The U.S. microgrid market reached 10 gigawatts in the third quarter of 2022, with more than 7 GW in operation and the rest in planning or construction stages, according to a new analysis from Wood Mackenzie.

“In terms of customer segments, Commercial and Industrial leads the way with significant project development in industries such as retail (department stores) and manufacturing, which indicates a rise in demand for an uninterrupted electricity service,” said Elham Akhavan, senior research analyst at Wood Mackenzie. “The government sector takes second place, driven by the military’s resilience and decarbonization targets, followed closely by the residential and education sectors,” Akhavan added.   

The U.S. microgrid market has seen a 47% increase in solar and storage capacity in 2022 compared to 2017 levels. Moreover, Wood Mackenzie data shows that more than 175 solar- and solar-plus-storage microgrid projects have been in active development and were scheduled to come online by the end of 2022.

Akhavan said: “There’s been a significant shift in technology type, in particular the rise of solar and storage demand among microgrid customers, largely driven by corporate ESG goals. This has triggered an uptake of multi-distributed energy resource microgrids – known as advanced microgrids – which are used in cases where solar and storage alone are insufficient to mitigate long-duration outages. A fossil fuel generator, often sized to cover the entire site, acts as backup for the solar and storage to ensure uninterrupted service when the grid is down.”

The turnkey microgrid-as-a-service business model is projected to experience continued growth across various non-utility customer segments. The influx of diverse investors eager to finance long-term projects, often with ESG attributes, has led to the dominance of the microgrid-as-a-service model. Simultaneously, the industry is seeing a gradual shift away from end-user ownership, the consulting firm said.

According to Wood Mackenzie’s data, the percentage of microgrids owned by end-users dropped 31% from 2019 to Q3 2022, while the share of MaaS deals grew 25% over the same period.

While third-party financing in general is not a new model, microgrid-as-a-service “is evolving beyond PPA contracts, which often involves procurement from a single DER to an affordable solution for financing the construction, operation and maintenance of multiple DERs, tailored to the customer’s energy objectives,” Akhavan added.

Wood Mackenzie data shows that there are 28 states with utility microgrids, with approximately 35 megawatts expected to have come online in 2022. This implies total utility microgrid capacity of over 1.1 GW. 

“From a microgrid capacity perspective, if the market continues to develop at a rapid pace, we will see more than 20% growth in annual capacity installation across the US compared to last year,” Akhavan said

“The West coast, led by California, is growing substantially, with a strong pipeline due to go into operation by 2024. This is followed closely by the Southwest market which has expanded more than three times since 2019. Texas is the frontrunner, with two of the leading developers in the region, PowerSecure and Enchanted Rock, having installed all capacity so far in 2022,” Akhavan added.   

The industry has also seen growth in the Northeast where a range of competitive grant programs are supporting resilience projects for critical facilities. However, recovery from the COVID-19 slowdown is uneven across regions in the US. For example, the Southeast has yet to recover to pre-pandemic growth.

Switching to cost based or cost reflective utility rates would make heat pumps competitive with natural gas heating and speed electrification, according to a new report.

The report, Heat Pump-Friendly Cost-Based Rate Designs, was done by Brattle Group for the Energy Systems Integration Group, a nonprofit organization that marshals the expertise of the electric industry’s technical community to support grid transformation and energy systems integration and operation.

In the white paper, the Brattle analysts analyzed a proprietary dataset of natural gas and electricity usage for 80 single-family residential customers of a large investor-owned utility with relatively high electricity rates and cold winters.

The analysis showed that the operating cost gap was positive, that is, the cost of operating heat pumps was higher for all 80 customers under default electricity rates than the cost of using natural gas-fired heating systems.

Heat pumps are more efficient than natural gas-based heating systems and their costs are expected to decline over time, but right now heat pumps are often more expensive to install and operate, the report noted.

However, the analysis also showed that cost based rate designs can improve the economics of heat pumps by making electric heating bills lower than natural gas heating bills.

“Moving to one of the three alternative rates flips all 80 customers from a positive cost gap to a negative cost gap, in which energy costs for operating the heating equipment are lower post-electrification,” the authors wrote.

Under rate II, the first alternative rate studied – rate I was the default rate – the fixed charge component of a customer’s bill was increased and the volumetric charge was lowered. The result was a reduction in customer heating bills sufficient to turn the operating cost gap negative for all customers.

Switching to a time of use day/night structure (rate III) or a demand-based structure (rate IV) resulted in even larger negative operating cost gaps with rate IV showing the largest reductions in electric heating bills for the sample of 80 single-family residential customers, the report found.

“These results reflect the fact that all of the alternative rate designs are better aligned with the marginal cost of generating and delivering power, compared to the default residential rate design, which typically is not,” the authors said. “In many jurisdictions across the country, retail electricity prices are largely disconnected from the marginal costs.”

The authors also noted that there was a large variation both geographically and temporally. “To the extent that retail prices are above the short-run marginal costs because a large portion of the fixed costs of delivering power are also collected through volumetric rates, this creates a distortion in price signals and leads to suboptimal levels of electricity consumption and adoption of new customer sited technologies,” they said.

One of the unintended consequences of such default electric rates, the report found, is the slower adoption of heat pumps because the use of heat pumps increases total electricity consumption and, therefore, electricity bills, making the use of heat pumps uneconomic under typical volumetric default rate structures.

The authors noted, however, that as electric system conditions evolve, and summer-peaking systems become winter peaking systems with increasing levels of building electrification, rate structures may need to be refreshed if they are to continue to reflect actual costs.

While alternative rates can make adoption of heat pumps more economic for many customers, the report’s authors said it is important to note the implications of those rates for customers’ other electric loads.

For some of the customers in the sample, switching to time-of-use rates (rate III) would increase their electricity bills by about $200 per year even before any electrification, the report found. For some other customers, switching to one of the demand-based rates would reduce their bills by about $100 per year before electrification.

The report recommended that utilities develop screening tools to determine which customers might benefit from alternative rates and market those rates accordingly. The report also recommended that utilities develop data analytics tools to identify customers who may be getting close to replacing their heating systems and contact them before they make an investment decision.

Texas public power utility CPS Energy has reached agreements with three companies for solar capacity, firming capacity and energy storage capacity, closing out the utility’s FlexPOWER Bundle initiative stemming from a request for proposals that was launched in 2020.

In total, the FlexPOWER Bundle will deliver 580 megawatts of solar, 50 MW of storage, and 500 MW of natural gas firming capacity.

Calpine will provide a total of approximately 500 MW of firming capacity located in Guadalupe County at the Guadalupe Energy Center. The Calpine agreement will make power available to CPS Energy in the Spring of 2023.

Ahstrom Renewable Energy, in collaboration with OnPeak Power, will provide 100 MW of the El Patrimonio solar project, which will be located in Bexar County.  The power purchase agreement is a 20-year contract with an anticipated commercial operation date of May 2025.

Additionally, as part of the agreement, Ashtrom Renewable Energy will provide community benefits, including the contribution of funds towards CPS Energy student scholarships, as well as on-site field day mentorship to local students during the construction of the facility in Bexar County. Ashtrom Renewable Energy will also grant funds towards the construction of an outdoor classroom that can be used for field trip instruction.

Eolian L.P. will provide San Antonio-based CPS Energy the exclusive right to dispatch a 50 MW, 2-hour duration energy storage project located in Bexar County. This location, combined with the operating flexibility offered by energy storage, will further improve CPS Energy system resiliency as well as customer reliability, the utility said. The agreement is a 20-year contract with an anticipated commercial operation date of December 2024.

CPS Energy will issue a new and separate RFP in the first quarter of 2023 to procure up to an additional 320 MW of solar, to include community solar proposals, to add to its generation portfolio.

In 2022, CPS Energy successfully executed agreements for 300 MW of solar capacity with Consolidated Edison Development Inc. and 180 MW with Ashtrom Renewable Energy.

Vermont has become the seventh state to sign on to develop a proposal for a Northeast Clean Hydrogen Hub.

Vermont joins Connecticut, Maine, Massachusetts, New Jersey, New York, and Rhode Island, along with 100 clean hydrogen ecosystem partners, in their efforts to develop and submit a proposal to the Department of Energy to compete for $8 billion in funding to become one of up to 10 regional clean hydrogen hubs designated under the federal Regional Clean Hydrogen Hubs program included in the bipartisan Infrastructure Investment and Jobs Act.

The seven states and their partners will continue to focus on the integration of renewables, such as onshore and offshore wind, hydropower, photovoltaic solar power, and nuclear power into clean hydrogen production, and the evaluation of clean hydrogen for use in transportation, including for medium- and heavy-duty vehicles, heavy industry, and power generation applications.

The Northeast Clean Hydrogen Hub partners have committed to collaborate with the New York State Energy Research and Development Authority (NYSERDA), New York Power Authority (NYPA), and Empire State Development (ESD) on proposal development to advance clean hydrogen projects.

Partnering states will also coordinate with their respective state entities to help align the collaborative’s efforts with each state’s climate and clean energy goals.

Those include:

• Connecticut’s Global Warming Solutions Act goal of reducing greenhouse gas emissions 80 percent by 2050

• Massachusetts’ goal of reaching net-zero carbon emissions by 2050

• New Jersey’s Global Warming Response Act goal of reducing greenhouse gas emissions 80 percent by 2050

• Maine’s statutory goals to achieve carbon neutrality by 2045 and reduce gross greenhouse gas emissions by at least 80 percent by 2050

• Rhode Island’s commitment to achieving 100 percent renewable electricity by 2033 and

• Vermont’s Global Warming Solutions Act goal, which requires the state to reduce greenhouse gas pollution 80 percent below 1990 levels by 2050

A report available to members of the American Public Power Association offers details on where the emerging hydrogen market is in the U.S. and globally, what is driving the growing interest in hydrogen and what obstacles are preventing hydrogen technology from being able to scale-up. The report is available here.

The Los Angeles Department of Water and Power’s greenhouse gas emission reduction targets have been certified to be in line with a trajectory that is well below a 2° centigrade increase above pre-industrial levels.

Los Angeles Department of Water and Power registered its greenhouse gas targets with the Science Based Targets initiative (SBTi), a global body that assesses GHG reduction targets to determine if they in line with the latest climate science.

The SBTi has established a set of criteria that all targets must meet in order for them to be validated as science-based.

In the evaluation, SBTi looks at “scopes” that determine the types of GHG emissions to be reduced. Scope 1 refers to direct GHG emissions. Scope 2 refers to energy purchases from a third party. Scope 3 refers to the purchase of goods and services other than energy from a third party, such as processing of sold products, capital goods, and employee commuting.

SBTi is a coalition of non-profit organizations including Carbon Disclosure Project, the United Nations Global Compact, World Resources Institute, and the World Wide Fund for Nature.

SBTi’s assessment showed that LADWP’s targets would reduce organization-wide emissions 69.3 percent by 2030 from a 2015 baseline, while providing approximately 21 percent more energy relative to 2015.

LADWP said that within its own operations, it plans to focus on reducing scope 1 and 2 GHG emissions by 71.6 percent per megawatt hour of electricity generated by 2030 from a 2015 base year; reducing scope 1, scope 2, and scope 3 fuel- and energy-related activities related to sold electricity GHG emissions by 78.1 percent per MWh of electricity sold over the same target timeframe; and reducing absolute scope 3 fuel- and energy-related activities not related to sold electricity GHG emissions by 37.5 percent over the same target timeframe.

LADWP said it is the first municipally owned utility in North America to establish science-based emission reduction targets.

LADWP is a signatory to several international principles and initiatives, including the Carbon Disclosure Project, and has participated in CDP’s Climate Change program for six years, earning an A- grade in the CDP’s Climate Change Score Report.

Reliability and affordability for U.S. electric utilities and their customers could be threatened under a Department of Energy Notice of Proposed Rulemaking related to energy conservation standards for distribution transformers, the American Public Power Association and the National Rural Electric Cooperative Association recently told the Department of Justice.

The DOE’s NOPR would transition almost the entire distribution transformer market in the U.S. to use amorphous steel cores, but there is only one domestic producer of amorphous steel cores today and that producer’s current output “is a mere fraction of what would be required to adequately meet the electric utilities’ demand,” the groups said.

“Our members are some of the primary consumers of distribution transformers and if this proposal is implemented as currently contemplated, it would have serious consequences on their ability to provide affordable, reliable electric service to millions of Americans,” APPA and NRECA said in Feb. 10 comments submitted to DOJ.

“We urge DOJ to fully consider the competition issues raised by the DOE NOPR and work with DOE to address these concerns before a final rule is issued by DOE,” the groups said.

As drafted, DOE’s NOPR would transition almost the entire distribution transformer market in the United States to use amorphous steel cores, as compared to the current widespread use of grain-oriented electrical steel (GOES) cores, APPA and NRECA told DOJ.

“We have numerous concerns about the proposal, but within the DOJ Antitrust Division’s purview, we specifically raise (1) the lack of domestic suppliers available to produce amorphous steel cores and (2) the untenable timeline in the proposal,” the groups said.

Despite the insistence in the NOPR that its effects go into place in 2027, it has immediate market implications, APPA and NRECA said.

“There is only one domestic supplier of GOES and this proposal risks putting the domestic electrical steel market in a precarious state. Rather than helping to diversify supply, the DOE NOPR is counterproductive as it would deter further domestic investment in GOES production because only amorphous steel cores would be able to meet the new energy conservation standard proposed by DOE,” they argued.

APPA and NRECA said that the NOPR will not foster competition and is instead likely to create a new monopoly supplier while simultaneously driving the existing GOES supplier out of the market. “This would create a ripple effect of likely killing further investment in the domestic production of GOES for distribution transformers under consideration or announced by other steel producers.”

The groups also have serious concerns about whether the only domestic producer of amorphous steel cores today “would even be able to meet electric utilities’ demand for distribution transformers.”

They pointed out that the only amorphous steel core producer’s output today “is a mere fraction of what would be required to adequately meet the electric utilities’ demand, raising serious implications for electric reliability and affordability. As currently drafted, the NOPR relies on a single supplier in the market to ramp up output to meet the demand in just three years.”

In addition, APPA and NRECA said that the labor shortages currently facing many U.S. industries today, including distribution transformer manufacturers, make it very unlikely that domestic production of amorphous steel cores will ramp up to the level that DOE assumes in the NOPR.

“We have serious doubts about the ability of one supplier to increase output in the timeline envisioned in this proposal. If this NOPR is finalized as drafted, and the sole supplier cannot meet the demand, manufacturers will be forced to source their material from international sources (particularly China) representing a significant national security risk to the United States,” APPA and NRECA said.

The NOPR would not increase the diversity of steel suppliers in the market, “but would rather drive out the lone GOES supplier in favor of an amorphous supplier because the new efficiency standards will drive nearly all distribution transformer manufacturing away from GOES,” the groups said.

The current manufacturing base serving electric utilities is struggling to meet demand and DOE’s NOPR exacerbates this ongoing crisis, APPA and NRECA said.

“Our members are facing unprecedented challenges securing equipment and material to provide reliable electric service to their customers. Electric utilities have been sounding the alarm for more than a year about the supply chain constraints around multiple types of equipment they require to keep the lights on, with distribution transformers being the most acute challenge.”

They noted that it now takes more than a year on average for utilities to receive distribution transformers, compared with 60 days just a couple years ago.

“Further, we expect the backlog to continue to increase absent U.S. government support as utilities invest in grid resilience and modernization projects and federal and state policies drive more electrification. With that backdrop, DOE’s NOPR sends the wrong signal at a critical moment when we need more investment in production capability right now and for the next several years to meet growing demand.”

A proposal of this magnitude requires more time and analysis to avoid unintended consequences, APPA and NRECA said.

“At a minimum, DOJ should work with DOE to better understand the competition implications raised by the DOE’s NOPR and take the requisite time to ensure that we do not create unintended consequences that will be detrimental to electric reliability and affordability, as well as U.S. national security.”

The Western Power Pool on Feb. 10 announced that the Federal Energy Regulatory Commission has approved the tariff for the Western Resource Adequacy Program, clearing the way for full implementation of the region’s first West-wide reliability program.  

In its ruling, FERC underscored the importance and potential benefits of a regional program and the enhanced reliability and resource adequacy that WRAP would bring. “Through increased coordination, we find that the WRAP has the potential to enhance resource adequacy planning, provide for the benchmarking of resource adequacy standards, and more effectively encourage the use of western regional resource diversity compared to the status quo,” the order noted. 

The WPP board of directors will meet this week to review the order and to officially clear the final hurdle for WRAP operations under the tariff. In short order, the WPP will make the governance changes required by the tariff, which includes seating a new independent board of directors identified in 2022.  

 In December and January, WPP received formal commitments from 20 utilities to move forward with the WRAP. Representatives from several of those utilities also applauded FERC’s ruling. 

 WRAP participants engaged in the first non-binding forward showing program as part of program implementation in 2022, and the first non-binding operational phase of the program will kick off this summer as scheduled. 

Utilities from the northwest, parts of the desert southwest, Canada and northern California are expected to be part of the WRAP’s overall footprint. 

A number of public power entities are participating, including Bonneville Power Administration, Chelan County PUD, Clatskanie PUD, Douglas County PUD,  Eugene Water and Electric Board, Grant County PUD, Salt  River Project, Seattle City Light, Snohomish County PUD, Tacoma Power, and Turlock Irrigation District.

The U.S. Department of Energy on Feb. 8 announced a funding opportunity of up to $74 million for up to seven pilot projects that will test the efficacy and scalability of enhanced geothermal systems.

“Through this investment, DOE hopes the research and development from the findings would demonstrate the growth and ultimate potential for geothermal energy to provide reliable, around-the-clock electricity to tens of millions of homes across the country,” DOE said.

This is DOE’s first funding opportunity for geothermal energy since the launch of the Enhanced Geothermal ShotTM , part of DOE’s Energy EarthShots Initiative, which seeks to cut the cost of geothermal energy 90% by 2035. 

Geothermal energy currently generates about 3.7 gigawatts of electricity in the United States, but a new analysis shows it could provide 90 gigawatts of firm, flexible power to the U.S. grid by 2050, as well as heating and cooling solutions nationwide. This substantial geothermal energy potential is, however, largely inaccessible with conventional geothermal technologies, DOE said.

Applications for the pilot demonstrations will be accepted over multiple rounds. First-round letters of intent are due March 8, 2023, and first-round applications will be due July 7, 2023. 

DOE is providing a voluntary Teaming Partner List where interested parties can provide contact information and their expertise for use in forming partnerships in order to help a broad and inclusive range of interested entities apply.

Click here for additional details on the funding opportunity.

The Utilities Board of Tuskegee in Alabama played a major role in the decision by Samkee Corp., a major South Korean automotive supplier, to invest $128 million to open its first U.S. factory in Alabama.

Samkee’s decision to locate the factory in Tuskegee was announced by Alabama Gov. Kay Ivey on Feb. 10.

The Samkee project that will create 170 jobs in Tuskegee.

After finalizing agreements with state and local authorities, Samkee is poised to begin construction on the new manufacturing facility in the Tuskegee Commerce Park, where it will become the city’s first auto parts manufacturer.

Samkee will serve as a Tier 1 supplier to Hyundai Motor Co.

The Utilities Board of Tuskegee General Manager Gerald Long said he looks forward to deepening the partnership with Samkee.

“Our utility will serve power, water and sewer to the industry,” said Long in a news release. “Their presence in our community will allow us to expand our system and resources to better serve them and all of our customers at an even higher-level of reliable service. We are proud to be a full partner in economic development countywide.”

In an email to Public Power Current, Long noted that about a year ago, he was a part of a delegation that traveled to South Korea to meet with Samkee’s CEO and tour their facilities.   

“We helped craft the project agreement, which included the Utilities Board agreeing to build a new 28-megawatt substation and assist in the development of a 44-acre pad-ready site for the $128 million facility,” he said. “We are also expanding our Water and Wastewater facilities to serve the new development.”

Samkee’s manufacturing plant is expected to have a significant economic impact on Macon County, Ala., according to an analysis by the Center for Business and Economic Research at the University of Alabama.

The analysis projects that the Samkee factory will generate $140.2 million in annual economic output in Macon County, contributing over $37 million to the county’s GDP while also generating $1.3 million per year in taxes.

The American Public Power Association’s (APPA) Demonstration of Energy & Efficiency (DEED) Program on February 3, 2023, appointed Rodney Bourne, General Manager at Rolla Municipal Utilities (Missouri), to fill a vacant seat on the program’s board of directors. Bourne will serve as the director representing Region 3, comprising Iowa, Kansas, Minnesota, Missouri, Nebraska, North Dakota, and South Dakota, until fall 2024. As one of ten regional DEED program directors, Bourne will act as a resource to help utilities refine grant applications prior to the advisory board’s review, in addition to contributing to funding and policy decisions for the program.

Region 10 Director Seat Opening

The DEED program is also currently seeking to fill a director position to oversee Region 10 (at-large seat). The director will represent DEED members in and outside the United States. The nomination deadline for this seat is March 6, 2023, and the form can be accessed here.

For any questions regarding the DEED program or board of directors nominations, please email DEED@PublicPower.org.