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October 3, 2024

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Stakeholders Call for MISO to Rethink Pared-down Meeting Schedule

[EDITOR’S NOTE: The headline for this story previously implied that MISO itself desired a change in the meeting schedule.]

Weeks into its new scaled-back stakeholder meeting schedule, MISO will re-examine its effectiveness by holding a stakeholder workshop later this month.

The Feb. 22 workshop on MISO’s stakeholder process and engagement comes as several committee chairs have spoken out against the new schedule.

“I hear your concerns. I am taking notes,” Bob Kuzman, the RTO’s head of stakeholder relations, said during a Wednesday Advisory Committee teleconference. “We understand there are hiccups, and there are going to be more hiccups.”

Kuzman said he was collecting opinions during the meeting to take back to MISO leadership.

The grid operator announced late last year a reduced meeting schedule consisting of eight meetings apiece per year for its main stakeholder committees. The committees include the Market Subcommittee, Resource Adequacy Subcommittee, Reliability Subcommittee, Planning Advisory Committee and Regional Expansion Criteria and Benefits Working Group, which makes cost-allocation decisions. (See MISO Modifies Stakeholder Meeting Schedule.)

Client relations staff framed the new meeting schedule as giving its subject-matter experts a meaningful pause between meetings in the transition to in-person meetings after two years of pandemic-induced isolation. The RTO eventually committed to only scheduling meetings through May and held its first series of face-to-face meetings last month. (See MISO Hosts First In-person Meetings amid Pandemic.)

Clean Grid Alliance’s Natalie McIntire suggested MISO use the February workshop to work together with stakeholders, rather than to impose changes.

“This really needs to shift to a collaborative effort with stakeholders instead of dictating changes, hearing complaints and then making adjustments,” she said.

“Stakeholders feel much better when they’re involved in the decision-making process,” Resource Adequacy Subcommittee Chair Chris Plante agreed.

“There are concerns about how the stakeholder process is evolving,” Market Subcommittee Chair Megan Wisersky said. “MISO now controls the stakeholder process without stakeholder discussion or consent. … The concern is the stakeholder process no longer belongs to the stakeholders.”

Wisersky said the lighter meeting frequency has nudged some agenda items into a “post-only” format, where information is posted on the MISO website but not discussed with stakeholders.

Multiple stakeholders also cast doubt that the RTO can accomplish its 2022 goals — finalizing participation models for storage and distributed resources; establishing dynamic line ratings; recommending long-range transmission projects; and possibly creating a seasonal capacity auction — with fewer meetings.

Planning Advisory Committee Chair Cynthia Crane said she noticed that meetings are shorter and “cursory,” with staff making fewer feedback requests of its stakeholders.

“I would encourage MISO to act very swiftly in making improvements,” she said.

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Industry Welcomes DOE’s Better Grid Initiative

The Department of Energy’s Building a Better Grid initiative has been warmly received by those within the industry who see prioritizing national transmission solutions as integral to adding more renewable resources to the grid.

They include Phillip Moeller, executive vice president at Edison Electric Institute, which represents investor-owned utilities.

“Transmission is going to be the key to unlocking those resources that are cleaner but generally far, far away from where the load centers are,” he said during a recent United States Energy Association virtual webinar on the DOE program. “We’re encouraged that there’s more talk about transmission in Washington, with the bipartisan infrastructure bill … not only setting the policies in place that will allow for better planning and ideally more construction, but also figuring out the economic side and giving some clarity to the return on these investments.”

Under Building a Better Grid, DOE will work to identify high-priority national transmission solutions capable of relieving congestion and accommodating more clean-energy resources. The department launched the program last month following the enactment of the Infrastructure Investment and Jobs Act that contained billions of dollars for grid infrastructure and expanded federal siting authorities. (See DOE to Tackle Tx Siting, Financing, Permitting in Better Grid Initiative.)

The department says the nation’s grid will need to expand by 60% by 2030 and by three times its size by 2050, if President Biden’s goals of a decarbonized grid by 2035 and a net-zero economy by 2050 are to be met. It says large renewable projects in remote areas and offshore wind will need high-voltage transmission lines to efficiently bring power to urban demand centers.

However, DOE has determined about 70% of the nation’s existing transmission lines and transformers are more than 25 years old. According to a 2021 study from the Lawrence Berkeley National Laboratory, more than 750 GW of solar and wind and 200 GW of storage were backed up in grid operators’ interconnection queues at the end of 2020.

Tri-State Generation and Transmission Association CEO Duane Highley, speaking on the same panel with Moeller, said his organization is looking forward to working with DOE. Calling his cooperative a “poorly named company” because it serves four states in its 200,000-square-mile footprint through its member systems, Highley said “transmission is extremely important for us as we’re making our energy transition.”

Based in Colorado, Tri-State intends to meet the state’s 80% decarbonization mandate by 2030.

“In order to do that, many gigawatts of wind and solar have to be moving across time zones in order to balance everything else,” Highley said.

Fortunately for Tri-State, it’s a member of SPP in the Eastern Interconnection, and it has plans to also join SPP’s Western expansion, RTO West. The grid operator has facilitated the construction of more than $10 billion of new infrastructure, much of it to interconnect wind farms on the plains of Nebraska, Kansas and Oklahoma.

SPP COO Lanny Nickell joined Highley on the panel to share the RTO’s experiences that he thought would be helpful to DOE’s initiative. He said the RTO owes much of its success to an agreement reached more than 10 years ago with its footprint’s state regulators to share transmission upgrade costs.

The result? Nickell said wind generation has grown from providing 6% of SPP’s annual energy needs to now providing 35% on an annual basis, helping reduce carbon dioxide emissions by more than 29% over the last seven years. He referenced a transmission-value study that indicates new transmission installed since 2015 has provided $5.24 of benefits for every $1 invested. (See “JTIQ, Tx Value Staff Reports,” SPP Markets and Operations Policy Committee Briefs: Jan. 10-11, 2022.)

Nickell said SPP relied on the transmission infrastructure to import up to 14% of its energy during last February’s severe winter storm.

“Our situation would have been much more catastrophic had it not been for the strength of our system and our connections with neighboring systems,” he said. “Extreme weather events are happening much more frequently, and a more resilient system is going to be needed to prepare for future events. Utilities and developers continue to request more renewable resources to add to their portfolios. More transmission is needed to meet these goals reliably and affordably.”

That includes more DC ties between the Eastern and Western Interconnections. Seven of the eight back-to-back DC ties in the U.S. and Canada link SPP with the Western Interconnection, but they only provide 1,320 MW of capacity.

Nickell used an analogy of two neighboring swimming pools linked by a common garden hose to highlight the ties’ limitations.

“Very limited, basic capacity. They’re garden hoses. They’re small,” he said. “That’s what limits us from really obtaining the value and the benefit [of interconnections]. That’s what needs to be considered in terms of really unlocking the system’s value.”

“The need to tie the grid together east to west is directly tied to the DOE proposal because you get a federal entity that could study and bring together private companies to help build and construct this network,” Highley said. “What we really need is to move that solar east and west across time zones. [Building a Better Grid] is going to resolve a lot of our issues with integrating renewables into the grid.”

Asked where new east-west transmission should be built, Nickell said SPP has yet to conduct studies for that but said he would definitely like to see more infrastructure along the Eastern Interconnection’s western footprint.

“We’ve been referred to as the Saudi Arabia of wind. We’ve got a lot of wind potential that we could deliver both east and west,” he said. “A lot of the solar potential, though, exists in the West. Wouldn’t it be great if we could swap those out? We can benefit from solar when the wind’s not blowing and from wind when the sun’s not shining.”

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Maine Roadmap Shows Gap in Public EV Infrastructure Funding

Maine’s recently released Clean Transportation Roadmap shows the state needs to identify significant near-term funding sources for public charging to support electric vehicle adoption.

“There is a gap as we get out to 2024-2025 and the [estimated] number of EVs gets larger,” Geoff Morrison, senior associate with The Cadmus Group, told the Maine Climate Council on Wednesday.

The roadmap, which Cadmus prepared for the state, recommended that Maine adopt California’s Advanced Clean Cars II (ACC II) and invest in 1,400 public Level-2 and DC fast charger plugs by 2025 to support EV growth from that policy.

With an average DCFC plug cost of between $138,000 and $363,000, Morrison said the chargers are expensive and the economics of installing and maintaining them are challenging. Even with high utilization rates, DCFC units would be unprofitable through 2030, according to the roadmap.

“There’s not a great reason to build them right now if there’s no public incentive,” Morrison said.

ACC II would push the total estimated light-duty EVs in the state to between 120,000 and 160,000 by 2030, according to the roadmap. The California Air Resources Board expects to release a rulemaking for ACC II in June, with the regulation taking effect for model year 2026. (See CARB Preparing Full Course of ZEV Rules for 2022.)

Building the public chargers needed for ACC II growth would require an estimated $71 million investment based on roadmap estimates. DCFC chargers would represent the bulk of that investment at $50.3 million.

However, Maine has only $27 million available for EV infrastructure investments over the next four years, leaving a $44 million gap. Available funding includes $8 million from the Maine Jobs and Recovery Plan and $19 million from the federal Infrastructure Investment and Jobs Act (IIJA). The state could narrow the funding gap with potential IIJA competitive grants, which the roadmap estimated would be about $10 million for Maine.

Additional market incentives beyond ACC II are necessary to meet the Maine Climate Council’s call for 219,000 light-duty EVs by 2030. Growing the DCFC network by 15% in 2030 could increase EV sales by 7% for the year, the roadmap said.

New charging infrastructure funding sources identified in the roadmap include a clean fuel standard, vehicle-miles-traveled (VMT) tax, gas tax and carbon mechanism.

Other states are considering or already testing an EV road tax or VMT tax for all passenger vehicles to supplement declines in gas tax revenues that pay for road upkeep. EV users are not assessed a charge in Maine to pay for infrastructure maintenance, according to Joyce Taylor, chief engineer at the Maine Department of Transportation.

The DOT has looked at the issue of declining gas taxes, but EV adoption has not been high enough in the state to warrant solving the problem right now, Taylor said.

A decline in gas taxes from EV adoption is a “national issue that has to be solved nationally, not just state by state,” she said.

An early study of a VMT tax in Maine showed the difficulty of sorting out the capture and allocation of taxes from out-of-state drivers, which is partly why a national solution is necessary, she said.

In a recent study, the Vermont Agency of Transportation estimated that Vermont will lose $5.3 million in gas tax revenues in 2025 from EV market expansion. That study examined the possibility of assessing a per-kilowatt-hour fee for out-of-state drivers when they use charging stations in the state. VTrans determined that a program of that kind, while helpful, would come with administrative difficulties. (See Study: EV Adoption to Cut $5.3M in Vt. Gas Taxes in 2025.)

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Environmental Groups Appeal SEEM in DC Circuit

Continuing their bid to block the Southeast Energy Exchange Market (SEEM), a collection of environmental, clean energy and community groups filed an appeal of FERC’s decision to approve the market with the D.C. Circuit Court of Appeals on Tuesday.

The Southern Environmental Law Center (SELC) filed the appeal on behalf of the Sierra Club, the Southern Alliance for Clean Energy, the North Carolina Sustainable Energy Association, and others. Advanced Energy Economy, Clean Energy Buyers Association, Solar Energy Industries Association, and the Natural Resources Defense Council joined as well. The plaintiffs hope to persuade the court to set aside FERC’s approval of the market from October, along with subsequent orders stemming from the commission’s decision (ER21-1111, et al.).

AEE General Counsel Jeff Dennis said in a statement that the SEEM agreement “threatens to erode foundational principles of open access to the transmission system that have been in place for decades, and to cement monopoly control of generation markets in the [Southeast].” He called for the market to be revised “to ensure fair competition among generating resources and open access to the transmission system in the region.”

SEEM’s sponsors — a group of utilities including Southern Co. (NYSE:SO), Dominion Energy South Carolina (NYSE:D), LG&E and KU (NYSE:PPL), the Tennessee Valley Authority and Duke Energy (NYSE:DUK) — proposed the market last year, saying that the expansion of bilateral trading would reduce trading friction while promoting the integration of renewable resources. But the proposal attracted considerable opposition from environmental groups, including many of the plaintiffs in Tuesday’s appeal.

The SEEM agreement took effect Oct. 12, after FERC — at the time short a commissioner and evenly split with two Republicans and two Democrats — failed to form a majority for or against it. Under Section 205 of the Federal Power Act, the agreement became effective “by operation of law.” (See SEEM to Move Ahead, Minus FERC Approval.)

The FPA allows any parties “aggrieved” by a FERC order to apply for rehearing within 30 days of its issuance, and because FERC did not issue a formal order in the proceeding, SELC and other opponents filed rehearing requests Nov. 12 — 30 days after Oct. 13, the date FERC announced that the agreement had taken effect. But FERC denied these requests, reasoning that Oct. 11 was the deadline for the commission to issue an order and therefore the beginning of the clock for filing rehearing requests. As a result, any requests filed after Nov. 10 were out of time. (See FERC Rejects SEEM Opponents’ Rehearing Requests.)

The SEEM opponents responded by asking for a rehearing of this decision as well, which FERC again denied. In their filing Tuesday, the plaintiffs called for the court to overturn all three decisions, in addition to:

  • FERC’s order of Nov. 8 approving revisions to four of the SEEM utilities’ tariffs implementing the special transmission service used to deliver the market’s energy transactions (See FERC Accepts Key Tariff Revisions to SEEM.).
  • The commission’s rejection of plaintiffs’ rehearing request for this order.

“This case is about the fundamental principle of open access and the commission’s obligation to enforce that principle to protect market participants and consumers,” SELC Staff Attorney Maia Hutt said in a separate statement. “Should SEEM be allowed to move forward, it must include open-access to transmission and accountability mechanisms that ensure that SEEM does not benefit utilities at the expense of customers.”

In an email to RTO Insider, a spokesperson for Southern said SEEM members would “provide the court the information necessary regarding the FERC proceedings and the benefits of SEEM for our customers.”

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MISO Planning Subcommittee Briefs: Feb. 8, 2022

MISO has formed a special task team to explore rerouting transmission flows during heavy congestion periods.

The Reconfiguration for Congestion Cost Task Team’s meetings are being held behind closed doors, as transmission reconfiguration discussions contain confidential and market-sensitive information.

Speaking during Tuesday’s Planning Subcommittee meeting, Chair Ray McCausland said the group will review past real-world examples of the system’s congestion, necessitating privacy. The group first met in January and will meet again Feb. 17.

The team reports to the Reliable Operations Working Group, which also holds non-public meetings.

MISO’s Independent Market Monitor has recommended members use reconfiguration plans along with ambient adjusted transmission ratings to ease constraints. The Monitor reported that the RTO’s real-time congestion costs more than doubled from late 2020 to late 2021 as more transmission elements began binding year-over-year. Record wind output and high natural gas prices increased the cost of re-dispatching the system to manage constraints, the IMM said.

MISO Ponders Generation as Non-Tx Alternatives 

MISO is considering opportunities to convert retired generators to synchronous condensers and serve as non-transmission alternatives.

Some stakeholders have said the grid operator’s increased reliance on renewables may force preserving some generators so they can provide inverter services.  

Staff’s Jeanna Furnish said generation assets served as temporary solutions in other RTOs while long-term transmission solutions were built.

Generation owners interested in making the conversion would need to be evaluated under MISO’s annual transmission expansion planning process’ (MTEP) transmission alternatives selection process.

Furnish said staff also believes its existing Tariff Attachment Y process can help govern decisions on converting retiring generators to into synchronous condensers. Under Attachment Y, the RTO analyzes whether a retiring generator must keep operating under a system support resource agreement for reliability reasons.

Furnish said MISO must still develop written agreements, operating procedures, and compensation for generators.

MISO Debuts ’22 Cost Estimates

MISO also introduced its 2022 draft cost estimates for transmission structures, substation equipment construction, and other elements.

The MTEP 22 cost-estimation guide contains updates that reflect higher prices of materials. The RTO has also added costs for aluminum conductor composite core and 765-kV transmission that is interchangeable to about 640 kV.

The grid operator uses the guide to evaluate transmission alternatives in its annual system planning work. Stakeholders have until March 11 to review the draft and submit revisions.

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ISO-NE Asks FERC to Expedite Killingly Rehearing Decision

New England is still awaiting results of Monday’s capacity auction, and the wait could go on longer than usual as ISO-NE has to wait for federal action to announce them (ER22-355-001).

The grid operator on Wednesday asked FERC to take expedited action on a rehearing request from NTE Energy in regards to the Killingly Energy Center. A court ruling on Friday ordering ISO-NE to allow the under-development Connecticut gas-fired power plant into Forward Capacity Auction 16 has added a large amount of uncertainty to the process.

The RTO moved to terminate Killingly’s capacity supply obligation in November, a decision that was upheld by FERC in January. But the D.C. Circuit Court of Appeals ruled that FERC must answer NTE’s request for rehearing before the termination can be enforced. (See Killingly Stays Alive After DC Circuit Halts FERC’s Termination Order.)

“Expedited action is necessary so that ISO-NE may provide to New England stakeholders and file with the commission the results of Forward Capacity Auction 16,” the RTO said in a filing to FERC on Tuesday. “Prompt resolution of the continuing uncertainty regarding the status of Killingly will also enable the ISO and market participants to conduct qualification activities related to FCA 17, which is scheduled to be conducted in February 2023.”

The RTO asked FERC to issue an order responding to NTE’s rehearing request by Thursday.

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FERC Rejects PJM Redefinition of ‘Designated Entity’ Under Order 1000

FERC on Tuesday rejected a filing by PJM in its Order 1000 compliance docket that would have updated the definition of “designated entity,” agreeing with a coalition of stakeholders that it infringed on their due process rights (ER13-198-008).

The commission not only disagreed with the RTO’s arguments for why the update was necessary; it also said that “PJM improperly filed revisions to its Operating Agreement as a compliance filing in response to an order that was final and required no compliance.”

In its September filing, PJM said the term “designated entity” was added to the OA at the time it submitted its Order 1000 compliance filing to refer to either an incumbent transmission owner or non-incumbent developer designated by the RTO to “construct, own, operate, maintain and finance immediate-need reliability projects, short-term projects, long-lead projects or economic-based enhancements to expansions projects that are selected through PJM’s competitive proposal window process.”

But the RTO said it identified “imprecise and inconsistent usage” of the term in Schedule 6, resulting in conflicting interpretations as to how the RTO should use the Designated Entity Agreement. It argued that the definition was too broad and was “intended to apply only to transmission projects sponsored by an incumbent transmission owner or non-incumbent transmission developer through the competitive proposal window process.”

While references to short-term projects, long-lead projects or economic-based enhancements to expansions “clearly applied to those projects submitted through PJM’s competitive proposal window process,” the RTO failed to differentiate between immediate-need reliability projects selected through the competitive proposal window process and those exempted from the competitive proposal process. It said the term “designated entity” was “not intended to apply to those unsponsored immediate-need reliability projects exempted from the competitive proposal process that are identified and selected by PJM and designated to the incumbent transmission owner in the zone in which the project will be located.”

PJM proposed revising the term to only apply to those immediate-need reliability projects, short-term projects, long-lead projects or economic-based enhancements selected in a competitive proposal window pursuant to the OA. The RTO said the “limited proposed updates” to the earlier Order 1000 compliance filing “will avoid potential confusion and eliminate any conflicting interpretations as to how PJM originally intended to use the Designated Entity Agreement.”

Stakeholder Protest

Several PJM stakeholders jointly protested the filing, including LS Power, American Municipal Power, the Public Power Association of New Jersey, the PJM Industrial Customer Coalition, the Indiana Office of Utility Consumer Counselor and the D.C. Office of the People’s Counsel.

The protesters argued that PJM violated the Federal Power Act by making the filing without approval from stakeholders, saying the RTO was taking an “unprecedented step” and that it was “attempting to avoid a vote from the Members Committee and meeting its burden under Section 206.” They argued that the term “designated entity” explicitly includes immediate-need reliability projects, short-term projects, long-lead projects and economic-based enhancements, and that PJM offered no proof of confusion about this definition.

They also argued that PJM’s “piecemeal, after-the-fact compliance filing approach” was inconsistent with due process principles that indicate parties should have the opportunity to protest the full compliance filing at the outset and that the commission should review the entire compliance filing “holistically.”

PJM countered that the protesters cited no precedent to support the claim that an updated compliance was prohibited or improper and that they “misstate the law” when claiming the commission lacks authority to consider the filing.

“When in 2015, the commission accepted PJM’s proposed tariff revisions implementing the requirements of Order 1000 in the PJM fourth compliance order with no further compliance directives, the accepted tariff revisions, including the definition of designated entity, became the rate in effect,” FERC said. “If PJM thinks that revisions to the definition of ‘designated entity’ and certain provisions of Schedule 6 would also be consistent with Order 1000, it should proceed by following its tariff procedures for submitting a Section 205 filing. Alternatively, if PJM believes its current tariff is unjust and unreasonable, it may file under Section 206.”

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NY Stakeholders, Residents Split on HVDC Tx Projects

New York’s plan to buy power from two new transmission lines being built to bring over 2.5 GW of renewable energy into New York City drew more than 17,000 comments by Monday, with opinion generally in favor of the entirely in-state project but divided on the project that would import electricity from Hydro-Québec in Canada (15-E-0302).

The state in September selected two transmission projects as Tier 4 renewable resources under its Clean Energy Standard. The 1,300-MW Clean Path New York (CPNY) project, developed by the New York Power Authority (NYPA) and Forward Power, a joint venture of Invenergy and energyRe, would bring upstate solar and onshore wind into the city. The 1,250-MW Champlain Hudson Power Express, developed by Transmission Developers Inc. and Hydro-Québec’s U.S.-based subsidiary HQUS, would run from the state’s border with Canada to Queens, with portions of the line running underneath the Hudson River.

<img src="//www.rtoinsider.com/wp-content/uploads/2023/06/140620231686782404.jpeg" data-first-key="caption" data-second-key="credit" data-caption="

CPNY Contracting Summary

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Regional development entities, county legislatures and labor union members supported both projects for creating an estimated 10,000 jobs statewide with $8.2 billion in in-state economic development investments. Others touted the new lines’ environmental benefits.

Julie Tighe, president of the New York League of Conservation Voters, said that CPNY is projected to reduce the state’s greenhouse gas emissions by 2.4 million metric tons annually, reducing overall emissions from the state’s electricity sector by 22%. CHPE would reduce GHG emissions by 37 MMT through 2040 and establish a $117 million environmental trust fund to improve water quality across the Hudson, Harlem and East rivers, as well as Lake Champlain, she said.

The projects are expected to deliver 18 million MWh of renewable energy per year to New York City, representing more than a third the city’s annual electricity consumption.

CPNY has a planned June 30, 2027, commercial operation date, while CHPE has an estimated COD of Dec. 15, 2025.

Winter Peak

The Independent Power Producers of New York (IPPNY) reiterated their longstanding opposition to CHPE. (See Enviros, Generators Oppose Canadian Hydro Line to NYC.)

“It is entirely possible that the [state’s] 2040 zero-emissions goal can be met at a lower cost with greater net benefits with the CPNY project, along with other zero-emission technology that does not require expensive new transmission lines,” IPPNY CEO Gavin Donohue said.

Not only would the CHPE project bypass both existing and new upstate renewable generation, it will not be able to meet the city’s power needs during winter months because Quebec load would take priority, IPPNY said.

HQUS CHPE Contracting Summary (NYSERDA) Content.jpgHQUS/CHPE Contracting Summary | NYSERDA

 

With the state’s electric system projected to become a winter-peaking system by 2041, “it is concerning that the HQUS project was selected despite being only able to provide capacity during nearly half the life of the proposed 25-year contract, raising serious questions regarding the reliability benefits of the project,” Donohue said.

IPPNY cited New York State Energy Research and Development Authority’s own benefit-cost analysis as showing CPNY would produce 34% greater net benefits than those yielded by CPHE, and the combined awards producing lower net benefits than if NYSERDA contracted CPNY alone.

Environmental, First Nations Concerns

The Sierra Club asserted that hydropower from mega-dams like the ones in Quebec is not renewable energy. The dams’ reservoirs can flood and destroy thousands of trees of the boreal forests that absorb tons of CO2 out of the atmosphere, and submerged vegetation causes more methane and CO2 to be released, said Catherine Skopic of the Sierra Club NYC Group and Atlantic Chapter.

In addition, dredging to lay the cables would stir up toxic polychlorinated biphenyls on the riverbed and further contaminate the waters of the Hudson River, Skopic said.

“The Hudson River is a fragile and important ecosystem, and under no circumstances should we be dredging up 100 years of buried toxins to build this pipeline,” Sierra Club volunteer Tara Noble added.

Some Bronx and Queens residents said they were more concerned about the air they breathe than about potential dangers from churning up riverbeds.

Since 2001 NYPA has operated four natural gas-fired peaker plants in the Mott Haven and Port Morris neighborhoods, promised at the time to be temporary, which neighborhood advocacy group South Bronx Unite said “have instead become permanent fixtures, burdening our community with additional air pollution.”

The group said those two neighborhoods have asthma hospitalization rates eight times higher than the national average and 21 times higher than any other neighborhood in the city.

Both transmission projects are essential to meeting decarbonization goals in New York City and improving public health, Queens resident Gianna Lum said.

“A just transition from fossil fuels is not only a priority to protect future generations,” Lum said. “The current peaker plant in Western Astoria is polluting nearby [public] housing and putting the health of vulnerable community members at risk.”

The Mohawk Council of Kahnawake, Quebec, said it supports CHPE and has agreed with Hydro-Québec on terms to host the new Hertel substation and the new 36-mile transmission line to be built through its territory.

While reparation claims by other indigenous groups for past harms by Hydro-Québec “must clearly be addressed with the relevant authorities, it is important to point out that the hydropower installations in question were not built as a part of the CHPE project,” the council said.

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Gov. Polis Speaks on Colorado’s Carbon-free Future

DENVER — Gov. Jared Polis last week joined energy industry stakeholders at the Colorado Solar and Storage Association’s 2022 Solar Power and Energy Storage Mountain West Conference to discuss the state’s future renewable energy economy.

Despite having trekked through a foot of snow to make it to the Feb. 2 conference, Polis was grateful to be able to speak for a live audience.

Writing in Colorado’s Greenhouse Gas Pollution Reduction Roadmap issued in January, Polis said that GHG reduction commitments from electric utilities are key to meeting the state’s carbon goals.

On Wednesday, the governor announced that most of the state’s largest utilities have submitted required clean resource plans showing regulators how they plan to achieve 80% emissions reduction compared to 2005 levels by 2030. He believes it’s possible that utilities will reduce emissions beyond the 80% goal.

“That’s the floor not the ceiling, but it’s a very, very aggressive floor,” he said.

Coal plant retirements are also an important piece of the state’s climate plan. As aesthetically displeasing as they are bad for air quality, coal plants are “urban blights” that only cost ratepayers more money, Polis said.

“Coal is our most expensive form of electricity in Colorado … and we really have to ask ourselves how long are we going to force Coloradans to pay more on their electric bills just to keep our coal plants going?”

With many of the state’s utilities moving toward carbon-free generation, Polis is most interested in keeping these renewable energy projects as low-cost as possible. With some “downward pressure” on the solar industry, Polis is optimistic that solar projects could come in under 3 cents/kWh, but he lamented the supply issues and costs the industry faces.

“We hope that President Biden discontinues the tariffs for China. That will help a lot,” he said. “Because whenever you think of the geopolitical landscape … the clean energy transition is something that should bring us together. We need the lowest cost solar panels possible, and I don’t care where they’re made. We need to get them done; we need to get the cost down.”’

On Friday, Biden extended the tariffs, but softened the blow by continuing an exemption for bifacial panels and doubling the amount of imports that can enter the country duty free each year, from 2.5 GW to 5 GW. (See Biden Extends Tariffs on Imported Solar Panels.)

Colorado has also made efforts to decarbonize buildings and transportation. Polis touted that, as of last month, electric vehicles made up 13% of the state’s total new vehicle sales.

Besides promoting EV sales, Polis hopes the state can modernize transportation as a whole with money state regulators budgeted to help improve air quality.

“In November, as part of our state budget, we proposed nearly half a billion dollars of one-time investments to improve air quality and accelerate the adoption of clean technology that improves the health of all Coloradoans and helps Colorado meet our climate goals.” Polis said.

The state hopes to use the funds to “improve transit opportunities, electrify school buses … replace the state’s oldest, polluting diesel trucks and grow the market for electric bicycles, giving rebates for rideshare programs and subsidies for low-income folks to be able to commute to work on e-bikes.”

Planning Ahead: Organized Markets

Looking to the next decade, Polis said joining an organized market will be integral to achieving the state’s long-term climate goals.

“In 2019, I signed into law the Colorado Transmission Coordination Act, which directed the PUC [Colorado Public Utilities Commission] to investigate the possible merits of joining an organized market,” Polis said.

In December, the PUC released a report saying that state utilities could save up to $230 million by joining a wholesale electric market. (See Colo. PUC: State Could Save up to $230M in Wholesale Market.)

“We now know what we suspected: that Colorado’s participation in a regional market is likely to reduce costs, improve the safety and reliability of the grid and advance our climate and clean energy goals,” the governor said.

In January, Xcel, Public Service Company of Colorado, Platte River Power Authority and Black Hills Colorado Electric chose to join SPP’s Western Energy Imbalance Service, which Polis described as “progress in the right direction.” (See Colorado Utilities Choose WEIS over WEIM.)

“A Western market is really an important part of reaching our clean energy goals faster and at a lower cost,” he said.

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FERC Auditors Find FirstEnergy Accounting Irregularities

FirstEnergy’s (NYSE:FE) long-time use of an internal service company to handle the day-to-day accounting for its transmission companies, local distribution companies and former power plant companies violated a number of federal regulations, a FERC audit has concluded (FA19-1).

FERC’s Division of Audits and Accounting issued an 85-page report Friday detailing the findings of the audit it announced a year ago. The company has largely agreed with its findings and committed to refunding $9.6 million to customers, the audit report noted.

The close examination of FirstEnergy’s accounting practices discovered that the cost of routine operations — from day-to-day local utility customer services to corporate political lobbying — somehow were reflected as other costs in accounting — for example, in transmission company overhead — and consequently may have been passed on as customer charges.

It also found that the internal company FirstEnergy had created to handle back-office accounting, FirstEnergy Service Co. (FESC), accounted for routine distribution company operating and overhead expenses as, for example, construction works in progress, though the expenses had nothing to do with construction.

In some cases, those mislabeled construction cost were deferred, meaning they were temporarily listed as a loss, only to be later amortized and collected in delivery rate increases.

FESC “capitalized overhead costs to Construction Work in Progress-Electric using an allocation method that was not based on actual time employees were engaged in construction activities based on timecard reports or on a representative time study,” the report said. “This may have led to FirstEnergy’s subsidiaries capitalizing costs to [that account] that did not have a definite relationship to construction. As a result, the companies may have overstated construction costs recorded in [the electric plant in-service account] as well as accumulated depreciation, depreciation expenses and accumulated deferred income tax (ADIT) balances, and understated operating expenses.

Relation to Bribery Scandal

The audit closely examined the role the unorthodox accounting practices played in the largest political scandal in Ohio’s history: FirstEnergy’s contributions of at least $70.1 million to “dark money” groups to bankroll a yearslong campaign to win legislative approval of a $1.1 billion subsidy for two nuclear power plants formerly owned by the company. Ohio lawmakers approved the bailout in 2019 in legislation known as House Bill 6.

Passage of H.B. 6 turned out to have been the key event in an ongoing federal probe into political corruption at the state level.

Lawmakers repealed the nuclear bailout provision of H.B. 6 in March 2021, eight months after federal prosecutors indicted former Ohio House Speaker Larry Householder (R) and four of his associates on federal racketeering charges. Two of the associates have pleaded guilty and are awaiting sentencing. A third killed himself. Householder and the fourth are awaiting trial.

FirstEnergy pleaded guilty to conspiring with public officials in a deferred prosecution agreement and agreed to a $230 million fine. The federal investigation is continuing, and further indictments are possible.

The audit found that “FESC improperly accounted for and improperly reported lobbying expenses, donations and other costs that lacked proper supporting documentation or were misclassified” as unsupported costs. The costs were charged to FirstEnergy subsidiaries as well as to the corporation. This led the subsidiaries to improperly account for and report the costs in their respective accounting records.

The report added that “out of $70.9 million of payments, $44.5 million was recorded in the accounts of [former power plant subsidiary] FirstEnergy Solutions [FES], and $25 million was recorded in FirstEnergy’s own books.”

FERC audit staff’s “discussions on internal controls during on-site interviews of FESC employees raised audit staff’s concerns about the existence of significant shortcomings in FirstEnergy and its subsidiary companies’ controls over financial reporting, including controls over accounting for the costs of civic, political and related activities, such as lobbying activities, performed by and on behalf of FirstEnergy and its subsidiaries,” the report said.

“Moreover, these controls may have been circumvented in ways designed to conceal the nature and purpose of expenditures made and, as a result, that led to the improper inclusion of lobbying and other nonutility costs in wholesale rate determinations.

Payments to Randazzo

The report details $22.8 million in payments FirstEnergy made between 2010 and 2018 to a pair of tiny Ohio companies incorporated by veteran utility lawyer and lobbyist Samuel Randazzo. Gov. Mike DeWine appointed Randazzo chair of the Public Utilities Commission in February 2019, a few weeks after the company made a final $4.3 million payment to Randazzo. DeWine has said he was unaware of the payment.

The company charged $20.9 million of the $22.8 million it paid to Randazzo to transmission companies and some of the corporation’s 10 local distribution companies, which the audit did not identify.

“FirstEnergy represented to audit staff that it will make refunds of around $185,000 to retail and transmission customers and has already made the related accounting entries to correct charges of $6.7 million allocated to electric plant in service of the [franchised public utilities] and transmission companies and to prevent those expenses from impacting future rates,” the audit said.

Randazzo resigned in November 2021, four days after FBI agents raided his downtown Columbus condo. He has not been charged.

The report also revealed that FirstEnergy told FERC staff auditors it was investigating $28.8 million in payments to 16 “entities associated with an individual identified by FirstEnergy” but not revealed in the report.

Most of those payments ($19.7 million) were charged to local distribution companies, while $1.1 million went on the books of FirstEnergy’s transmission companies, $2.2 million to FES and $5.8 million to the corporate books.

The audit report could bolster an effort by the Ohio Consumers’ Counsel (OCC) to convince the Ohio PUC to compel FirstEnergy to submit discovery in a case regarding the company’s political expenditures pending before the commission. The OCC, a state agency charged with representing consumers in utility issues, again pressed a PUC administrative judge for discovery within hours of the FERC audit release.