2019 inspection of 685,000 distribution poles, 50,000 transmission structures and 200 substations in high-fire threat districts, the monitor noted.

“There are over 500,000 tags from 2019 to present that remain unresolved to date,” it said.

The monitor also expressed skepticism about PG&E’s plans to bury 10,000 acres of power lines in fire-prone areas. CEO Patti Poppe announced the effort in July during the same media event in which she discussed the utility’s possible role in starting the Dixie Fire. (See PG&E Proposes Undergrounding 10K Miles of Distribution.)

“The Monitor team applauds PG&E’s commitment to undergrounding to mitigate wildfire risk but notes that some serious questions and issues remain regarding PG&E’s implementation of the undergrounding initiative,” it said.

The utility did not give a timeframe for the work but has plans to underground just 66 miles of lines in 2021 and a total of 327 miles over the next three years, the monitor said.

Even if greatly increases its efforts over a 20-year period, “there is substantial skepticism among PG&E field personnel that PG&E can feasibly underground more than 500 miles per year using current technology and hardening methodologies,” the monitor said.

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FERC Accepts ISO-NE Request to Terminate Killingly CSO

FERC on Monday accepted ISO-NE’s request to yank the capacity supply obligation for the Killingly Energy Center in eastern Connecticut, dealing another near-fatal blow to the contentious 650-MW natural gas plant under development (ER22-355).

The RTO has said that Killingly, which secured a CSO for the 2022/2023 capacity period, has failed to meet developmental milestones and is on track to not be in commercial operation by the required date of June 1, 2024, two years after the start of that period. Developers have up to two years to find other resources to meet their CSO obligations if they themselves cannot.

Developer NTE Energy disagreed with ISO-NE’s claims about delays on the project, saying they were out of its control because of factors including legal challenges and the COVID-19 pandemic. The company claimed in November that financing is “imminent” and challenged what it called “an incorrect assumption” by the RTO that led to a “premature” decision. (See ISO-NE Seeks to Terminate CSO for Conn. Power Plant.)

But in an order issued Monday, FERC sided with ISO-NE, saying it was “persuaded by the evidence” presented that Killingly will not achieve critical milestones by 2024. After consulting with NTE, which it did in several meetings over two months, the RTO has the right to terminate the CSO, FERC said.

As a result of FERC’s ruling, the company will lose its CSO, forfeit financial assurance associated with the terminated megawatts and no longer be eligible for the next Forward Capacity Auction in early February.

NTE, Opponents React

NTE says it’s not giving up on the project.

“We are very disappointed and do not agree with FERC’s decision,” the company’s managing director, Tim Eves, said in a statement. “The Killingly Energy Center is important for grid reliability, and we will continue to work to be the bridge for the region’s carbon-free future.”

But the plant’s future is cloudy. The company itself has said in filings that FERC’s approval of ISO-NE decision would cause it “irreparable” damage and lose it hundreds of millions of dollars of revenue.

Environmental groups in Connecticut, which have opposed Killingly and sued over the project in a case that was ultimately decided by the state Supreme Court, celebrated this week at the latest dimming of the project’s future prospects.

“It was the outcome we hoped for, and we’re happy,” said Samantha Dynowski, director of the Connecticut chapter of the Sierra Club.

She said the plant ever being built appears “very unlikely” without a CSO.

“In the face of [ISO-NE] not wanting them and Gov. [Ned] Lamont saying he doesn’t want the plant … they’d really just be forcing themselves on a market that doesn’t want them here,” Dynowski said.

The order has broader implications for ISO-NE, and the events leading to it should spur action by the RTO, said Dan Dolan, president of the New England Power Generators Association.

“Moving forward, more needs to be done to ensure that new facilities only offer into the market when they are ready to come in on time,” Dolan said in an email to RTO Insider. “Market reforms should include proposals like escalating penalties for delays. This will help make continued improvements to provide reliability value for New England consumers and competitive revenue opportunities to those facilities providing the reliability services.”

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PG&E Building ‘Remote Grids’ in Fire-prone Areas

Pacific Gas and Electric plans to build more standalone “remote grids” in California this year, allowing the utility to remove distribution lines serving small groups of isolated customers as a way to reduce wildfire danger.

After finishing its first remote grid project in Briceburg, Calif., last year, PG&E said it was setting a target of having up to 20 remote grids up and running by the end of this year.

And community choice aggregators are partnering with PG&E on some of the projects. Sonoma Clean Power, which serves Sonoma and Mendocino counties, is hoping to have its first remote grid project completed within a year.

Sonoma Clean Power CEO Geof Syphers said the remote grids could increase the use of clean energy, decrease wildfire risk and reduce costs to electric ratepayers.

“It could be a triple win,” Syphers told NetZero Insider.

Solar, Storage and Backup

PG&E decided to build the Briceburg remote grid after the 2019 Briceburg Fire destroyed a distribution line serving five customers. The power line ran across rugged terrain in a high fire-threat area near Yosemite National Park.

The Briceburg remote grid consists of solar panels, battery storage and backup propane generators. It serves two homes, a visitor center, and telecommunications and transportation facilities.

The remote grid uses ground-mounted and container-mounted solar panels provided by BoxPower, a Grass Valley-based company. The containerized microgrid system may streamline development of future remote grids at similar sites, according to a release.

The remote grid includes a fire suppression system, and PG&E and BoxPower can monitor and control the grid via satellite.

The system is expected to provide up to 89% renewable energy per year.

“This hybrid renewable option reliably powers five customers without the need to rebuild the overhead line, and the remote grid is intended to meet customer needs at lower lifetime costs and a significantly lower risk of fire,” PG&E spokesperson Paul Doherty said in an email.

PG&E said there are hundreds of potential sites for remote grids in its service territory. The company is evaluating high fire-threat areas in El Dorado, Mariposa, Sonoma, Tulare and Tehama counties.

Lessons learned from Briceburg and other early projects will guide PG&E’s remote-grid expansion, the company said.

PG&E plans to provide an update on the remote grid program next month when the company files its 2022 Wildfire Mitigation Plan.

CCA Involvement

Community choice aggregators are helping PG&E with remote grid projects by reaching out to customers who might be good candidates for joining a remote grid.

Syphers at Sonoma Clean Power said the outreach includes a discussion on how to maximize the use of renewable energy. Thus far, one customer has agreed to a 100% renewable system, he said.

The trade-off for 100% renewable is the potential for reduced reliability, Syphers said. But he noted that customers might already be experiencing periods of public safety power shut offs while overhead distribution lines stay in place.

Syphers said a typical remote grid site would include one to three customers at the end of a power line running through a high fire-threat area.

Electric use for a remote grid should be on a residential scale, he said, although some non-residential uses such as agricultural water pumping could be accommodated.

It’s ultimately up to PG&E to decide whether a remote grid makes sense for a particular site, Syphers said. One factor is how the cost of a remote grid compares to the cost of hardening an overhead distribution line in a high fire-threat area, which could involve replacing bare overhead conductor with covered conductor, installing sturdier poles or moving the line underground.

“This is an opportunity to just be smarter about how we’re using ratepayer dollars,” Syphers said.

Sonoma Clean Power’s remote-grid planning also includes a “top-to-bottom” energy-efficiency retrofit.

Syphers said he could envision larger remote grids that include seven to 10 customers, but he noted that all customers must be willing participants.

“It could grow as we learn more,” he said.

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MISO Makes 2nd Plea for Time on ROE Refunds

MISO has made another attempt to coax more time from FERC to calculate refunds to transmission customers over the commission’s ever-changing return on equity percentage.

The RTO has now asked for an extension until May 31 to complete the refunds (EL14-12-004).

The grid operator previously requested a June 30 deadline to determine refund amounts; FERC granted a delay until Feb. 28 from its original Sept. 23, 2021, deadline to calculate the reimbursements. (See MISO, TOs: More Time Needed for ROE Refunds.)

MISO said it has good cause to support a spring deadline, saying the “overall resettlement task remains unchanged” since it first requested an extension. The RTO said it and its transmission owners have completed resettlements from 2013 to 2019, but said the remaining refunds require a more complex calculation that relies on forward-looking transmission rates and true-up mechanisms.

The grid operator said it expects to crunch numbers through April, with transactions to take place in May. MISO Senior Manager of Transmission Settlements Christina Drake said it remains “infeasible to implement all of the directed refunds within the timeframe set forth by the commission’s orders.” It promised the refunds will include interest at FERC-approved rates.

MISO said as an example, 2020’s refunds involve 103 transmission owners and “all charges made under related tariff schedules and attachments that use those parties’ ROE, including the systemwide average rate for through-and-out service.”

The RTO’s extensive refund calculations stem from a return on equity that FERC changed several times over a handful of years as it tried to nail down an appropriate baseline for investors backing transmission projects.

The commission in 2020 enacted a 10.02% ROE for transmission rates effective Sept. 28, 2016, superseding the 9.88% and 10.32% ROEs approved in 2019 and 2016, respectively. Those figures were at different times intended to replace the 12.38% ROE established in 2002, which FERC deemed excessive almost a decade ago. In all, MISO TOs must pay refunds for the period of November 2013 to February 2015 and September 28, 2016, to December 23, 2020. (See FERC Ups MISO TO ROE, Reverses Stance on Models.)

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CAISO Working Groups Start EDAM Design

Three stakeholder working groups charged with designing key elements of CAISO’s proposed day-ahead market for the West began work this week and plan to meet twice weekly until mid-March to finish the job.

The groups’ intensive schedules reflect the importance of the extended day-ahead market (EDAM) in CAISO’s bid to broaden its Western Energy Imbalance Market (WEIM) from a real-time to a day-ahead market in the next two years.

The working groups must address some of the thorniest issues that could threaten EDAM’s viability, including resource sufficiency evaluations, transmission commitments and greenhouse gas (GHG) compliance, all of which could provoke dissent among would-be participants.  

Previous stakeholder complaints about transmission rights and other matters, along with the energy emergencies that CAISO faced in summer 2020, put the EDAM initiative on hold until last fall, when the ISO revived it. (See CAISO Reconvenes EDAM Stakeholder Meetings and EDAM Design Could Undermine Tx Rights, Critics Say.)

Composed of WEIM member representatives, the working groups are starting with a broad set of design principles developed last year by a select group of stakeholders. Group members can accept or rework the design principles; they also must try to agree on more detailed design elements.

“A lot of the opportunity that exists here is that there aren’t any hard-and-fast rules other than the principles, which are subject to reevaluation as well. Nobody is stuck in any deep details,” Kevin Smith, a lawyer representing the Balancing Authority of Northern California, said in Monday’s first meeting of working group 1 on supply commitment and resource sufficiency evaluation (RSE).

RSE became a controversial issue in the WEIM when CAISO updated it last year to include measures dealing with the uncertainty of weather-dependent renewable resources, transmission outages and other variables. Some contended the “uncertainty” components of the RSE skewed test results and led to failures.

Participants also raised concerns around demand response resources, capacity counting rules and consideration of load conformance. (See CAISO Reevaluating WEIM Resource Sufficiency Test.)

The resource sufficiency test is meant to ensure that each WEIM participant has enough capacity and ramping capability to supply its own needs and to prevent participants from “leaning” on the market to meet internal demand.

The RSE for WEIM’s well-established real-time market is being reexamined in a stakeholder initiative, while the working group must wrestle with resource sufficiency in the proposed day-ahead market.

“Consistent with the ‘prevention-of-leaning’ concept supported by the existing EIM resource sufficiency test, the EDAM would have robust resource sufficiency requirements,” the common design principles say. “This test would be developed and applicable to all participating entities in order to qualify for EDAM market participation each day.”

The initial list of questions for working group 1 include, “What resources qualify for showing within the EDAM RSE?” and “What is the expected granularity and detail of the EDAM RSE?”

The second working group, which held its initial meeting Tuesday, is addressing transmission commitment and congestion rent allocation. Its common design elements include maximizing the amount of firm or high-priority transmission available to EDAM while respecting open-access transmission principles.

The group is being asked to “define how transmission across EDAM entity network is made available, including consideration of any restrictions or limitations,” and to consider the timing and duration that transmission is made available, among other topics.

Working group 3, which also met for the first time Tuesday, is weighing questions around greenhouse gas accounting, including whether state boundaries will form GHG “compliance areas” and how GHG compliance costs will be recovered.

Group 3 plans to meet every Tuesday and Thursday afternoon through mid-March. Working group 1 will meet on Monday and Wednesday afternoons during the same period; working group 2 is scheduled to meet on Tuesday and Thursday mornings until March 16.

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FERC Approves $40K Penalty for Santee Cooper

FERC on Dec. 30 approved a settlement between South Carolina Public Service Authority (Santee Cooper) and SERC Reliability under which the state-owned utility will have to pay $40,000 for violations of NERC reliability standards.

NERC submitted the settlement to the commission at the end of November in a spreadsheet Notice of Penalty, along with settlements between SERC and Louisville Gas & Electric, and between ReliabilityFirst and CenterPoint Energy (NP22-6). The latter settlements did not carry any monetary penalties.

FERC indicated last week that it would not review the agreements — in addition to separate NOPs concerning settlements between RF and American Electric Power, and between WECC and NaturEner Wind Watch — leaving the penalties intact. (See AEP to Pay $570K in NERC Penalties.)

Santee Cooper’s settlement concerns FAC-009-1 (Establish and communicate facility ratings), specifically requirement R1, which states that transmission owners and generator owners must “establish facility ratings for [their] solely and jointly owned facilities that are consistent with the associated facility ratings methodology.” The utility self-reported in 2018 that it had violated the standard; SERC later determined that the infringement also involved requirement R6 of FAC-008-3 (Facility ratings), which superseded the earlier standard in 2012.

During a review of facility ratings prior to a SERC audit, Santee Cooper “discovered four instances of incorrect element ratings at one substation”; as a result the utility’s facility ratings did not match its methodology. Correcting the element ratings led to three facility rating increases and one decrease. As part of the audit, SERC later conducted a walk-down of the substation and found seven additional incorrect element ratings, though these did not affect the facility rating.

An extent-of-condition review and walk-down of all of Santee Cooper’s generation and transmission facilities after the audit revealed incorrect facility ratings at 18 of 319 transmission facilities (including the one that the utility discovered before the audit). Misratings were also found at nine of Santee Cooper’s generating units.

Santee Cooper found that the oldest incorrect facility rating dated to June 2007, when FAC-009-1 took effect. The utility finished revising all incorrect element and facility ratings by March 18, 2021.

SERC determined that the root causes of the violations were “deficient procedure at [Santee Cooper’s] generating facilities and inadequate training at its transmission facilities.” In the case of the generating facilities, the procedure did not identify “specific instances where [Santee Cooper] should use a calculation instead of manufacturer nameplate values or when multiple elements could be considered in a single rating.” Business units associated with the transmission facilities were not aware of the utility’s process for communicating changes to the transmission system.

In addition to correcting the element and facility ratings, Santee Cooper conducted several mitigating actions. First, it gave the transmission project management and area engineering business units more visibility into the facility rating process by adding their representatives to the model validation and dynamics review team; now the team “includes representation from all areas that have a key role in the facility ratings process.” The utility also established a team focused on minimizing data discrepancies between database and field assets, comprising representatives from multiple departments.

In addition, Santee Cooper undertook a standardization of database and field assets and equipment inputs, along with an annual internal control targeted at validating at least 20% of its transmission facilities every calendar year. Moreover, the entity revised its generation facility ratings methodology to “provide clarity” on such factors as the use of nameplate ratings rather than calculations and how to evaluate generator step-up transformers.

SERC also applied mitigating credit for Santee Cooper’s internal compliance program, which it said “includes strong oversight and an ongoing internal control to walk down 20% of its facilities every year.” The regional entity found no previous instances of noncompliance to warrant aggravating the penalty.

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Solar Developer Objects to New York DEC Analysis

A NextEra Energy (NYSE:NEE) subsidiary developing a 180-MW solar project in upstate New York since 2017 is urging the state’s Siting Board to reject as “faulty” the Department of Environmental Conservation’s project description and analysis, especially on wetlands classification and mitigation (Case No. 17-F-0598).

In a December rebuttal to DEC staff testimony the previous month, North Side Energy Center said it was illogical for the department to classify the project as an industrial-use facility and thus render it incompatible with state wetlands regulations.

North Side said the term “industrial use facility” dates from 1985 and is associated with impacts from constructing buildings, accessory roads and parking areas that can impede rainwater absorption and roil streamflow, in turn creating more erosion and sedimentation.

“Here, solar technology for the project was selected to avoid concrete foundations. There will be no buildings. Panels will be mounted on racking systems supported by driven posts, resulting in minimal ground disturbance,” said North Side, a wholly owned, indirect subsidiary of NextEra Energy Resources, itself a subsidiary of NextEra.

Access roads for the 2,200-acre project, sited a few miles from the Canadian border, will not be paved entirely, but virtually all of the roads will be gravel, allowing rain to soak into the ground. Therefore, North Side argued, the project will not create the kind of impact imagined when industrial-use facilities were included in state regulations.

The Siting Board will rule in July on the project’s application for a certificate of public convenience and necessity. Meanwhile, three administrative law judges have established a procedural timeline, with a status conference this Friday followed by a Jan. 14 deadline for submission of exhibit list; witness list and testifying order; contested issues; and areas for cross examination.

An evidentiary hearing will be held Jan. 24, with post-hearing briefs due Feb. 28 and reply briefs on March 15.

Evaluation Crosstalk

DEC biologist Christopher Balk testified in November that department staff calculated that the project, as currently proposed, will result in direct impacts to 621 acres of protected wetlands and 136 acres of adjacent areas.

Asked if DEC staff were commenting on the applicant’s system energy efficiency plan (SEEP) guide as it related to wetlands and waterbodies, Balk said, “No, department staff’s proposed certificate conditions differ from the applicant’s in such a manner that review of the SEEP guide as it relates to wetlands and waterbodies would not result in any meaningful comments from staff.”

North Side argues that DEC staff assume that the entire area under the panels — which it says will be reseeded and restored and which the record shows will improve functions to previously disturbed wetlands — should be treated as an avoidable adverse impact and thus requires mitigation.

The “regulation [that the department] asks the Siting Board to exert over non-mapped wetlands is unprecedented, limitless, prejudicial and groundless. By adopting this ad hoc, unlawful approach to wetland regulation, developers will not be able to rely upon existing law and regulations for fear that the DEC staff will go beyond it,” North Side said.

DEC staff recommend approximately 1,100 acres of wetlands be created or restored to serve as mitigation, which North Side said would make the project unfinanceable. The market rate from a least one organization that creates wetland mitigation (Ducks Unlimited) is approximately $100,000/acre, the developer said.

By that estimate, DEC staff’s recommendation would mean a wetland mitigation cost of approximately $110 million for a solar project for which the capital cost is approximately $300 million.

Alternatively, DEC staff argue that the Siting Board amend the official wetland maps and treat the non-mapped wetlands as Class I, which would prohibit any facilities from being located there.

“As the applicant has no alternative site, that DEC strategy would also kill the project,” North Side said.

It also noted that a preliminary jurisdictional determination issued in October by the U.S. Army Corps of Engineers (USACE) said it will exert jurisdiction over those non-mapped wetlands, so the company would not seek a permit from it.

A crucial difference between the corps’ requirements and the DEC staff position in this case is that USACE requires compensatory mitigation only for permanent jurisdictional wetland losses resulting from the placement of fill for activities such as grading, the construction of access roads and placement of concrete pads, North Side said.

“The USACE does not recognize the installation of driven piles (such as the solar array posts) into wetlands as fill and therefore the placement of the solar racking system and the panels themselves would not require mitigation, as the action would be non-jurisdictional to USACE,” North Side said.

Compatibility Tests

A project in New York must pass three compatibility tests in order to be permitted:

  • would be compatible with preservation, protection and conservation of the wetland and its benefits;
  • would result in no more than insubstantial degradation to, or loss of, any part of the wetland; and
  • would be compatible with the public health and welfare.

North Side argues that the project meets all three tests. It says most of the proposed impacts are in the form of conversion, which typically constitutes conversion of land cover through clearing of non-aquatic vegetation associated with panel installation to eliminate the potential of shading effects caused by vegetation. In addition, the discontinuance of agricultural activity will improve wetlands in areas used for row and field crops, the company said.

The project meets the second test because placing solar posts, access roads and inverter and substation pads do not amount substantial degradation of the land, the developer said. It also said it is ready to comply with USACE mitigation requirements, which it estimates would amount to approximately 15 acres of wetland mitigation.

Finally, North Side said the project meets the third test because no significant adverse impact on the environment, public health and safety were determined through the many studies it performed to prepare the application.