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NREL report highlights how electrification increases the need for demand flexibility

June 5, 2021

by Peter Maloney
APPA News
June 5, 2021

Demand-side flexibility can support widespread electrification and a renewables-based power grid by providing operating reserves throughout the year thus reducing the need for natural gas plants and energy storage to fill in demand gaps, according to a new report from the National Renewable Energy Laboratory (NREL).

Increasing demand-side flexibility reduces the number of low-load hours for fossil fuel generators and reduces the number of starts and shutdowns of natural gas generators, resulting in up to $10 billion in annual operating cost savings in scenarios with the greatest demand-side flexibility, according to the report, Operational Analysis of U.S. Power Systems with Increased Electrification and Demand-Side Flexibility.

The report is the sixth and final in NREL’s Electrification Futures Study (EFS) that was launched in 2017 to explore the potential impacts of widespread electrification in all U.S. economic sectors.

The EFS researchers found that demand-side flexibility—mainly from optimized vehicle charging and flexible operations of end-use equipment in buildings and industry—can alleviate the challenges of operating a highly electrified power system with high levels of variable renewable generation.

Shifting load to align with wind and solar generation reduces the risks of unserved energy and the curtailment of renewable resources, NREL said, adding that the complementary relationship between flexible electric vehicle charging and solar generation is particularly pronounced.

In modeled scenarios with high electrification and high variable renewables, demand-side flexibility can lower annual carbon dioxide (CO2) emissions by 8.3% by enabling greater utilization of renewable energy and avoiding fossil fuel consumption, the studies found.

For the EFS project, NREL analysts ran simulations of the national power system, using hourly operations, operational costs, and emissions to study the interactions between different levels of electrification, demand-side flexibility, and renewable energy deployment.

The analysts examined hourly power system operation without demand-side flexibility to test whether electrification — and associated changes in annual energy demand, hourly demand, operating reserve requirements, and the capacity mix — affects the grid’s ability to serve load or operating reserves.

The simulations showed the future power systems envisioned in the EFS can serve nearly 100% of load and 100% of operating reserves with no demand-side flexibility, but energy storage would be critical to balance load and provide operating reserves. Expanded power transfer capability across regions would also be needed to meet increased electrified demand.

The results showed “the importance of all sources of grid flexibility — including transmission and inter-regional power transfers, flexible generation, storage, and demand-side sources of flexibility — will likely be important for operating a power system with high electrification and high renewable energy deployment,” Trieu Mai, NREL analyst and EFS principal investigator, said in a statement.

In the final EFS report, NREL analysts examined how flexible loads change system operations with electrification.

They found that by shifting the timing of electricity demand, demand-side flexibility can provide operating reserves throughout the year, reducing the need for other generation sources such as natural gas plants and energy storage.

“Ultimately, the analysis highlights the value of increased integration and coordination of demand- and supply-side resources in future electric system planning and operations—particularly under high electrification futures,” Ella Zhou, NREL analyst and lead author of the final report, said in a statement.

The NREL analysts also noted that additional research is needed on flexible load operation, cost, and value across a wide range of subsectors and end uses, including assessments of grid reliability in a highly electrified system.

NREL has scheduled a June 17 webinar to discuss the findings of its EFS project and the need for further study.

NYPA providing $39 million for New York City electric bus chargers

June 5, 2021

by Peter Maloney
APPA News
June 5, 2021

The New York Power Authority (NYPA) said it has finalized a $39 million agreement to install 67 overhead chargers for New York City buses.

Under the agreement, NYPA will provide and install 66 overhead chargers capable of charging a total of 60 buses at four Metropolitan Transit Authority (MTA) depots in Staten Island, Brooklyn, Queens, and Manhattan, as well as an overhead on-street “pantograph” charger at Williamsburg Bridge Plaza in Brooklyn.

A pantograph charger is mounted on an overhead, on-street structure that mates with electrical contacts on a bus’ roof. It provides enough charge during drivers’ rest periods to keep the bus operating for two shifts per day.

Installing chargers overhead allows them to operate with buses from a variety of manufacturers.

The new infrastructure will help support the MTA’s commitment to purchase only electric buses starting in 2028 and to have an all-electric 5,800-bus fleet by 2040. It also supports New York Gov. Andrew Cuomo’s goal of having the five largest transit operators in the state electrify their transit fleets by 2035.

MTA and its local operator, New York City Transit, has about 25 electric buses and funding approval for another 500 electric buses in the agency’s 2020-2024 capital plan.

In late May, the MTA said it plans to purchase 60 electric buses this year, a 33 percent increase over its previous plan to purchase 45 electric buses.

Design and engineering work on the overhead chargers at the bus depots began last month.

Construction is expected to begin this fall, with the project expected to be completed within a year so that the chargers will in operation when the MTA’s next round of electric bus purchases arrives in third-quarter 2022.

ABM and Verdek have signed contracts to help complete the project. The charging hardware is being supplied by ABB and Siemens.

The overhead chargers at the depots will have power levels ranging from 150 kilowatts (kW) to 300 kW. The on-street charger will have a power level of 500 kW.

“Modernizing our public transportation infrastructure is a significant step toward the full electrification of the transportation sector that will remove polluting vehicles from our roadways,” Gil Quiniones, NYPA president and CEO, said in a statement. “Together with the MTA, we will promote a cleaner environment, improve public health and ensure a sustainable future for all New Yorkers.”

Public power utilities are playing a key role in the electrification of public transportation.

Last October, the Seattle City Council approved Seattle City Light’s Transportation Electrification Strategic Investment Plan, enabling the utility to move ahead with its transportation electrification strategy, which includes customer-facing incentives and out-reach and electrification enablement, such as the development of infrastructure needed to support transportation electrification.

Los Angeles is also transitioning to an emissions-free bus fleet, and the Los Angeles Department of Water and Power is working with the city’s Department of Transportation (LADOT) and MTA Transit to coordinate deployment plans. LADWP has so far helped LADOT install 255 charging stations to support 510 electric buses by 2028 and has created a fleet rate structure for electric fleet vehicle charging.

In Vermont, Burlington Electric Department and Green Mountain Transit in January unveiled two electric-powered buses.

In Florida, Orlando’s transit agency, LYNX, added eight electric buses to serve fare-free downtown circular routes.

And in 2015, Seneca, South Carolina, became the first city in the country to have a totally electric bus system when it deployed five battery-electric buses and two fast charging stations.

Report sees role for small modular reactors in Washington State’s clean energy transition

June 2, 2021

by Peter Maloney
APPA News
June 2, 2021

Small modular nuclear reactors (SMRs) could play a key role in Washington State’s mandated transition to a clean energy economy, according to a new report by researchers at the Pacific Northwest National Laboratory (PNNL) and the Massachusetts Institute of Technology.

Washington’s Clean Energy Transformation Act, enacted in 2019, calls for the elimination of coal-fired generation by 2025, aims to reach carbon dioxide (CO2) neutrality by 2030, and requires that the state’s power sources must generate electricity without emitting greenhouse gases by 2045.

The phasing out of coal- and natural gas-fired generation, which supplied about 17 percent of the state’s fuel mix in 2018, will leave a roughly 5-gigawatt (GW) gap in generation capacity that SMRs could help fill, according to the report, “Techno-economic Assessment for Generation III+ Small Modular Reactor Deployments in the Pacific Northwest.”

The report analyzed five case studies combining two SMR technologies and three potential sites. The study evaluated deployment of NuScale-designed plants, each containing 12 SMR units delivering roughly 600 megawatts (MW) to 700 MW at three different sites, and deployment of GE-Hitachi (GEH)-designed SMR plants delivering roughly 300 MW at two different sites.

The first case analyzed deployment of NuScale SMRs at the Idaho National Laboratory in Idaho Falls, Idaho, as a potential site for the Utah Association of Municipal Power Systems’ (UAMPS) Carbon Free Power Project. In January, UAMPS and NuScale signed an agreement to facilitate the development of a nuclear plant at the site.

In May, the Grant County Public Utility District signed a memorandum of understanding with NuScale to evaluate the deployment of the company’s SMR technology in central Washington.

The second case looked at using NuScale SMRs at a site near Energy Northwest’s Columbia nuclear plant in eastern Washington.

The third case studied placing a GE-Hitachi SMR at the Idaho National Laboratory site using the same cost reductions as the NuScale plant. The fourth and fifth cases evaluated using NuScale and GE-Hitachi designs, respectively, at the Big Hanaford coal-fired plant in Centralia in western Washington that is scheduled to close its coal-fired units in 2025.

The analysis indicated that in a future CO2 free electricity sector deployment of advanced SMRs would be competitive with Levelized Costs of Electricity (LCOEs) in the range of $51 per megawatt hour (MWh) to $54/MWh for the NuScale design and in a range of $44–$51/MWh for the GE-Hitachi design.

Each of the three sites also provides additional advantages, according to the report. There is already existing infrastructure and a workforce trained in the operation of conventional and nuclear plants in place in eastern Washington, and the Centralia site has existing grid connections that could be tapped, as well as a workforce that could be shifted from the closing coal-fired units.

The authors noted that they used two different means of calculating LCOE. For NuScale, they used the company’s current design. For GE-Hitachi, they used that company’s design-to-cost methodology with target pricing that is being confirmed as the design matures.

The findings “show that advanced small modular reactors could be economically competitive in a future carbon-free electricity sector,” Ali Zbib, PNNL’s manager for nuclear power systems and a co-author of the report, said in a statement. “They’re well-suited to play an important role in an energy market that requires more flexibility.”

The report noted that advanced SMRs can operate continuously at full power to provide baseload energy or can follow power swings on the grid. The report also found that electricity demand in Washington can fluctuate significantly on a monthly, daily and even five-minute basis, noting that average daily demand in February 2019 varied by more than 2,100 MW.

The report also noted, however, that near-firm renewable resources, such as wind power coupled with energy storage, “may provide competition to SMR generation.” The report cited a 1-MW, 150-MWh storage system developed by Form Energy in Minnesota that will provide Great River Energy with dispatchable wind power.

And, given the relatively short development time for such projects “and their relatively inexpensive power, they may provide stiff competition to the longer permitting to generation time paths for SMRs.”

At current prices, the cost of long-term storage “is prohibitively high to keep the lights on using only variable renewable energy,” the report found.

Lithium ion batteries cost approximately $200 per kilowatt hour (kWh) for approximately 4 hours of storage, the authors noted. They cited a MIT study indicating that storage costs could need to be as low as $20/kWh for long-term storage to be feasible.

Nonetheless, renewable energy still suffers from its variability and, even with its comparably low cost compared with firm power alternatives, “it fails to provide the flexibility required to meet long duration periods when wind and sun are not providing adequate electricity,” the report said.

While wind and solar will play a critical role, phasing out carbon-emitting resources sparks the need for flexible, non-carbon-emitting sources, and “nuclear energy can be an integral part of a clean energy portfolio that will allow the state of Washington to meet its clean energy objectives,” Zbib said.

The report is available here.

California PUC realigns energy efficiency to increase equity and long-term focus

June 2, 2021

by Peter Maloney
APPA News
June 2, 2021

The California Public Utilities Commission (CPUC), in a late May decision, reformed its approach to energy efficiency programs to better align them with greenhouse gas (GHG) emissions reduction, support for customer equity, and long-term grid stability.

The decision, Docket #: R.13-11-005, changes how the goals for energy efficiency programs in the state are set and evaluated and the processes for setting those metrics.

The CPUC released the proposed decision in April.

The decision calls for a shift in energy efficiency goals to long-term GHG reductions and grid benefits and away from setting goals based on savings of kilowatt-hours, kilowatts, and therms. The new “total system benefit” metric, expressed in dollar value, takes lifecycle energy, capacity into account to better target “high value” load reduction and “longer-duration energy savings while being fuel agnostic,” according to the decision.

The decision also changes the way energy efficiency programs are measured, shifting cost effectiveness evaluations away from an assessment of energy efficiency portfolio-wide economic benefit to an approach that segments the portfolio into categories and evaluates each category based on the primary purpose of the program. The new method is aimed at supporting the continuation of programs that “serve important functions but whose benefits are not appropriately captured by cost effectiveness ratios.”

In terms of process, the decision replaces the 10-year business plan and yearly utility filings with the CPUC with a 4-year application that includes a strategic planning component.

The decision calls for Investor-owned utilities to file new energy efficiency program applications in February 2022 that will take effect by January 2024.

The CPUC said that this summer it would continue to work to improve energy efficiency programs through the consideration of new energy efficiency goals and the addition of details to the changes implemented in the new decision.

“This decision helps to continue California’s leadership in energy efficiency by reducing the conflict between cost-effectiveness and other equally or more important policy objectives that address equity and provide market support for our energy efficiency programs,” Commissioner Genevieve Shiroma said in a statement. “It further maximizes energy efficiency measures for longer duration greenhouse gas reductions in support of our integrated resource plan and in delivering grid benefits.”

Retail electric sales to rise this summer led by commercial, industrial demand: EIA

June 2, 2021

by Peter Maloney
APPA News
June 2, 2021

Retail U.S. electricity sales will be 1.5 percent higher this summer than last summer with much of the growth coming from the commercial and industrial sectors, according to new estimates from the Energy Information Administration (EIA).

The projections reflect an improving economy following the pandemic-related downturn in 2020, the EIA said in its Summer 2021 Electricity Industry Outlook, a supplement to the agency’s Short-Term Energy Outlook.

Based on economic forecasts from IHS Markit, the EIA expects U.S. 2021 GDP to grow by 6.2 percent. The EIA forecasts the rebound in economic activity will push retail sales to the industrial sector in June, July, and August to be 4.5 percent higher than in the same period last year.

The EIA also sees increased economic activity boosting commercial sector demand for electricity. The agency forecasts retail electricity sales to the commercial sector this summer will be 2.6 percent higher than last summer but still 3 percent less than in 2019.

At the same time, the EIA projects a small decline in residential sector retail electricity demand this summer with sales 0.9 percent lower than last summer, mostly because of milder weather forecasts from the National Oceanic and Atmospheric Administration. The projected decrease in retail sales will be offset somewhat by growth in the number of residential customers and by more people working from home than in past years, the EIA noted.

The EIA forecasts a 1.6 percent increase in the number of residential electricity customers in 2021 because of a rebound in household formation after the economic slowdown of 2020, but also forecasts a decline in the amount of electricity consumed by a typical home. The EIA expects electricity use per residential customer to average 1,090 kWh per month between June and August 2021, which would be 2.5 percent less than last summer.

Between June and August 2020, retail electricity sales across all sectors totaled 1,055 billion kilowatt hours (kWh), the lowest level since the summer of 2015. Retail electricity sales to the commercial and industrial sectors showed an even steeper decline, totaling 357 billion kWh last summer, the lowest level since 2004. While retail sales to the industrial sector last summer totaled 239 billion kWh, the lowest level since the 2009 recession.

Residential electricity sales, meanwhile, reached a record high, hitting 457 billion kWh between June and August 2020. Near record warm temperatures contributed to the rise, as did the fact that more people were working from home and spending more time in their homes as a result of COVID-19 stay-at-home orders and social distancing guidelines, the EIA said.

DOE releases interactive tool for tracking microgrids installed throughout the U.S.

June 1, 2021

by Paul Ciampoli
APPA News Director
June 1, 2021

The U.S. Department of Energy (DOE) on May 26 announced the release of a new, interactive tool for tracking microgrids installed throughout the U.S.

The DOE noted that a microgrid is a local grid with an independent source of energy capable of disconnecting or “islanding” from the utility grid. Microgrids improve resilience by allowing critical facilities to continue operating in the event of a utility-grid outage. For manufacturers and industrial facilities, microgrids can also help ensure delivery of the high-quality, reliable electricity necessary to maintain today’s increasingly digitized operations, DOE said.

The Microgrid Installation Database includes a comprehensive listing of the country’s 461 operational microgrids that provide a total of 3.1 gigawatts of electricity. The information, which is updated on a monthly basis, is presented in a tabular format to help users easily access and sort data, DOE said.

The site features an interactive map of microgrid installations across the U.S., he ability to filter and search for sites by technology, end-user application, generation and storage capacity, and operating year, and downloadable data files.

The database is available here.

The new Microgrid Installation Database is co-located with a Combined Heat and Power (CHP) Installation Database, which captures the nation’s CHP installations. CHP technologies allow facilities to generate on-site electric power and useful thermal energy from a single fuel source.

Public power utilities and microgrids

A number of public power utilities are actively pursuing or have completed microgrid projects.

Washington State Gov. Jay Inslee, a Democrat, recently visited a Snohomish County PUD (Everett, WA) microgrid site. The Arlington microgrid is currently undergoing testing and commissioning and should be fully operational in a few months.

Meanwhile, the first phase of the Virgin Islands Water and Power Authority’s (WAPA) plan to develop an 18-megawatt (MW) microgrid, complete with a battery storage system, for the west end of St. Croix, Virgin Islands, has received an initial allocation of federal funding, WAPA said on April 9.

Also in April, Chattanooga, Tenn., Mayor Andy Berke, EPB President and CEO David Wade, Chattanooga Police Chief David Roddy, and Chattanooga Fire Chief Phil Hyman confirmed that construction would soon begin on a new collaborative microgrid project between the City of Chattanooga and EPB. The project aims to increase resilience and redundancy of power supply to the city’s public safety agencies via on-site solar arrays, traditional backup generation, battery storage and a microgrid controller.

And in January 2021, Lincoln Electric System in Nebraska reported that it put a 29-megawatt (MW) microgrid in service at virtually no cost.

FERC orders firm to respond to FTR manipulation allegations

June 1, 2021

by Paul Ciampoli
APPA News Director
June 1, 2021

The Federal Energy Regulatory Commission (FERC) recently ordered GreenHat Energy LLC and its owners to explain why they should not pay a total of $229 million in civil penalties and disgorge nearly $13.1 million in unjust profits for alleged electric market manipulation.

In a report attached to FERC’s May 20 order to show cause, FERC’s Office of Enforcement staff alleges that the GreenHat parties violated the Federal Power Act and the PJM Interconnection LLC’s tariff and operating agreement by engaging in a manipulative scheme in the financial transmission rights (FTR) market.

The order directs GreenHat, John Bartholomew and Kevin Ziegenhorn to show why they should not be assessed civil penalties of $179 million, $25 million, and $25 million, respectively.

GreenHat, Bartholomew, Ziegenhorn and the estate of Andrew Kittell, who was the third owner of the company, also must explain why they should not be required to disgorge $13.1 million in unjust profits, plus interest. Issuance of the order does not indicate Commission adoption or endorsement of the staff report.

FERC noted that between 2015 and 2018, GreenHat acquired the largest FTR portfolio in PJM.  In June 2018, it defaulted on the portfolio, leaving other PJM members, including many utilities serving retail customers, to cover more than $179 million in losses over the next three years. At the time of its default in 2018, GreenHat had only $559,447 in collateral on deposit with PJM.

FERC Enforcement staff alleges that GreenHat’s conduct was unlawful in several ways. Among them are that GreenHat sent false price signals into the PJM market by purchasing FTRs based not on expected profitability but on which FTRs it could acquire with minimal collateral, GreenHat made deliberately false statements to PJM to try to avoid a collateral call and GreenHat rigged FTR auctions by using inside information about Shell Energy North America (US) LP’s offers (on the seller side of the auction) in designing its own bids for the same FTRs (on the buyer side of the auction). 

Although the alleged scheme generated enormous losses that were borne by all other PJM members, it was highly profitable for GreenHat’s owners, FERC said. 

Kittell, Bartholomew and Ziegenhorn realized that although GreenHat’s enormous portfolio was unprofitable overall, it included some “winners,” that is, FTRs that increased in value after GreenHat bought them.  GreenHat made four deals in which it sold winners to third parties for a total of $13.1 million in cash.

According to the Enforcement staff report, this alleged scheme is an example of a type of fraud in which perpetrators acquire assets with no intent to pay for them, and then try to turn the assets into immediate cash for themselves.

The GreenHat parties have 30 days to respond to the Commission’s order.

Commissioner Danly concurrence

In a concurrence on the FERC order, Commissioner James Danly said that he supports the Commission’s issuance of an Order to Show Cause. “As the primary regulator of PJM’s FTR market, the Commission has the responsibility to make an official public determination as to whether or not GreenHat’s default was the result of fraud or manipulation,” he wrote.

“But my support for the issuance of the Order to Show Cause is based solely on my belief that the Commission has the responsibility to issue an official pronouncement as to whether GreenHat engaged in fraud or manipulation. My support of this order should not be read as an indication that I have reached any conclusions at this time on the ultimate question of GreenHat’s liability.  I am issuing this concurring statement to provide some guidance to the parties as to what I believe would be helpful for them to address in their submissions in response to the show cause order,” he said.

Based on his review of the Enforcement Staff Report and Recommendation, Danly said he has questions and concerns about both Enforcement’s and GreenHat’s positions, which he details in his concurrence, which is available here.

FERC Chairman says Commission cannot keep changing ROE methodology

June 1, 2021

by Paul Ciampoli
APPA News Director
June 1, 2021

The Federal Energy Regulatory Commission (FERC) cannot keep changing its return on equity (ROE) methodology, FERC Chairman Richard Glick recently said in comments at a Commission meeting, adding that companies need to have some level of regulatory certainty if they are going to continue to make multi-million and, in some cases, multi-billion dollar investment decisions.

Glick made his remarks at FERC’s monthly open meeting on May 20 in the context of a Commission order that set a ROE for an Entergy unit power sales agreement.  The order employs the same methodology the Commission used when establishing the ROE for Midcontinent Independent System Operator, Inc.’s (MISO) transmission owners in Opinion Numbers 569-A and 569-B. 

Glick noted that when FERC issued Opinion Numbers 569-A and 569-B, he expressed concern about the Commission’s decision to add the risk premium model “because the first MISO ROE order had thoroughly explained why the risk premium model is not an appropriate tool for assessing a just and reasonable ROE.” While he continues to have his concerns, he also believes that FERC cannot keep altering its ROE methodology. 

FERC in May 2020 revised its method for analyzing the base ROE used in setting cost-based public utility transmission rates.  FERC’s reference to “public utility” refers to utilities that are subject to FERC’s rate jurisdiction under the Federal Power Act.

The changes adopted by the Commission through the issuance of Opinion No. 569-A are likely to result in higher allowed ROEs than would have resulted from the method outlined in Opinion No. 569 issued in November 2019 and could also make it more difficult to challenge existing ROEs as unjust and unreasonable. 

In Opinion No. 569, FERC said it will use the discounted cash flow (DCF) methodology and capital asset pricing model (CAPM) to determine if an existing base ROE is unjust and unreasonable, and, if so, what replacement ROE is appropriate. Applying the new methodology in a pair of complaints against MISO transmission owners, Opinion No. 569 determined that their base ROE should be 9.88 percent.

FERC’s order on rehearing revised the methodology established in Opinion No. 569 and found that the MISO transmission owners’ base ROE should be set at 10.02 percent.

In response to FERC’s decision, Glick concurred in part and dissented in part.

Commissioners offer dissent, concurrence

FERC Commissioner Mark Christie offered a concurrence to FERC’s May 20 order, while Commissioner Allison Clements dissented from the decision.

In his concurrence, Christie said that while the order “correctly applies the Commission’s ROE methodology set forth in Order No. 569 and its progeny, I believe that the Commission’s policy is flawed to the extent it replaces judgment with rote application of pre-set formulae and should be reviewed in a general proceeding to consider possible changes to that methodology.  Second, I believe the Commission can, and should, issue ROE orders much more expeditiously in the future and matters of procedure, including setting strict procedural deadlines for FERC itself to follow, should be part of any such future proceeding on the ROE issue.

Clements said that she agrees that the order reasonably applies the Commission’s return on equity ROE policy established in Order 569-A to the facts in these proceedings. “I dissent because I do not believe our existing methodology for setting ROEs in jurisdictional cost-based rates fully carries out our consumer protection responsibility under the Federal Power Act.  As a result, I cannot conclude that the ROE established in these proceedings is just and reasonable,” she wrote.

She said that FERC should revisit its existing ROE policy. “I appreciate that this policy has been unsettled for years, a state that increases investment uncertainty and extends litigation. To be sure, I share the goal of a stable ROE policy that will speed rate proceedings and allow for timely ROE updates as market conditions change. But we should not double down on the desire for near-term stability to strong detriment of consumer protection, and I worry our current ROE policy does just that.”

Poll finds strong support for the creation of a consumer-owned utility in Maine

May 31, 2021

by Paul Ciampoli
APPA News Director
May 31, 2021

Newly conducted public opinion polling shows that 75% of registered voters from across the state of Maine say they support the idea of replacing Central Maine Power and Versant with a local non-profit consumer-owned utility, according to research conducted by SurveyUSA.

According to SurveyUSA, 38% strongly support the idea; 37% say they somewhat support. Just 10% are opposed to the idea, while 7% somewhat oppose and 3% strongly oppose.

The research was conducted by SurveyUSA for a group call Our Power, which supports the creation of a consumer-owned utility in the state.

Support is strongest among 35-to-49-year-olds (85%). Support is higher in urban parts of Maine (81%) than in suburban (72%) or rural (62%) portions of the state. Even among those rural Maine residents with 62% support, the lowest support for the idea among any subgroup, 28% strongly support and 34% somewhat support the idea of creating a consumer-owned utility.

According to the poll, 82% of Versant customers and 74% of Central Maine Power customers say they support the idea.

“Opposition to the concept, while weak in general, does have a significant correlation with both age and with ideology,” SurveyUSA said. While just 4% of those under age 50 are opposed, 14% of those 50+ are opposed, and opposition among conservatives, at 16%, is notably higher than among moderates (6%) or liberals (5%).

SurveyUSA said that a few of the major reasons Maine residents may be so strongly supportive of the consumer-owned utility concept are:

Ursula Schryver, Vice President, Strategic Member Engagement and Education, at the American Public Power Association (APPA) recently appeared before a hearing held by Maine state lawmakers related to the bill.

She noted that there has been an increase in the number of communities exploring the public power option, a trend that has been driven by a number of factors including reliability, the desire for renewable energy options and increased economic development. Schryver, who made her comments at a May 20 hearing held by the Maine Legislature’s Energy, Utilities, and Technology Committee, also detailed the resources that APPA offers when it comes to municipalization.

The Maine committee hearing focused on a bill, LD 1708, which would create a consumer owned utility that would take over the electric service now provided by Central Maine Power and Versant Power. Central Maine Power Company and Versant Power (formerly known as Emera Maine), are majority owned by Iberdrola of Spain and Emera of Canada, respectively.

At the hearing, Schryver noted that her comments were neither for or against the legislation “primarily because APPA doesn’t weigh in on decisions made by individual communities.” APPA, she noted, serves as a resource and APPA believes that every community needs to make a decision that is right for itself.

Bill allows public power to receive refundable direct payment for energy tax credits

May 27, 2021

by Paul Ciampoli
APPA News Director
May 27, 2021

The Clean Energy for America Act (CEA), which includes a provision to allow public power to receive refundable direct payment for energy tax credits, is headed to the Senate floor after debate and amendment on May 26 by the Senate Finance Committee.

As amended, the CEA provides $260 billion in tax relief over the next decade and would replace the current investment tax credit (ITC) and production tax credit (PTC) with technology neutral ITCs and PTCs. As part of these revisions, the bill would allow merchant power generators, investor-owned utilities, public power utilities, rural electric cooperatives and Indian tribal governments to receive refundable direct payments of the ITC and PTC. The Joint Committee on Taxation estimates that roughly $50 billion of such payments would be made over the next decade.

The original bill would have denied access to refundable tax credits to public power utilities, rural electric cooperatives, and Indian tribal governments.

However, the American Public Power Association, the Large Public Power Council (LPPC), and National Rural Electric Cooperative Association (NRECA) joined in advocating for their inclusion. As a result, committee member Sen. Michael Bennet, D-Colo., offered a direct pay amendment that was eventually adopted as part of a broader package of amendments to the original version of the bill.

“We should make these tax incentives accessible to electric coops, public power companies, and tribes,” Bennet said during markup of the bill. “They are doing yeoman’s work to transition to clean energy and drive opportunity in rural America and we should support them.”

In a May 26 letter to Bennet, Joy Ditto, President and CEO of APPA, Jim Matheson, CEO of NRECA, and John Di Stasio, President of the LPPC, praised his amendment.

As drafted, the CEA “allowed some utilities to immediately receive the benefit of certain energy tax credits. With the inclusion of your amendment, it now also would allow public power utilities, rural electric cooperatives, and Indian tribal governments to do so. That would mean more local projects, with local jobs, under local control. Having direct ownership as an option also will help our members develop a generation mix that best suits the needs of the customers,” wrote Ditto, Matheson and Di Stasio.

Inclusion of refundable direct payment tax credits in the CEA means that leading proposals in the House (H.R. 848, the GREEN Act) and Senate are now in agreement on the issue. If enacted into final law, this would be the first time in the history of energy-related tax credits that public power utilities would truly have equal access to such credits.

Bennet’s amendment retains current law prohibitions on receiving tax credits for projects receiving “subsidized” financing, including tax-exempt financing. While final legislative text is not available, it appears the intention is to preclude the use of tax-exempt financing for a project that also receives energy-related refundable tax credits. But analysis done by APPA and others shows that the value of the investment tax credit and production tax credit substantially exceeds the cost of losing the ability to issue tax-exempt debt to finance such projects.

In addition, “Chairman’s Modifications” to the CEA from Sen. Ron Wyden, D-Ore., Chairman of the Senate Finance Committee, struck a provision that would have allowed public power utilities and rural electric cooperatives to issue taxable direct payment Clean Energy Bonds (CEBs). While such bonds could have been highly valuable for long-lived assets, many of the assets that utilities will invest in in the near term – including battery storage and wind turbines – have shorter useful lives.