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November 5, 2024

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NextEra, SREA Protest Canceled MISO Project at FERC

NextEra Energy Transmission and the Southern Renewable Energy Association (SREA) have asked FERC to intervene in a last-ditch effort to save the only competitive transmission project ever approved for MISO South.

The two lodged separate protests after MISO filed at the commission in January to terminate its executed selected developer agreement with NextEra Energy Transmission (NEET) Midwest (NYSE:NEE) to construct the $115 million, 500-kV Hartburg-Sabine Junction project in East Texas (ER23-865).

The grid operator determined there wasn’t a need for the project last year, saying its benefits evaporated because of recent Entergy (NYSE:ETR) generation additions in the region. (See MISO Cancels Hartburg-Sabine Competitive Project.)

When Texas passed a right-of-first-refusal (ROFR) law for incumbent developers in 2019, a struggle percolated over whether NEET Midwest, MISO’s originally selected developer for the project, or Entergy Texas would build the line.

NEET told FERC in its filing that it is “optimistic” it can resume the project’s development following the 5th U.S. Circuit Court of Appeals ruling last year that the law discriminates against nonincumbents in the portions of Texas belonging to interstate transmission systems. Texas has since appealed the ruling to the Supreme Court. (See Texas Petitions SCOTUS to Review ROFR Ruling.)

The transmission developer told FERC that MISO’s cancellation of the project was premature. It said the grid operator “failed to appropriately weigh the full array of potential consequences of termination, like evaluating the true cost of canceling the [project] where it may more efficiently address identified system needs as compared to other projects proposed for inclusion” in MISO’s annual Transmission Expansion Plan (MTEP).

NEET pointed to the $1.1 billion, 150-mile, 500-kV line and substation project that Entergy Texas proposed for reliability purposes in MTEP 23. It implied that MISO is better suited to system planning than Entergy, which has sparked debate among stakeholders over whether the utility is attempting to dodge more efficient and regionally allocated transmission projects. (See Initial MTEP 23 Ignites Familiar Arguments over MISO South’s Reliability Spending.)

“Termination of the project at this time would leave real benefits on the table for customers in the MISO South region and potentially incentivize incumbent utilities in RTO/ISO regions to use litigation and other delay tactics as a method to undermine competitive transmission development in favor of potentially more expensive and less efficient solutions that are less likely to offer the same level of cost-containment mechanisms typically offered by developers through the competitive planning processes implemented by RTOs/ISOs,” NEET argued.

MISO approved Hartburg-Sabine as a market efficiency project under MTEP 17. The project was expected to alleviate congestion, ease import limitations and allow access to lower-cost generation for customers in the chronically congested West of the Atchafalaya Basin and western load pockets in Entergy’s MISO South footprint.

SREA accused Entergy of using “an anticompetitive strategy of capturing, delaying and/or canceling transmission projects with local generation assets at significant cost to local ratepayers, while at the same time not resolving underlying load pocket problems.”

The industry association maintained there still might be a need for Hartburg-Sabine because MISO performed only a “limited” benefits screen in its latest analysis of the line. It added that since 2017, the grid operator hasn’t performed a congestion analysis for MISO South, so the region could be in considerable need of prudent planning.

SREA lamented that Hartburg-Sabine has gone the way of the Waterford-Churchill economic project in Entergy Louisiana territory. The utility and MISO agreed to build the 230-kV project in 2016. Four years later, Entergy canceled the project after it built the nearby 950-MW St. Charles combined cycle gas turbine.

The association said Entergy is trying to resuscitate the Waterford-Churchill project in MTEP 23, rebranding it as a baseline reliability project rather than a competitively bid market efficiency project. Baseline reliability projects in the MISO footprint are proposed by transmission owners, not cost shared, and billed only to the local transmission zone in which they’re located.

“The cancellation of Hartburg-to-Sabine at this particular moment without a deeper analysis of the project could simply extend an ongoing trend in inefficient planning,” SREA told FERC.

Entergy filed in support of MISO’s decision to terminate, saying that Hartburg-Sabine “will not provide any meaningful adjusted production cost benefits, that terminating the project will not adversely affect reliability and that continuing to include the project in transmission models could distort transmission planning processes and potentially harm stakeholders.”

The utility also disputed that its proposed reliability project in MTEP 23 shares characteristics with Hartburg-Sabine. In an emailed statement to RTO Insider, Entergy spokesman Neal Kirby said the company will address the allegation in an upcoming FERC filing.

Kirby said the two projects are “completely different in location, scope and scale, and address different needs.”

“The MTEP 23 project travels from near the Texas border deep into the western region and allows increased imports of power to mitigate against risks during high load conditions or if generators in the western region are unavailable,” he said. “By contrast, the Hartburg-Sabine project travels a short distance entirely within the eastern portion of Entergy Texas’ service area and provides few if any of the benefits of the MTEP 23 project. In fact, as MISO’s analysis shows, it provides no meaningful benefits, let alone benefits exceeding costs.”

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Energy Tech Group Pans Duke Indiana’s Planned Gas Plant

A trade association representing emerging energy technologies is criticizing Duke Energy Indiana’s proposal to build a natural gas power plant, saying a greener collection of solar, wind and storage resources can annually save customers several million dollars.

Advanced Energy United (AEU) released a report in February assessing alternatives to Duke Energy Indiana’s (NYSE:DUK) 2021 integrated resource plan that proposes to build a 1,221-MW combined cycle plant by 2027. The clean-energy advocacy group tapped consulting firm Strategen to assess Indiana’s changing market dynamics and develop a clean-energy portfolio to “match or exceed the energy and capacity” from Duke’s proposed gas-fired plant.

Strategen and AEU concluded that a combined 2.9 GW of energy from wind (1,600 MW), solar (1,300 MW) and four-hour battery storage (900 MW) could save ratepayers $68.5 million in 2027. AEU said it anticipates savings in subsequent years will be even higher.

The advocacy group said last year’s Inflation Reduction Act changes the playing field for the resource transition. It said its suggested portfolio can provide equivalent energy and capacity more cheaply than the cost of a large gas plant. The group added that its economic analysis of the two options included potential excess energy sales and market purchases.

Duke said in its IRP that a new gas plant would avoid “committing to dramatic resource changes prematurely, preserve its decision-making flexibility going into the 2024 IRP analysis, and shield customers from undue cost increases in the near-term.”

“Duke’s assumptions from 2021 are outdated,” AEU said. “Market trends and recent federal action to extend energy tax credits have dramatically shifted the economics of various energy resources. This created a need to revise current and future utility plans so that benefits can flow to Hoosiers.”

Contemplated portfolio mix (Duke Energy) Content.jpgDuke Energy Indiana’s contemplated portfolio mix through 2040 under its 2021 IRP | Duke Energy

 

According to the report, the Duke gas plant would generate 6,014 GWh during 2027 while the renewables portfolio will churn out 7,984 GWh and likely require 961 GWh of imports. Economic analysis pinned the clean energy portfolio at $227 million in 2027 and the gas plant at $274 million, accounting for capital expenditures, fuel costs and fixed and variable operations and maintenance costs. Strategen said it also factored in revenues from selling excess energy, which the clean energy portfolio has more potential for.

The firm said its gas plant estimates don’t include the possible carbon capture and sequestration equipment that Duke may need to install to reach its 50% carbon-reduction goal by 2030 and net-zero carbon emissions by 2050. It also didn’t put a number on the cost of converting the plant to green hydrogen.

“This analysis is conservative and understates the potential economic value of the clean energy portfolio because it is only considering the energy revenue when matching profiles with the [combined cycle plant],” Strategen said. “If allowed to operate purely economically, the battery storage would see added revenue by arbitraging energy to periods of high prices, not just when the renewable generation is short.”

AEU noted that volatile gas prices may make the gas plant a riskier bet. It said Duke studied a scenario in its IRP where gas prices are so high — Duke kept the fuel price forecasts confidential — that building a new plant would be uneconomic.

The advocacy group asked that Duke re-evaluate its plan to invest in the plant and to “consider further investment in clean energy resources through the added benefit of the IRA tax credits.”

Duke Disputes Clean Portfolio Savings

In an emailed statement to RTO Insider, Duke said it’s in the process of updating its IRP to reflect the IRA, new guidance from MISO on generation planning, and the changing costs of technology and commodities. The utility noted that it’s holding a third public session on the IRP update Feb. 27.

Duke said AEU’s report relies on generic cost data which “may not always capture the full costs” and doesn’t match the real market bids that it received in request for proposals issued last year. It said when it updated AEU’s proposal for current conditions in Indiana, it immediately found the clean energy portfolio to be more expensive.

The utility said the portfolio is “not a realistic plan” because it requires Duke to site large-scale renewable projects that need thousands of prepared acres within six years.

“Generation diversity is essential and a strength, and we expect our updated plan will be diverse and include a significant amount of renewables as well as natural gas resources that can be dispatched when needed, regardless of weather conditions,” Duke said. “Including a moderate amount of natural gas in the resource mix positions us to retire coal plants earlier and add more renewables on our system until new, economical carbon-free technology arrives.”

The utility added that it’s simply too risky to substitute a “core” on-demand resource with a generation mix that relies on solar, wind, four-hour storage and power markets.

“We have to plan in a way that ensures reliability and self-reliance and is not overly reliant on the weather and power markets,” the company said. “We are making the largest transition from coal-fired power in the state, and the renewable energy we add will be the largest addition of any of Indiana’s utilities. We have to do this right. We have to transition in a way that ensures reliability and affordability for customers as well as cleaner energy.”

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Moore Names Consumer Advocate to Head Md. PSC

Maryland Gov. Wes Moore (D) has nominated a consumer advocate to head the Public Service Commission and a gas industry advocate to fill one of two other soon-to-be open seats on the commission.

As part of his “Green Bag” nominations sent to the Maryland Senate on Friday, Moore’s PSC nominations included Frederick H. Hoover Jr., assistant people’s counsel in the Office of the People’s Counsel (OPC), and Juan Alvarado, senior director of energy analysis for the American Gas Association.

Hoover will be replacing outgoing PSC Chair Jason Stanek, who was appointed by former Gov. Larry Hogan (R) and whose term expires on June 30, according to a spokesperson for Moore. Alvarado will  take the seat of either Commissioner Patrice Bubar or Commissioner Odogwu Obi Linton, both of whose appointments were rescinded by Moore last month, the spokesperson said.

Bubar and Linton were also appointed by Hogan but have remained unconfirmed by the Senate. They were among the 48 appointments by Hogan that Moore rescinded, with no explanation, in a Jan. 23 letter to Senate President Bill Ferguson (D). Similarly, he provided no explanation for his PSC nominees, which were just two of the 307 names sent to the Senate in the Green Bag.

Moore could make a third nomination to the PSC later in the legislative session, according to Maryland Matters. Bubar and Linton will continue to serve on the commission until their replacements are confirmed by the Senate and sworn into office.

Maryland’s Green Bag is a tradition that dates back to 17th century England, when lawyers carried their papers in green bags, according to an article in a 2004 State Archives newsletter. The current Green Bag is hand-crafted leather, embossed with the state seal, kept in the archives.

While once seen as a symbol of political patronage — green being the color of money paid for such appointments — today the bag, containing a list of gubernatorial appointments, is delivered to the General Assembly on 40th day of its legislative session, as set in state law in 1851.

Moore boasted that the 307 appointments sent to the Senate on Friday represent a truly diverse Green Bag, with women accounting for 57% of nominations and people of color comprising 45%.

Climate activists had hoped Moore’s rescission of Bubar’s and Linton’s nominations — and the end of Stanek’s term in June — would be an opportunity for the new governor to reshape the PSC and further advance his vision for Maryland’s electric system to be powered 100% by clean energy by 2035.

But the choice of both Hoover and Alvarado could signal a more centrist, pragmatic position.

So Who Are They?

Hoover’s record can only be pieced together from a number of media reports and online research. He led the Maryland Energy Office during the administration of former Gov. Paris Glendenning and was the agency’s deputy under former Gov. Martin O’Malley, both Democrats. Following Hogan’s inauguration in 2015, he worked as a senior program director for the National Association of State Energy Officials.

He has been at the OPC at least since 2020. During that time, the office has pushed the PSC to take stronger action against the gas industry. In early February, for example, the office petitioned the PSC to curb ongoing investment in new gas infrastructure by Maryland utilities.

“Maryland’s gas utility operations, massive infrastructure spending and long-term plans conflict with market trends, state climate policy and the interests of customers,” the OPC said in a Feb. 9 press release on the petition. “To address the conflict, the commission should promptly initiate proactive, comprehensive regulation to manage the transition to a new age, broadly acknowledged, in which gas will play a far diminished role.”

Hoover has also served as past board chair of the League of Conservation Voters, according to Kim Coble, the organization’s executive director, as reported in Inside Climate News.

Hoover’s “experience in clean energy and his commitment to addressing climate change will be valuable assets to the PSC,” Coble told Inside Climate.

However, she also raised concerns about Moore’s nomination of Alvarado. Having a gas industry official on the commission “could present a challenge to the PSC’s efforts to advance utility and transportation services while also respecting the significant and unique role the commission plays in advancing the state’s climate goals and specifically the governor’s 100% clean energy goal,” she said.

Alvarado’s LinkedIn resume lists a 12-year stint at the PSC from 2008 to 2020, including seven years as the director of its Telecommunications, Gas & Water Division. Since 2020, he has worked as director and then senior director of energy analysis at the AGA.

In a recent promotional video for the AGA, Alvarado says that the replacement of coal with gas has been responsible for a major reduction in U.S. greenhouse gas emissions. “It’s going to be an integral part of further reducing emissions in the future, to the point where I think it can one of the paths to zero net emissions,” he says.

A spokesperson for Moore defended both PSC nominations, citing the nominees’ decades of administrative experience and knowledge of the energy industry, as reported by Inside Climate. “The administration is confident that these individuals will work tirelessly to ensure safe, reliable and economic public utility and transportation service to the citizens of Maryland,” the spokesperson said.

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NY CJWG Poised to Select a 35% DAC Coverage Threshold

The New York Climate Justice Working Group (CJWG) on Thursday appeared ready to designate 35% of New York’s 2020 census tracts as disadvantaged communities (DACs), after reviewing public comments on the draft criteria.

CJWG members attending the group’s meeting argued that inclusion is better than exclusion, saying that a 35% census tract designation is preferable as it places less logistical burden on the dispersion of funds, since DACs would likely be closer together.

The scope of the percentage designation is critical, since it impacts where and how climate investments will be distributed, and which communities will receive more decarbonization financing.

The CJWG plans to hold a final vote on the criteria determining what percentage of census tracts will be covered as a DAC on Feb. 23. It expects to release final criteria to the public and the state’s Climate Action Council in March.

The CJWG uses 45 indicators to identify DACs, which can be grouped into either environmental burdens or population vulnerabilities. In addition, it defines DACs as “households reporting annual total income at or below 60 percent of state median income.”

The state’s Climate Leadership and Community Protection Act (CLCPA) created the independent CJWG and charged it with developing criteria to identify DACs, as well as requiring the group to meet at least once a year to review its DAC identification criteria and modify them as necessary (S6599).

The CLCPA outlines a goal “for disadvantaged communities to receive forty percent of overall benefits of spending of clean energy and energy efficiency programs,” which aligns with Biden administration’s Justice40 initiative.

Several states, such as California and Oregon, are adopting similar policies that more equitably distribute climate funds, using criteria that include geography, climate risk and historical inequalities to determine DACs.

CJWG member Abigail McHugh-Grifa, executive director of the Climate Solutions Accelerator of the Genesee-Finger Lakes Region, said the CJWG must ensure “no low-income households are left behind, and that limiting the number of census tracts could result in community level projects being lost.”

Alanah Keddell-Tuckey, director of the Office of Environmental Justice at the Department of Environmental Conservation, reminded other members that communities not designated as a DAC, but considered environmental justice areas, will continue receiving decarbonization investments through other funding streams, such as the Environmental Bond Act. (See ‘NEW YORK: Voters Approve $4.2B Environmental Bond,’ Incumbents Successful in Most Contested Governors’ Races.)

Eddie Bautista, executive director of NYC Environmental Justice Alliance, told fellow members that the CLCPA’s intent was to “drive investment on a community level while diminishing historical disparities.” He said the CJWG must consider a designation that “gets us to the highest CLCPA compliance.”

Another CJWG member, Sonal Jessel, director of policy for WE ACT, said she supports a 35% designation because “we must ensure that we are covering as many people as possible.” She asked whether native lands were considered.

Alex Dunn, a consultant with ILLUME Advising who generated the CJWG Tableau maps, confirmed that native lands were part of the tracts considered and advised members to remember that whatever percentage designation they decide upon should balance community vulnerabilities with environmental burdens.

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NY PSC Accepts $2.75M NYSEG Settlement over Gas Leak Fire

The New York Public Service Commission on Thursday voted to accept a $2.75 million settlement agreement with Avangrid’s (NYSE:AGR) New York State Electric and Gas over a gas leak that led to a fire last February (22-G-0425).

The funds will be used for gas ratepayer benefits, at the discretion of the commission.

The Feb. 2, 2022, incident destroyed a two-family home in Brewster, a village in the Lower Hudson Valley. Subsequent investigations concluded that NYSEG improperly installed the PermaLock tapping tee that caused the leak, kept poor records and complicated fire-prevention efforts because employees lacked proper equipment. (See NY PSC Accepts NYSEG Proposal to Address Gas Leak Fire.)

The order adopting the agreement notes that the commission-approved remediation plan — which directed NYSEG to investigate and resolve further tapping tee violations — is ongoing.

However, the order states that the $2.75 million settlement “provides gas ratepayers with a substantial financial benefit in connection with the resolution of the 11 alleged violations identified.”

“The commission holds public utilities responsible for the maintenance and safety of their gas facilities, and expects utilities to be ever ready for, and respond promptly and effectively to, incidents such as the Brewster event,” Public Service Commission Chair Rory Christian said in a statement.

The commission also called for a new proceeding “wherein all gas distribution utilities in New York will confirm and report on the use of PermaLock tapping tees in their service territories and perform an examination of potentially improperly installed PermaLock tapping tees in their gas systems.”

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New Jersey BPU Grants Second Easement for OSW Project

The New Jersey Board of Public Utilities overruled opposition from local governments and the New Jersey Division of Rate Counsel Friday to grant the state’s first offshore wind project an easement to connect its turbines over county-owned land to a substation onshore.

The board voted 4-1 to back the plan, which would run the 275-kV line underground through the Jersey shore community of Ocean City, which is in Cape May County, to the PJM grid at a substation sited on a now closed coal-fired power plant in neighboring Upper Township.

To move ahead, the project — Ocean Wind 1, developed by Denmark-based Ørsted — needed a temporary 18-month easement and a permanent 30-foot-wide easement across county land in Ocean City.

The BPU’s approval was the second successful use by Ørsted of a controversial law (S3926) enacted in July 2021 that allows offshore wind developers to site power cables and equipment on public land regardless of whether local or state governments approve. The BPU in September granted a separate easement sought by Ørsted for Ocean Wind 1 through Ocean City using the same law. (See NJ BPU Approves Easement Plan for 1st OSW Project.)

The law allows the BPU to override local government opposition if the project can show that the element at issue is “reasonably necessary” for the construction and operation of the wind project. (See NJ Lawmakers Back Offshore Wind Bills.)

“We don’t take these kinds of actions lightly,” said BPU President Joseph L. Fiordaliso. “And there has to be a definite public need in order for this board to even consider this type of action.

“But we have to look at the whole picture and see what is in the benefit of the 9.3 million people who live here,” he said. Fiordaliso added that he believed that “the transmission lines that will go through this area will not in any way alter the appearance or alter the economic viability of the area.”

Matters of Dispute

Voting against the easement approval, Commissioner Dianne Solomon said she did not believe that the board had done sufficient review to back the developer’s application. She said the BPU should have referred the case to an administrative law judge for a more thorough investigation.

“Clearly, this is a contentious if not a contested matter,” she said. “The record is lacking for us to determine if the preferred route is ‘reasonably necessary.’

“Given the situation in which we find ourselves under the legislation passed, we should be seeking more information, not less,” she said. “By voting no, I am not expressing opposition to the petition. Rather, I am objecting to the procedure and bringing this petition to a board vote today.”

Solomon, who voted to grant the first easement in September, added that she believed the board “erred in our decision” in approving the first easement.

During two public hearings to gather stakeholder opinion, and a third hearing at which the developer and local officials made their closing arguments, Ørsted argued that the Cape May easement, and a series of consents needed to obtain environmental and other permits, were necessary to keep the project on schedule after the developer spent two years in a failed attempt to persuade county officials to grant the approvals.

Cape May argued that the BPU should slow the process and take time to explore alternative cable routes dismissed by Ørsted. The attorney who presented the arguments for the county, Michael J. Donahue, who also represents 10 of the 16 communities in Cape May County, said Ørsted’s proposed route “could jeopardize sensitive marshes and impact area historical sites, and utilities in the area, such as sewer, gas and water main lines.” (See NJ County Asks BPU to Slow Approvals for First OSW Project.)

Donahue argued that to limit disruption and negative impacts from the transmission lines, the BPU should consider cable routes for two other offshore wind projects approved by the agency — Ocean Wind 2 and Atlantic Shores — at the same time as the route and easements for Ocean Wind 1.

Solomon cited arguments made by the New Jersey Division of Rate Counsel, which opposed the granting of the easements. In a letter to the BPU on July 7, Director Brian O. Lipman argued that all the parties involved should be allowed to conduct deeper discovery than the BPU’s procedure allowed.

Maura Caroselli, deputy rate counsel, said at the October hearing that the BPU should require Ørsted to reveal the costs of the different routes that it considered, and whether the chosen route was the cheapest route. If it is not, the board should require the developer to “show why the least cost plan is not a reasonable alternative,” she said.

Lipman, in the final hearing on Nov. 10, said there were still “factual disputes” that required the BPU to “hold a proper hearing with proper ability to cross-examination, discovery.” Such a process, he said, would create a “robust record from which the board can make its ultimate determination.”

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Mich. AG Nessel Calls for More Transparency on Utility Lobbying

Michigan utilities would be required to provide more transparency on their spending to influence rate cases under new regulations proposed by Attorney General Dana Nessel.

In comments to the Public Service Commission filed earlier this month, Nessel said that because utilities are government-regulated monopolies, “customers of these monopolies should have the right to know whether and how much their utility is spending to influence legislation or other public policy that impacts the utility and consumers. I am hopeful the commission will consider these recommendations and implement them for Michigan.”

Nessel’s comments were made in connection with the commission’s call for public comments on possible changes to its rate case standard requirements (Case U-18238). Currently rate cases are to be completed no later than 10 months after filing, and the utilities are supposed to provide a large series of documents as part of the initial filings.

Spokespersons for Michigan’s two largest regulated utilities, CMS Energy (NYSE:CMS) and DTE Energy (NYSE:DTE), did not make any comments directly about Nessel’s proposals. Both said their companies do not include any costs for lobbying in their rate requests.

Along with calling for the utilities to show what they spend to influence decisions on utility matters, Nessel said the rules on filing rate cases should also require that utilities use a shorter revenue and cost forecast period, require cost/benefit analysis, provide better disclosure for utilities that operate in several state jurisdictions and improve the litigation process.

Specifically, in terms of greater accountability on lobbying costs, Nessel called for the PSC to direct the utilities to report:

  • expenses on influencing regulation or legislation either directly or indirectly through their affiliates;
  • expenses on influencing public opinion about policy issues or on the company’s reputation;
  • expenses on all proceedings before the commission, specifically how much the company spent, and how it was spent, on previous rate cases, as well how much the utility forecast it would spend on a current rate case;
  • all 501(c)(3) and 501(c)(4) contributions to each nonprofit organization, including any organizations receiving contributions from a utility’s affiliated 501(c)(3) charitable foundations; and
  • all expenses for litigation a utility files trying to overturn rules or statutes.

The PSC has not indicated when it might propose changes to the rate case requirements.

Speaking for CMS, Katie Carey, director of external relations, said, “Consumers Energy supports the Michigan Public Service Commission’s efforts to make sure rate case filing requirements provide the information needed for a transparent and timely review of the company’s rate case filings. No costs to influence public policy are included in rate case filings and are not reflected in customer rates.”

And Peter Ternes, external affairs director for DTE, said the company “shares” the PSC’s goal of “ensuring the delivery of affordable, reliable and cleaner energy to our state and our customers.” DTE also looks forward to the PSC’s “determination of whether the current rate case filing requirements, which already require the production of significant documentation, require modification,” Ternes said.

Both the state and federal government already regulate DTE’s lobbying activities, Ternes said, which include revealing some lobbying expenses.

Also filing comments was the Association of Businesses Advocating Tariff Equity, a group that includes Dow Chemical and General Motors, which said utilities should provide more information on capital expenditures resulting from mandates, and on variances between projections and spending.

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Mahony Named Mass. DOER Commissioner

Elizabeth Mahony, a former deputy of new Massachusetts Gov. Maura Healey, has been picked to lead the state’s Department of Energy Resources.

Mahony was an assistant attorney general focusing on energy and telecommunications when Healey was Massachusetts’ attorney general, working in that office since 2015. She also previously spent three years at DOER as general counsel.

“I’ve worked with Elizabeth for many years,” said Energy and Environmental Affairs Secretary Rebecca Tepper, who also joined the Healey administration from the AG’s office, where she was energy bureau chief. “I’ve seen her in action, thinking up creative solutions to complex problems and delivering real results for the commonwealth. Elizabeth will be at the epicenter of our clean energy transition, and I know she will prioritize ratepayers and advance equity in everything she does.”

Mahony has worked closely with the solar and wind industries, as well as with environmental groups and on environmental justice issues such as the Merrimack Valley gas explosions.

She’s also a veteran of the ISO-NE process, working for years on the grid operator’s Consumer Liaison Group, most recently as chair of the coordinating committee, a position she took up a year ago. (See “Leadership Change,” Overheard at ISO-NE Consumer Liaison Group: March 10, 2022.)

“I’m thrilled to be returning to the Department of Energy Resources to continue the important work of achieving the commonwealth’s bold clean energy goals,” Mahony said in a statement.

“We will be intently focused on preparing our grid for this transition; updating our housing stock for electrification; encouraging more solar, storage and wind; and creating a fertile ground for the clean technology economy to flourish — all while centering environmental justice communities in the work,” she said.

She will replace Patrick Woodcock, who has served as DOER commissioner since December 2019.

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Study: Program Boosted Calif. Home Solar Above US Average

A California incentive program may have helped boost the rate of solar installation in new homes in the state to 40% in 2019, well above the non-California national average of less than 1%, according to a new study.

Within California, the percentage of new homes with solar varied widely by region. Much higher deployment was seen within the territories of investor-owned utilities, Lawrence Berkeley National Laboratory researchers said in their new report, “Starting with Solar.” The study, by researchers Grace Brittan and Ben Hoen, was the subject of a webinar last week.

One potential reason for the regional differences is a solar incentive that was available to IOU customers.

The New Solar Homes Partnership (NSHP) program was launched by the California Energy Commission in 2007. The program accepted applications until April 2018 and issued payments through 2021.

The cash-rebate incentive for solar energy systems in new homes ranged from 50 cents to $1.25/watt. The incentive was available in the service territories of Pacific Gas and Electric, San Diego Gas & Electric and Southern California Edison.

“In investor-owned utility areas of the state where NSHP incentives were available, recent new solar home penetration rates were approximately 50%,” the researchers said. “Outside those IOU areas, penetrations were less than 5%.”

As part of their study, the researchers talked to building industry representatives.

“[We] take advantage of the regulatory environment in each state,” said one large builder, who was not identified. “Net metering and other incentives are central to new solar homes penciling out.”

In contrast to the NSHP incentive, net metering is offered both inside and outside of IOU territories, Hoen noted.

The NSHP program preceded California’s solar mandate for new homes. The CEC approved the mandate in 2018, and it took effect on Jan. 1, 2020.

Regional Differences

In contrast to the new-home solar deployment rate of 40% in California, the rate in the U.S. outside of California was about 0.5% in 2018/19, the study found.

But some areas did better than others. The rate of new-home solar was just over 4% in Arizona, nearly 3% in Nevada and about 1.3% in Utah.

In Las Vegas, three zip codes made the top 10 list for new-home solar deployment outside of California, with rates of 79%, 50% and 24%. Bellingham, Wash., also made the top 10, where 25 out of 114 new homes were equipped with solar, or 22%.

Within California, new-home solar deployment in 2018/19 was highest in three counties — Placer, El Dorado and Yolo — where it hit 70%.

The Berkeley Lab study compared solar systems on new homes in California versus existing homes. The size of systems installed on existing homes in the state has been gradually increasing, to about 7 kW in 2020. In contrast, system size on new homes has been relatively flat from 2015 to 2020, around 4 kW.

“While new homes generally have smaller system sizes than existing homes, this may be due to having more energy-efficiency measures (less load),” the researchers said.

Builder Differences

From 2018 to 2020, about 7% of solar installations on existing homes in California included battery systems. In contrast, less than 1% of new-home solar systems came with batteries, the study found.

The researchers also looked at solar deployment among home builders who had the largest market share in California. Some, but not all, of the top new home builders had high rates of solar-equipped homes.

For Lennar, which had about 10% of the market share in 2018/19, around 90% of new homes in IOU territories were solar-equipped. Woodside Homes, with about 3% of the market share, was also close to 90% solar deployment in IOU territories.

The researchers noted that Lennar installed the solar systems themselves, while other builders subcontracted solar installation.

The NSHP program goal was the installation of 360 MW of solar energy capacity on new housing by the end of 2021. According to the program’s final report, $241 million in incentives were paid through the program for the installation of 232 MW of solar energy capacity.

About 12% of the total incentive payments went to affordable housing projects, which had a total capacity of 22 MW.

The CEC report noted that the program began with large incentive rates that were gradually reduced as hardware costs dropped over time. The installation of solar on new homes “is now cost effective without additional incentive money,” the report said.

CEC called the NSHP program a success.

“The NSHP program furthered the transition to a clean energy economy and has served as a model for new renewable and energy efficiency incentive programs across the United States,” CEC said in the report.

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EPA Reaffirms Power Plant Mercury Regulations

EPA last week reversed a 2020 Trump administration decision that undermined the legal basis for the Mercury and Air Toxics Standards (MATS) for power plants, reaffirming that the rule is “appropriate and necessary.”

The agency’s final rule reaffirms the scientific, economic and legal underpinnings of MATS, which was designed to curb the release of harmful substances from coal- and oil-burning power plants.

EPA says there are about 519 electric generating units at 250 locations that are subject to MATS. “Because the EPA is not amending the MATS rule, there are no cost, environmental or economic impacts as a result of this action,” the agency said. “However, finalizing this affirmative threshold determination provides important certainty about the future of MATS for regulated industry, states, other stakeholders and the public.”

“Retaining these protections is a critical first step,” said Georges C. Benjamin, executive director of the American Public Health Association. “We now urge EPA to strengthen them. We need stronger standards to protect all communities from these pollutants, especially those living near power plants.”

MATS has been at the center of a long-running seesaw battle that has changed directions with legal rulings and with control of the White House.

Amendments to the Clean Air Act in 1990 gave EPA authority to regulate electric utility steam-generating, and the agency under the Clinton administration concluded in 2000 that regulations were “appropriate and necessary.” Under the George W. Bush administration, EPA reversed itself in 2005 and said the regulations were neither.

The Obama-era EPA reversed itself again and issued the final MATS rule in 2012; it said resulting improvements to public health alone would be worth $37 billion to $90 billion a year, given the impacts of mercury and toxics such as hydrogen chloride and selenium. Coal- and oil-burning plants were by far the largest domestic source of these contaminants, EPA said, and among the largest emitters of pollutants such as arsenic, chromium cobalt and nickel.

In Michigan v. EPA in 2015, the U.S. Supreme Court ruled that EPA must consider the cost of implementing regulations it was ordering. EPA in 2016 said it had done so, and reaffirmed that its regulations remained necessary and appropriate.

President Donald Trump famously declared an end to “the war on coal,” and in May 2020, EPA found it was no longer appropriate and necessary to regulate electric utility steam-generating units through MATS.

EPA also said the residual risk and technology review (RTR) mandated by Section 112 of the Clean Air Act showed that emissions had been reduced to the point that residual risk was at acceptable levels, and that there were no new advances in emissions controls that would provide further cost-effective reductions.

President Biden issued a flurry of executive orders on his first day in office in January 2021, among them No. 13990, which directed EPA to revisit the May 2020 action.

The decision EPA announced Friday revokes the 2020 decision and reaffirms the 2016 decision.

In its news release Friday, EPA hinted at political considerations, speaking of its 2020 actions as having been carried out by “the previous administration.” It said the 2020 action undercutting MATS “was based on a fundamentally flawed interpretation of the Clean Air Act that improperly ignored or undervalued vital health benefits from reducing hazardous air pollution from power plants.”

Mixed Reaction

Reaction was divided.

Edison Electric Institute President Tom Kuhn commended EPA, saying in a statement that his members had been successfully implementing MATS during the yearslong regulatory process.

“EEI’s member companies, and the electric power industry collectively, have invested more than $18 billion to install pollution-control technologies to meet these standards,” Kuhn said. “Since 2010, our industry has reduced its mercury emissions by more than 91%, and we have seen a significant change in our nation’s energy mix, which is getting cleaner and cleaner every day.”

U.S. Sen. Tom Carper (D-Del.), chair of the Senate Environment and Public Works Committee, cheered the move.

“When the previous administration chose to remove the legal underpinnings of the MATS rule, they ignored the irrefutable science on the devastating impacts that mercury has on children’s health,” he said in a news release. “Fortunately, EPA is now correcting course and bolstering the MATS rule. This decision will help ensure that our nation’s power plants continue to run on effective pollution-control technology that protects communities’ health and economic wellbeing.”

The committee’s ranking member, Sen. Shelley Moore Capito (R-W.Va.), said in a news release that EPA would now be even more opaque in its rulemaking process and more likely to overstep its legal authority.

“With today’s announcement, we are once again reminded that the Biden administration’s end goal is to shut down American coal plants, fire American coal workers and do everything in its power to make America less energy independent,” she said.

Earthjustice welcomed EPA’s announcement and called for the agency to go further. “Coal-fired and oil-fired power plants are among the worst of the worst polluters, and their toxic emissions fall hardest on communities of color and low-income communities,” Earthjustice attorney Jim Pew said in a news release.

In its announcement Friday, EPA highlighted the health impacts: “Controlling these emissions improves public health by reducing fatal heart attacks, reducing cancer risks, avoiding neurodevelopmental delays in children and helping protect our environment. These public health protections are especially important for anyone affected by hazardous air pollution, including children and particularly vulnerable segments of the population such as indigenous communities, low-income communities and people of color who live near power plants.”

It said that the requirements of MATS, and concurrent advances in the technology used by the power industry, had by 2017 resulted in emissions reductions of 96% in acid gases, 86% in mercury and 81% in other metals.