FERC on Monday approved a settlement agreement requiring Alliance NYGT to pay nearly $900,000 for running two small power plants on natural gas for more than three years while being reimbursed for more expensive kerosene (IN21-4).
Under the terms of the agreement with the commission’s Office of Enforcement, the company will pay NYISO $463,984 for restitution and compensating market participants and remit a $420,000 civil penalty to the U.S. Treasury.
The agreement also requires that Alliance submit two annual compliance monitoring reports, with a third annual report at the office’s option, and to conduct at least one training program relating to compliance with the commission’s regulations and the NYISO tariff.
Alliance’s 40-MW Hillburn plant in Hillburn, N.Y. | Alliance Energy Group
Alliance bought the Hillburn and Shoemaker generators in 2007. The units are located in Orange County, and each has a 40-MW nameplate capacity. Between January 2009 and January 2012, Alliance operated the generators exclusively on kerosene while making repairs to remedy operational issues that were most pronounced when burning gas.
Alliance completed the generators’ gas equipment upgrades in 2012 and contacted NYISO to request information about updating the reference prices in advance of the repairs being completed. Alliance failed to start on gas in response to a January 2013 dispatch request, but thereafter “the generators began operating primarily on gas to fulfill their awards.” However, the units’ reference prices remained indexed to the more expensive liquid fuel, the commission said.
Alliance’s 40-MW Shoemaker plant in Middletown, N.Y. | Alliance Energy Group
NYISO in September 2013 began communicating with Alliance about the type of fuel used to operate the generators, but the company’s responses were “untimely, inaccurate or incomplete,” according to FERC, and it wasn’t until March 2016 that the firm began updating its reference prices to reflect gas capabilities for both generators.
During the period that it failed to notify NYISO of the generators’ ability to operate on gas, Alliance received inflated make-whole payments.
Utilities need to offer electric vehicle rate designs that will encourage customers to use EVs in the most efficient ways possible, such as utility-managed charging, according to Rachel Gold, director of the utilities program at the American Council for an Energy-Efficient Economy.
“A lot of utilities around the country are offering rate designs [for grid services],” Gold said during a National Association of Regulatory Utility Commissioners Winter Policy Summit panel discussion Wednesday. But “there are very few utilities that are offering managed charging programs right now.”
She also discussed utilities’ role in charging infrastructure deployment.
“Most of the investment that we’ve seen [by utilities] has been targeted at the traditional role of the utility as an infrastructure company,” Gold said, especially, she added, in Level 2 charging infrastructure.
Building and incentivizing EV charging, like the home charger shown here, is an emerging role for utilities in the coming transportation electrification. | Enel X
She said utilities could focus on incentivizing investments in fast charging infrastructure, specifically fast charging usage by EV fleets.
Within charging infrastructure investment strategies, utilities have been successful in targeting opportunities to address multiple market and community benefits at once.
“We’ve seen utilities targeting low-income, economically distressed or environmental justice communities,” Gold said. “We’ve also seen targeting at bus charging or medium- and heavy-duty fleet charging in places where there’s an air quality benefit and, in particular, where there’s an air quality benefit that overlaps with low-income communities.”
Colorado’s Approach
Colorado Public Utilities Commissioner John Gavan said utilities in his state were directed by law in 2019 to develop transportation electrification plans that would help the state reach its target of putting 940,000 EVs on the road by 2030.
“Today we only have 33,000 EVs on the road, with less than 4,000 charging ports across the entire state,” he said. “Growing to a 940,000-vehicle level — which would be half our cars — by 2030 represents a huge shift for the state.”
While most of the utility plans on transportation electrification in Colorado focus on building out charging infrastructure, regulators worked to ensure utility activity does not conflict with the emerging private charging economy, Gavan said.
He said that the initial charging infrastructure deployments under the transportation electrification plan from Xcel Energy Colorado focused on multifamily dwellings and lower-income neighborhoods. The utility is also focusing on Level 2 and fast charging deployments for areas that do not support a strong commercial business case.
Gavan said that the PUC has allowed Xcel to own EV charging infrastructure and promote managed charging, “but we did not support a broad EV purchase rebate.” The commission instead targeted the rebate program to income-qualified buyers.
That program investment, he said, totals $107 million over three years and carries a monthly bill impact of 68 cents per ratepayer.
A MISO study on renewables integration has found the grid operator can reliably operate its system with a fuel mix heavy on wind and solar energy, but only if its members engage in dramatic transmission expansion.
The 216-page report concluded that reliable system operations “beyond the 30% system-wide renewable level is not insurmountable and will require transformational change in planning, markets, and operations.” It said a market redefinition and grid expansion is imminent to accommodate an “unprecedented pace of change.”
Speaking Wednesday during a Feb. 10 Planning Advisory Committee teleconference, MISO Manager of Policy Studies Jordan Bakke said the four-year Renewable Integration Impact Assessment (RIIA) showed that transmission — not energy storage — remains most effective at delivering power when renewable energy accounts for a majority share of the resource mix. (See MISO: Tx Beats Storage in Integrating Renewables.)
| DTE Energy
However, MISO is optimistic it “can achieve renewable penetration of at least 50% with transformational change and coordinated action amongst all participants.”
The RTO hovered around a 12-13% renewable penetration in 2020.
The study predicts a steeper, shorter and later-in-the-evening loss-of-load risk as wind and solar resources meet more of the footprint’s demands. (See MISO Renewable Study Predicts Later Peak, Narrower LOLE Risk.) MISO also expects to be more dependent on the system’s remaining conventional generators and warns of shortage risks when the resources take unexpected outages.
Bakke said that, taken as a whole, the study underpins MISO’s need for more transmission planning, , new market tools “to incentivize availability of grid services,” innovative transmission technologies and fresh resource adequacy mechanisms and unit-commitment tools.
“MISO, our members, and the entire industry are poised on the precipice of great change as we are being asked to rapidly integrate far more renewable resources,” MISO President Clair Moeller wrote in a summary. “Given our regional reliability imperative, MISO must act quickly, deliberately, and collaboratively to ensure that the planning, markets, operations, and systems keep pace with these changes. We can achieve this great change if we work together.”
The RTO will host a March 3 workshop to review with stakeholders the study’s conclusions in more detail.
The future of net energy metering ― and how solar owners should be compensated for the power they put back on the grid ― begins with asking the right questions, says Mohit Chhabra, senior scientist at the Natural Resources Defense Council.
“We often talk about net metering as an absolute, when the question really is: net metering and what?” Chhabra said during a panel discussion on NEM on Feb. 9 at the National Association of Regulatory Utility Commissioners Winter Policy Summit. “What is the value of solar in my region? What are your energy and climate policy goals? Once you’ve determined that value of solar, how do you best reflect that in a way that’s easy to understand and manage in rates?”
First introduced by states when rooftop solar costs were high, NEM was intended to help residential customers offset their upfront costs by paying them retail electricity rates for their excess power. NARUC said in a FERC Rejects Net Metering Challenge.)
NEM has long been a flashpoint between solar installers and utilities. Discussions have shifted toward looking at net metering in the larger context of rate redesign as increasing amounts of distributed energy resources come onto the grid.
“It’s really a blunt instrument,” said Emily Fisher, general counsel and corporate secretary at the Edison Electric Institute, the trade association for investor-owned utilities. “It needs to be refined because the value that rooftop solar provides is really dependent on where it is and when it’s being used.”
She reframed the question for the panel: “How do we make it the most useful tool possible for accomplishing the goals we collectively have?”
| FLS Solar
A Mature Technology
Vermont provides a case in point. Net metering has driven a thriving solar industry in the state, where incentives are available not only for small rooftop installations but for commercial projects up to 500 kW, Vermont Public Utility Commissioner Sarah Hofmann said. The state also offers additional incentives for projects built in “preferred locations,” such as brownfields or parking canopies, she said.
About 30% of the state’s peak load now comes from net-metered solar, Hofmann said, but that success has come with problems. As in other states, Vermont utilities argue that net metering has shifted fixed costs for transmission and distribution from net-metered customers to those without solar, many of them low-income consumers. Bottlenecks are also occurring in remote areas of the state where new solar projects cannot export power without jeopardizing the grid, she said.
NEM “does have to change and evolve. Basically, [solar] is a mature technology at this point, and you make different regulatory decisions when something has matured.”
Vermont’s most recent revision to the NEM compensation structure — the fourth since 2017 — will see residential rooftop rates step down from 17.4 cents/kWh to 16.4 cents and later in the year, to 15.4 cents.
Incentive or Price Signal?
States with strong solar markets have rolled out a range of NEM successors, underlining the diverse, regional nature of possible alternatives. California has retained retail NEM but tied compensation to time-of-use rates.
Customers get a lower payback for excess solar put on the grid at mid-day, but pay higher, peak rates for power they use from the grid in the late afternoon and evening. As a result, the residential storage market has been growing in the state, allowing solar customers to store their mid-day power and either use it or put it back on the grid later in the day. The California Public Utilities Commission is now working on another update, NEM 3.0.
Hawaii, which has the highest penetration of rooftop solar in the nation, ended retail rate net metering in 2015. The state has since introduced tariffs that encourage customers to consume as much of the power they produce as possible, or limit the amount they can export, again raising consumer interest in residential storage.
Most recently, the Arizona Corporation Commission approved a technology-agnostic compensation plan for a range of DERs. Rates are based not on specific technologies, but on the resources or services they provide to the grid. (See States Working out Details of 100%.)
Kevin Lucas, senior director of utility regulation and policy at the Solar Energy Industries Association (SEIA), said the initial successes of net metering in high-penetration markets underline why it should be retained in states where residential solar is still in its early stages. While acknowledging that changes are needed, he said, the rules should be kept simple, especially for residential and small business customers.
The residential solar market is itself resilient, adjusting to changes in net metering rates and the COVID-19 pandemic ― a point often unacknowledged in policy discussions like those at NARUC. According to the most recent market report from Wood Mackenzie and SEIA, after a pandemic-related drop in the second quarter of 2020, residential solar has rebounded, and some installers are reporting strong pipelines. The two-year extension of the 26% federal investment tax credit for solar, enacted in December, should also help maintain market growth. (See Wind, Solar, EE, CO2 Storage Win Tax Breaks.)
Going forward, rate and NEM redesign will require balance, tradeoffs and keeping all policy options open, Lucas said.
“When you get to very high levels of penetration and you start to focus on how do we deeply decarbonize the system, you start to have some unique trade-offs that you might not have had. The picture changes a bit as you advance,” he said.
“It’s good to remember that net metering isn’t the only way to promote solar,” Chhabra added. “Additional incentives could be built into rates. It’s striking the right balance between sending more accurate price signals and sending the right level of support and having the right policies in place.”
FERC’s directive to open wholesale markets to aggregations of distributed energy resources is forcing states to consider new communication channels and more holistic system planning, and how they respond will be crucial, industry officials say.
“FERC left a lot of power in the state regulators’ hands, and this is really leaving the states in a place to make or break Order 2222,” Marcus Hawkins, executive director of the Organization of MISO States (OMS) said during a panel discussion at the National Association of Regulatory Utility Commissioners (NARUC) Winter Policy Summit on Feb. 9. Illinois Commerce Commission Chair Carrie Zalewski moderated.
FERC Order 2222, issued last September, ordered RTOs and ISOs to open their markets to DER aggregations now largely limited to providing demand response (Order 2222, RM18-9). Although the commission declined to allow local or state regulators to prohibit DERs from participating in the wholesale markets through an opt-out, it said regulators can prevent resources from participating in both retail and wholesale programs. (See FERC Opens RTO Markets to DER Aggregation.)
“What a retail regulator does to shape their programs will have a huge influence over the economics of where DER aggregation can flourish or not,” said Hawkins, who predicted retail programs are likely to provide more revenue to DERs than wholesale markets in the near term. “Also, the ability to condition participation in a retail program is huge. So, if a retail program prohibits wholesale activities … then you really have the final say in where the DER is going to go.”
Marcus Hawkins, executive director of the Organization of MISO States, discusses how states should engage in RTO stakeholder proceedings on FERC Order 2222. | NARUC
State regulators will also control spending on distribution system investments, which will determine metering technology and the sort of information that will be available on DERs, Hawkins said.
FERC defines DERs as any resource located on the distribution system, a distribution subsystem or behind a customer meter, including energy and thermal storage, intermittent and distributed generation, energy efficiency and electric vehicles. The order requires RTOs to allow DER aggregators to register as market participants under models that accommodate their physical and operational characteristics.
FERC’s initiative would be threatened, Hawkins said, by “a system where distribution utilities are constantly fighting battles, being accused of being a barrier to participation in wholesale markets, or a place where inefficient planning is being done because not enough data is being shared between the DERs and the wholesale market.”
Hawkins noted that RTOs, which are facing a July 19 deadline for compliance filings, must determine the coordination framework among them, state regulators, distribution utilities and aggregators. “It’s important for [state] commissions to consider whether they want that coordination to be direct — where the aggregator or the RTO has some sort of direct communication with the commission — or indirect through a regulated utility,” he said.
RTOs must also determine how often to review the coordination. “It’s not just set it and forget it,” Hawkins said. “Aggregations might change. So, there might need to be some flexibility in the process.”
Hawkins said OMS has found it challenging to get utility distribution officials involved with MISO. “There’s a lot of what I refer to as MISO watchers, which are the wholesale and transmission planning people at the utilities, but not necessarily the distribution folks,” he said. “Getting those experts — both people who work on DER programs from commissions and also distribution utility experts into the conversation at the RTO is important. … Bringing those voices is the only way we’re going to understand where conflicts exist between retail and wholesale tariffs. … You need to have a lot of eyes on the language to understand what will make those retail programs either work or fail within the larger wholesale context.”
New Lines of Communication
Paul Suskie, SPP’s executive vice president of regulatory policy and general counsel, said the RTO’s territory, which has no capacity market and where all utilities are vertically integrated, is starting to see a bit more interest in DER, “but it’s still very, very small in the aggregate.”
Paul Suskie, SPP | NARUC
“We’re looking at operational communication challenges [under Order 2222],” he continued. “This will require us to communicate with entities that we don’t historically communicate with. … Because we’re at the wholesale [level] we do not have a lot of communications with even some of our member companies at the retail level. … So, we have some new communication and operational challenges with existing members, let alone new entities that may participate under Order 2222.”
Ted Thomas, chairman of the Arkansas Public Service Commission said the FERC directive “is very challenging. But if we can meet those challenges, I think there’s a great upside.”
Thomas said FERC “left many of the most difficult challenges to be dealt with by the RTOs in their stakeholder processes,” adding that he hopes the commission will grant RTOs an extension on the compliance deadline. (See MISO to Seek Extension on Order 2222 Plan.)
System Planning
Kelli Joseph, Power Edison | NARUC
Former NYISO official Kelli Joseph, now an adviser to mobile storage company Power Edison, said it was “unfortunate” that FERC did not spell out its system planning requirements “other than saying a coordinated framework could be good.”
Although RTOs conduct separate transmission planning processes for reliability, economic and public policy projects, Joseph said it’s important to ensure “that there’s at least a process within one or more of those transmission planning models that can actually do a comparison between a transmission solution, a generation solution and potentially a DER solution.”
Joseph served on a joint task force of NARUC and the National Association of State Energy Officials that explored how aligned planning could guide the development of the grid in the future. The task force will hold a press conference at 11 a.m. EST on Feb. 11 to discuss the results of its efforts. “Thinking about how to use that … system planning framework could potentially inform some of this market coordination hopefully going forward as well,” Joseph added.
Oregon Public Utility Commissioner Megan Decker | NARUC
Oregon Public Utility Commissioner Megan Decker said although Order 2222 doesn’t apply in her state because it is not part of an RTO, it nonetheless demonstrated “leadership.”
“I have been really impressed with the level of dialogue on DER integration that I’ve seen as a result of the FERC order,” she said. “Unlocking the distribution system is something we will need. It’s going to be a pretty long-term transition. Wholesale market access by itself doesn’t necessarily mean the kind of DER explosion in states that aren’t ready for it. State programs right now largely drive DER uptake because of the economics.”
Even in California, which has done much of what is required by the FERC order, Decker said, “the money [to encourage DERs] is not there in the wholesale market.”
Infrastructure is the main concern facing two Washington bills that propose to switch the state’s auto market to only electric vehicles by 2030.
Will there be enough generation? Who will install and pay for all the charging stations? Can the Northwest power grid transmit enough energy to handle all those vehicles?
“We’re going to need hundreds of thousands of charging ports for millions of vehicles,” Douglas Warren, a lobbyist for Douglas and Klickitat counties’ public utility districts, said at a Washington House Transportation Committee hearing Feb. 1.
State Rep. Nicole Macri (D) and Sen. Marko Liias (D) introduced similar bills this session to require that the Washington State Transportation Commission adopt regulations by 2025 mandating that all model year 2030 and later passenger and light-duty vehicles sold in the state be EVs. The two bills would require the commission to provide the legislature a plan for developing the regulations by Sept. 1, 2023.
“We’re trying to phase this in. We’re trying to be thoughtful,” Liias said.
This is the second year that Macri has submitted the proposal as a bill. It did not make it out of the House Transportation Committee in 2020. This year, Liias introduced a companion bill in the Senate.
Two new Washington bills would require that all cars sold in the state be electric by 2030. | Washington Department of Commerce
“We’re presenting this bill because of the urgent needs of dealing with climate change,” Macri said.
Macri and Liias both pointed to General Motors’ recent announcement that it plans to manufacture mostly electric vehicles by 2035. Macri also cited Volvo and Volkswagen introducing their first electric vehicles in the last few years. The private sector is already beginning a transition to EVs because of pollution concerns, they concluded.
“Transportation is the largest source of emissions in the state. Everyone knows we’re headed this way,” Liias said.
Pierce County Councilor Ryan Mello, speaking on behalf of himself, told the committee that the marketplace has begun to gradually transition to EVs on its own, and that the state government needs to send a strong signal to manufacturers to encourage that change.
‘Wishful Thinking’
At the hearing, several questions addressed the infrastructure issue, which both Macri and Liias acknowledged is a major hurdle.
“No one knows what the fiscal impact of this bill will cost. … There seems to be variables on top of variables on top of variables in this bill,” Rep. Jim Walsh (R) said.
“We need a statewide analysis,” Warren said. Nick Garcia, policy director for the Washington Public Utility Districts Association, said a massive investment in Washington’s power grid will be necessary to sustain EV culture.
Macri contended that having a locked-in date is needed to give the marketplace good information on how to adjust and give the state government a timetable to get infrastructure constructed. “2030 is still a long way off,” she said.
Scott Hazelgrove, representing the Washington State Auto Dealers Association, noted that his organization opposed Macri’s bill last year but is neutral in this session and hopes to work with the representative on the details. A deadline for making changes could be a useful tool in helping his constituents deal with switchovers to EVs, he said.
“A 100% EV rate in Washington approaches wishful thinking,” argued Jessica Spiegel, Northwest regional director for the Western States Petroleum Association.
Rep. Ed Orcutt (R) asked, “What if we get to 2030, and there’s not a big enough supply of EVs, will there be exceptions?”
A public meeting held Monday for a planned electrical substation in the East Boston neighborhood shined a light on the juxtaposition of long lead times for transmission planning and new energy transition goals.
Eversource Energy first identified a need for new transmission to accommodate increased demand in the East Boston area in 2014. Two new transmission lines were built between existing substations in the nearby cities of Chelsea and Everett as part of the utility’s Mystic-East Eagle-Chelsea Reliability Project.
But opponents of the new substation argue that renewable resources could meet that demand.
The substation was approved for construction by the Massachusetts Energy Facilities Siting Board (EFSB) in 2017, with the condition that Eversource and the city of Boston consider moving the substation away from a fish processing company and closer to a playground. The board held the meeting to determine whether to approve the change. Opponents of the project called on the board to reconsider the project based on public health and clean energy concerns.
Marcos Luna, a local resident and professor in the Geography and Sustainability Department of Salem State University, said during the meeting that the policies that allow for the approval of the substation “lag reality” given the state’s target for net-zero emissions by 2050.
Residents in Boston are questioning the justification for a local substation project that Eversource says is important for maintaining reliability among increasing electrification. | Famartin, CC-BY-SA-4.0 via Wikimedia Commons
An analysis led by the Union of Concerned Scientists (UCS) found that installing rooftop solar panels in the East Boston neighborhood could meet increased electricity demand in the area while cutting customers’ electric bills and reducing emissions.
UCS conducted the study with GreenRoots, a local environmental justice organization, and found that deploying rooftop solar on a third of triple-decker buildings in the area could provide close to 10 MW of solar capacity and that the households identified in the study could save $60 to $120/month on their electricity bills.
Pairing those solar systems with a typical battery system could add more than 9 MWh of energy storage, the study said. Furthermore, the systems in aggregate could cost 40% less than the $50 million Eversource proposal.
The study also found that the solar systems could reduce emissions from electricity consumption in the buildings by 40% compared to using power generated by fossil fuels. With energy storage batteries, the solar could reduce emissions by 70%.
Demand Concerns
Patrick Woodcock, commissioner of the Massachusetts Department of Energy Resources, told attendees of the EFSB meeting that increasing electrification of buildings and transportation will drive up load, particularly for heating.
“We are increasingly seeing electrification as our long-term, upcoming plan” for reducing emissions in the state, he said, necessitating additional transmission infrastructure.
He noted that adding that solar and energy efficiency standards are also driving load down, but there is not a consensus on how that trend will manifest in the area around the planned substation.
Bryndis Woods, a senior researcher at the nonprofit consulting group Applied Economics Clinic, said that Eversource has not presented sufficient evidence for the need of the planned substation. The company is basing its load increase forecast on a 2015 ISO-NE Capacity, Energy, Loads and Transmission report, which predicted a 1% increase in load per year.
Woods testified that local load has only been growing by 0.4%/year, and load growth in the area is forecasted to be flat to negative.
Bob Clarke, director of transmission and citing for Eversource, told RTO Insider that while the utility does not expect load to increase as much as it originally predicted in East Boston, the Chelsea substation’s load will exceed system capacity by 2022, and there is no room to expand that substation.
Eversource’s forecasting is different from ISO-NE’s, said David Rosenzweig, the attorney representing the utility before the EFSB. Logan Airport, which is in East Boston, is expecting a 10-MW increase in demand because of expansion, and new planned development in the area will consist of 10.5 million square feet of mixed-use building space to be constructed over the next 20 years, Rosenzweig said.
With these significant load increases, East Boston is “in great vulnerability” of supply shortages or even outages if the substation is not built, he said.
Maine legislators and officials gave a preview of their work this year in implementing the state’s energy policies while keeping costs to consumers low.
Following a surge of new climate-related legislation passed in Maine last year, state legislators are now trying to balance the need to meet mandates without burdening ratepayers.
Understanding the financial ramifications of energy-related policies “is constantly my No. 1 priority,” Sen. Trey Stewart (R) said Wednesday during a preview of the joint Energy, Utilities and Technology (EUT) Committee’s work this legislative session.
Stewart called Maine’s new climate laws “admirable,” but he said the costs of achieving them “will become a problem at some point.” Last year the Legislature passed legislation relating to, among other things, the state’s emissions and renewable portfolio standard; net metering; offshore wind; heating; electric vehicles; and transmission alternatives.
This year’s legislative session will give lawmakers a chance to adjust the bills passed last year, Dan Burgess, director of Maine’s Energy Office, said during the webinar, hosted by E2Tech.
“I think [this session] is an opportunity to continue the progress that we’ve made in order to create economic opportunities within the energy space and to ensure that we’re keeping affordability in mind,” he said.
Maine lawmakers are looking at ways to make the state’s climate goals, such as putting 41,000 electric vehicles on the road by 2025, affordable for ratepayers. | Chevrolet
Rep. Nicole Grohoski (D) said that her priority for this session is to make sure that the energy transition is affordable and equitable for residents. She said the EUT Committee will consider a group of bills that deal with financing and accessing lower-cost capital.
Those bills address, for example, commercial property-assessed clean energy (C-PACE) financing, heat pump incentives and even a green bank, she said. In addition, there are legislative efforts related to creating a consumer-owned utility to unlock access to revenue bonding and low-cost capital for a large-scale grid buildout to support electrification of major sectors.
Grohoski said that she is sponsoring a bill this year to create a generation authority in the state that would also provide nontaxable low-cost capital through revenue bonds for local clean energy developers.
New Reports
Burgess said that the Energy Office will release information soon related to progress of the Maine Climate Council’s strategic initiative to create a clean transportation roadmap for the state. Initial estimates from the council show that the state needs to have 41,000 light-duty EVs on the road by 2025 to meet its emissions goal for 2030.
The roadmap, Burgess said, will help identify issues that must be addressed to advance clean transportation across all EV classes and public transportation.
The Energy Office also is preparing to release a report about the Climate Council’s call for modernizing Maine’s buildings. Burgess said the report will identify the current state of building efficiencies and opportunities for advancing home weatherization programs, appliance standards and C-PACE programs.
Commission Initiatives
The Maine Public Utilities Commission is working to overcome significant technical challenges related to clean energy mandates put in place by the Legislature, while also acknowledging the importance of minimizing costs for consumers and businesses.
Chairman Philip Bartlett said the commission currently has a working stakeholder group of industry and utility representatives to examine the interconnection of distributed energy resources. The working group issued a notice Tuesday seeking input on the review process for small DER projects. Bartlett said that some small projects are subject to a higher level of review than others, causing “significant delay and added expense.”
As part of that inquiry, he said, the group will consider penalties for utilities if they do not meet interconnection requirements.
The PUC also will be opening a proceeding to looking into Central Main Power’s (CMP) recent claim that it needs to complete upgrades at more than 100 substations to connect new DERs to the grid.
“It’s important to consider the timeline with respect to when CMP became aware of this problem … and how projects are being impacted,” Bartlett said.
To ensure that Maine can interconnect high levels of DERs in the future, the commission will open a separate proceeding to consider distribution system design changes. The proceeding also will work to improve data collection and transparency.
“It is important to assess what is needed for the grid of the future, and we cannot minimize costs without good information to help drive decision-making,” Bartlett said.
Gov. Gavin Newsom named new members Tuesday to the three bodies that govern California energy policy — CAISO, the Public Utilities Commission and the Energy Commission — and reappointed a sitting member of the ISO’s Board of Governors.
Newsom appointed former NERC Trustee Jan Schori to fill a seat on the CAISO board left vacant when former Chair David Olsen decided to retire at the end of November.
In a rare move, the governor named an Energy Commission staff member, Deputy Director Siva Gunda, to the panel of five commissioners. Former Commissioner Janea Scott left in January to take a top post at the U.S. Department of the Interior under the Biden Administration.
Newsom selected the Energy Commission’s general counsel, Darcie Houck, to fill an open spot on the CPUC dais. In December he picked former Commissioner Liane Randolph to head the California Air Resources Board, leaving a vacancy.
And the governor reappointed Mary Leslie to a seat she has held on the CAISO board since 2019.
During Tuesday’s CEC meeting, commissioners welcomed their new colleague, Gunda, and wished Houck well in her next role. Chair David Hochschild noted that the CEC and CPUC must work together to predict energy use and procure resources. The additional connection between the two entities will be helpful, he said.
Darcie Houck, chief counsel to the California Energy Commission, will fill a vacant seat on the California Public Utilities Commission. | California Energy Commission
“The collaboration between the CPUC and the Energy Commission is so fundamental to our success, and so, knowing the strong bond the two of you have with each other is another reason we should all be excited,” he told Houck and Gunda.
Working with CAISO, the commissions are trying to head off energy shortfalls this summer and in the next few years, as the state transitions from fossil fuels to renewables. Last summer’s energy emergencies and rolling blackouts led to calls for better synchronization among the three entities. (See New CAISO CEO Vows Urgency on Resource Adequacy.)
“It’s just clear California will not succeed and will not have an effective resource adequacy framework if the ISO and the CPUC and the CEC do not have that shared sense of tremendous urgency and focus and collaboration,” CAISO CEO Elliot Mainzer said in an interview last year. “We have to work well together.”
Schori’s appointment followed her service as a NERC trustee for 12 years, the maximum allowed. She was termed out earlier this year.
From 1984 to 2008, Schori worked for the Sacramento Municipal Utility District, one of the nation’s largest municipal utilities, including as its CEO and general manager, general counsel and staff attorney. She graduated from the University of California Davis School of Law.
Leslie, whom Newsom named to the CAISO board two years ago, was the longtime president of the Los Angeles Business Council, a one-time deputy mayor of Los Angeles and a former commissioner at the Los Angeles Department of Water and Power.
Houck, another UC Davis graduate, has been chief counsel at the CEC since 2019. She was an administrative law judge at the CPUC from 2016 to 2019 and staff counsel at the CEC from 2000 to 2005. She worked in a private law firm between her stints of government service.
Siva Gunda, a deputy director at the Energy Commission, was named a CEC commissioner. | California Energy Commission
Gunda served as deputy director of the Energy Assessments Division at the CEC since 2018 and was office manager of the commission’s Demand Analysis Office in 2017-2018. He previously worked at the UC Davis Energy and Efficiency Institute, including as director of research for two years and as a program manager for four years prior. Gunda holds a master’s degree in mechanical and aeronautical engineering from Utah State University.
After he was sworn in Tuesday morning, Gunda — who, commissioners said, is known for giving credit to others — thanked his fellow staff members at the CEC for their “collective success” and hard work pursuing the state’s clean energy goals and helping determine the causes of last year’s rolling blackouts. (See CAISO Issues Final Report on August Blackouts.) Their joint efforts culminated in his appointment, he said.
“The staff at the Energy Commission are one of the most passionate, committed and intellectually honest group of people that I’ve ever met,” Gunda said after he was sworn in Tuesday morning. “It’s been an absolute honor and pleasure.”
Drones have the potential to revolutionize utilities’ information gathering and grid resilience, far outweighing the time and expense of adopting the new technology, according to speakers at the National Association of Regulatory Utility Commissioners’ Winter Policy Summit on Tuesday.
“This technology is a game changer. … The time and ease and even the cost [of inspection] is much improved using the [drone] technology at our disposal,” Duquesne Light Co. COO Kevin Walker told a panel on “Emerging Technologies for a Resilient Grid.”
Clockwise from top left: D.C. PSC Chair Willie Phillips; Andy Abranches, PG&E; Kevin Walker, Duquesne Light Co.; and Drew McGuire, EPRI | NARUC
Drones Capture ‘Impossible’ Shots
Duquesne has been using drones since 2018, and their benefits are already obvious, according to Walker. He described the unmanned aerial vehicles creating topographical maps of landslides to assist in recovery planning. The maps they develop can tell operators whether vehicles will be able to access the affected locations.
The utility has also sent drones on inspection trips into unstable tunnels where workers can’t be sent for fear of collapse, and to take photos of conduits on the underside of bridges that would be “nearly impossible to get with normal, conventional methods.”
A photo of the underside of a bridge, taken with a drone, that would be “nearly impossible” to capture by other means | NARUC
The devices have become just as valuable in California, according to Andy Abranches, senior director of special projects at Pacific Gas and Electric. Abranches recalled the utility’s efforts to inspect the entire transmission system in the wake of 2018’s Camp Fire, which investors said began with equipment that PG&E had made little effort to inspect and repair for nearly 90 years. (See “Reduced Inspections,” Ancient C Hook, Financial Manipulation Caused Camp Fire.)
To aid in the massive inspection effort, PG&E turned to aerial photography from both helicopters and drones. This gave inspectors a wealth of information, which turned out to create its own problems.
“The field of view and the angles that you get from using helicopter aerials, as well as drones, really enriches the inspection process. But all of that comes at a pretty significant cost [of] a huge volume of inspection photos,” Abranches said. “Just in a two-year period, we got over 4 million inspection photos … and [when] we have someone in the back office … reviewing that information, [it’s] very cumbersome.”
Humans Always Needed
PG&E’s solution was an internal project called the Sherlock Suite, which combines a repository for images with a set of models designed to automatically sort them into searchable categories. Similar images can be grouped together for mass inspection, and pictures of a particular location can also be viewed on a timeline so that when a problem is found, inspectors can cycle back through earlier photos to discover when it first emerged.
PG&E’s Sherlock Suite, an AI-enabled tool for storing, sorting, and analyzing aerial photos | NARUC
Building this tool has taken more than two years, and while Abranches said the team has made a strong product, “training” the artificial intelligence to recognize and sort the images reliably is likely to take far longer. The Sherlock Suite is expected to improve over time thanks to its machine-learning capabilities, but panelists agreed that humans always need to be in the loop. Ideally, the system’s organic and technological components will build on each other’s strengths.
“Any superpower can be overplayed. … Nothing can be 100% accurate all the time, and there [are] embedded biases … in our technology,” Walker said. “So we have to create that check and balance. … That’s why we have people like data scientists coming into our industry in more numbers than we ever have before, because they know how to analyze that data and [detect] anomalies that the naked eye … can’t see.”
Asked about security for these databases — which could include images of people who were unaware their pictures were being taken — participants acknowledged that this issue has to be a priority. Drew McGuire, senior program manager of distribution for the Electric Power Research Institute, recommended that planners follow their instincts for caution and never assume any system is invulnerable.
“When we design a system, when we design a distribution line, we don’t know exactly what’s going to happen … but we know eventually this line will be stressed,” McGuire said. “We can think of cyber in kind of a similar approach. We may not know the exact vector that’s going to be used … [but] eventually there’s a potential that they’re going to be stressed. And we need to … design them in that kind of way, where you assume that at some point you’re going to have to respond and react.”
