The Electric Highway Coalition (EHC), a group of electric utilities working together to install fast-charging EV stations along major interstate highways, has doubled its members.
Membership in the EHC has now grown to include AVANGRID, Consolidated Edison, DTE Energy, Eversource Energy, Exelon, FirstEnergy Corp., ITC Holdings Corp., and National Grid. Formed in March 2021, EHC began its membership with American Electric Power, Dominion Energy, Duke Energy, Entergy Corporation, Southern Co., and the Tennessee Valley Authority.
Eversource joins Electric Highway Coalition to expand EV charging across the US
New Electric Highway Coalition plans to connect US Gulf Coast, Midwest and Atlantic State destinations via fast chargers
Duke Energy, MidAmerican, Liberty and Midwest Energy join Ameren-led EV charging initiative
Together, the 14 members — representing 29 states and the District of Columbia and serving more than 60 million customers — are committed to growing EV charging solutions along major transportation corridors within their service territories and working with other members to enable convenient charging options and seamless travel routes for EV drivers.
In addition to expanding membership, the EHC has further defined its goals and is pursuing shared objectives. The members have agreed to work together to ensure efficient and effective fast charging deployment plans that enable long distance EV travel, avoid duplication among coalition utilities, and complement existing corridor fast charging sites. Ideally, EHC members are pursuing sites that are easily accessible for drivers located less than 100 miles apart.
The EHC is also committed to providing a positive charging experience for drivers, including having at least two charging stations with universal vehicle compatibility, and additional features where feasible, such as real-time status reporting for drivers and convenient payment collection.
DC fast charging stations are typically capable of getting drivers back on the road in 20-30 minutes. Member companies are working closely with stakeholders in their service territories to determine the best approaches to support effective EV charging buildout. Each member company will determine its own specific pricing models and select its own charging equipment providers.Member update: TVA
As a founding member of the EHC, TVA is working to ensure that EV drivers have access to a seamless network of charging stations connecting major highway systems across its seven-state service area and beyond. TVA is helping drive innovation and collaborating through partnerships within the Tennessee Valley to increase the use of electric vehicles. The shared goal is to move from the approximately 18,000 EVs in the region today to more than 200,000 EVs on Tennessee Valley roads by 2028.
TVA recently launched In Charge: Life with an Electric Vehicle, a five-episode video series aimed at dispelling myths and exploring the benefits of electric transportation. Take a road trip throughout the Tennessee Valley with a new video released every two weeks through September, to see how electric vehicles can fit any lifestyle. View the premiere episode here.
“Electric vehicles benefit the environment by reducing carbon, but the economic impact is also substantial,” said Drew Frye, TVA manager of Commercial Energy Solutions. “In the Tennessee Valley, you can buy a locally made EV, power it using electricity from TVA and your local power company, and do so knowing that you’re supporting local jobs.”Member update: AEP
AEP has committed to replacing its 2,300 cars and light-duty trucks with EV models by 2030. Additional medium- and heavy-duty vehicles will transition to hybrid or electric alternatives as models become available. The charging network announced today also will enable AEP employees to use EVs to travel throughout the company’s 11-state service territory. AEP also is working with select customers across its service territory to help them understand the benefits of electrifying their own vehicle fleets or business processes.
Across its service territory, AEP is working with regulators to create programs that benefit all customers and support EV adoption, such as off-peak charging programs, incentives for charging station installations, energy efficiency rebates, and consultative services to encourage electrification.
In 2018, AEP Ohio launched a $10 million program to deploy 375 charging stations in partnership with local governments, workplaces and multi-family dwellings to increase publicly available charging sites and demonstrate the benefit of public-private partnerships as part of the Smart Columbus initiative. The program included a requirement to locate 10% of the charging stations in low-income areas, a benchmark that was exceeded.
In 2020, Indiana Michigan Power began offering its IM Plugged In program to address residential, multi-family dwelling, fleet and workplace charging, as well as corridor fast charging. The program offers customers rebate programs that reduce EV charging infrastructure costs and EV-specific off-peak rates.
Appalachian Power offers a residential off-peak charging program for Virginia customers. Customers also receive credits for EV charging that takes place during off-peak periods, such as overnight.
Additionally, residential customers of Public Service Company of Oklahoma and Southwestern Electric Power Company in Louisiana and Texas are eligible for energy efficiency rebates on qualified EV chargers.
The EHC welcomes interested utilities to join as it seeks to extend the network’s reach. Additionally, it supports, and looks forward to working with other regional utility transportation electrification initiatives.
DISTRIBUTECH International’s live and in-person event is set to take place in Dallas, Texas, January 26-28, 2022. Registration will open soon. Click here to view registration packages and sign up to be notified when registration is open. We hope to see you in Texas!
In the recently announced ANOPR on transmission planning, cost allocation, and generator interconnection reform process, FERC is seeking comments on whether it should require transmission providers to consider grid enhancing technologies in generator interconnection studies to interconnect renewable projects. FERC is also seeking comments from transmission providers who have already implemented and have experience with these technologies.
FERC is looking for comments on transmission planning, cost allocation, and generator interconnection processes since this could be one of the most important transmission planning orders from FERC since Order 2003. Renewable developers should note the focus of this FERC on speeding up renewable project interconnections because most regional grid operators have solar projects in the queue.
As a presenter at the recent PJM interconnection policy workshop put it, FERC Chair Glick and Commissioner Clements indicated their specific concerns with the current state of affairs in generator interconnections and transmission planning. Both FERC Commissioners are concerned that transmission planning is not integrated with generator interconnection planning, and planning focuses on meeting near-term needs.
Without stating it specifically, FERC with this ANOPR has laid out the problem of lack of transmission build-out to interconnect renewable projects. Even if Commissioner Danly dissents in the final order issuance, FERC Commissioners would have a majority vote.
Based on the NOPR on transmission line ratings, we know what the responses to FERC ANOPR on GETs topic would be
FERC issued a Notice of Proposed Rulemaking (NOPR) on “Managing Transmission Line Ratings” on November 19, 2020. FERC gave all interested parties 60 days to respond. Key stakeholder comments filed in that NOPR proceeding include,
1. Previous FERC Chairman Norman Bay wrote in EDF Renewables comments that transmission congestion could limit a RE project output, and hence EDF supports transparent transmission line ratings.
2. When new generator interconnection projects are delayed by more than a year, American Clean Power Association (ACP, previously American Wind Energy Association AWEA) and SEIA support implementing DLRs.
3. Clean Energy Parties (NRDC and others), ACP and SEIA, and the WATT Coalition support an option for interconnection customers to fund a DLR study if the TO does not study DLR as an alternative for network upgrades.
4. MISO Independent Market Monitor (IMM) also supports DLRs.
FERC defined Dynamic Line Ratings DLR as: “a transmission line rating that: (1) applies to a period of not greater than one hour; (2) reflects up-to-date forecasts of inputs such as (but not limited to) ambient air temperature, wind, solar irradiance intensity, transmission line tension, or transmission line sag; and (3) is calculated at least each hour, if not more frequently.”
The real issue is the Transmission Owner (TO) incentives, and the solution lies with FERC
In the FERC NOPR on transmission line ratings, in which FERC has not issued an order, three PJM TOs (AEP, Dominion, and Exelon) do not want FERC to mandate DLRs. MISO TOs in a joint filing and PJM say the same thing.
If FERC mandates DLRs, PJM TOs want PJM to have the flexibility to implement DLRs, and that PJM should consult their TOs.
In the ANOPR, FERC is also seeking comments on the TO incentives question in sections such as, Identifying Geographic Zones That Have Potential for High Amounts of Renewable Resource Development to Meet Increased Demand, Incentivizing Regional Transmission Facilities, Participant Funding and Eliminate Participant Funding for Interconnection-Related Network Upgrades. Hence FERC is looking to incentivize TOs to adopt GETs as alternatives to network upgrades.
FERC could adopt a criterion to implement DLRs
In their comments to FERC on transmission line rating NOPR, ACP and SEIA propose a criterion for implementing DLRs based on the following conditions:
• “Congestion costs have surpassed $1 Million per year;
• New generation interconnection has been delayed by more than one year due to factors that include transmission line capacity, or
• The generation has been curtailed by more than 20 percent on average for one year due to factors that include thermal constraints on line capacity.”
This criterion can be helpful for renewable developers to support in their comments to FERC on the ANOPR because it directly answers the question FERC is asking “whether FERC should require transmission providers to consider grid enhancing technologies in generator interconnection studies to interconnect renewable projects?”. The answer is yes. FERC should require DLRs under the above-stated conditions.
Once published in the federal register, transmission providers have 75 days to respond. Reply comments are due 105 days after the federal register publication date. Assuming August 2 as the publication date in the federal register, all interested parties can reply by October 15. Stakeholders can reply to other’s comments by November 15.
FERC may collect stakeholder comments via technical conferences held in different parts of the country. It is equally likely that FERC would issue a NOPR and then a final FERC Order. Meanwhile, RE developers should look at network upgrade costs from RTO generator interconnection studies and explore the possibility of GETs like solutions.
Last week, Ken Bossong of the SUN DAY campaign said that data released over the past decade by the U.S. Energy Information Administration (EIA) and the Federal Energy Regulatory Commission (FERC) as well as near-term forecasts by both agencies suggest continued strong growth by renewable energy sources. However, unless accelerated, that growth will fall short of President Biden’s clean power goals for 2030.
EIA’s data from the past ten years indicate renewables could be one-third of U.S. electrical generation in 2030.
EIA’s most recent “Electric Power Monthly” report reveals that renewable energy sources (i.e., biomass, geothermal, hydropower, solar, wind) provided 22.5% of U.S. electrical generation during the first four months of 2021. A decade earlier, during the first four months of 2011, renewables provided 13.75% of electrical production. Thus, over the intervening years, renewables added – on average – a bit less than one percent annually to their share of the nation’s electricity supply.
Almost all the growth can be attributed to wind and solar which expanded from 3.3% in April 2011 (year-to-date) to 13.9% in April 2021 (YTD). Meanwhile, the share of electrical generation attributable to biomass, geothermal, and hydropower combined has remained virtually unchanged, accounting for between a bit less than 9% and a bit more than 10% each year.
Should that trend continue, renewables would be on track to provide approximately one-third of U.S. electrical generation in 2030 with wind and solar combined providing about 23% and the combination of biomass, geothermal, and hydropower contributing another 10%.
For the immediate future, this trend appears to be confirmed by EIA in its most recent monthly “Short-Term Energy Outlook” (STEO) which forecasts utility-scale renewables to grow from 19.8% in 2020 to 20.6% in 2021 and then to 22.5% in 2022. If small-scale solar were to be included, renewables were 20.6% of U.S. electrical generation in 2020 and are on track to exceed 21% in 2021 and 23% in 2022.FERC’s data further confirm likelihood of one-third renewables by 2030
The growth rates suggested by EIA’s data seem to be confirmed by a ten-year look-back at FERC’s monthly “Energy Infrastructure Update” reports which track the installed electrical capacity of all generating sources. For April 2021, FERC reports that renewable sources accounted for 24.77% of installed, utility-scale (i.e., greater than 1-MW) generating capacity in the U.S. A decade earlier – i.e., in April 2011, renewables’ share of generating capacity was 13.97%.
Thus, as is true for actual electrical generation, renewables are increasing their share of generating capacity by about one percent per year with almost all the growth attributable to solar and wind. In April 2011, solar and wind accounted for 3.74% of the nation’s generating capacity while hydropower, biomass, and geothermal accounted for 10.23%. By April 2021, solar and wind had grown to 14.96% while the other renewables accounted for 9.81%.
Also, in each “Energy Infrastructure Update,” FERC provides data for “high probability additions” and “retirements” during the upcoming three years for each energy source. Its latest 3-year data foresee the net capacity for coal, oil, natural gas, and nuclear power combined dropping by more than 14 gigawatts (GW) whereas renewables – mostly solar and wind – are forecast to grow by over 64 GW. Should that transpire, renewables’ share of domestic generating capacity would rise to 28.83% by April 2023 (i.e., adding about 1.35% to its share each year).
If that projected growth rate is sustained for the balance of the current decade, renewables’ share of the nation’s generating capacity would be approximately 38% by 2030. With 38% of installed capacity, renewables might be expected to provide 32-35% of actual generation — a figure consistent with what can be extrapolated from EIA’s data.Could renewables surpass 33% by 2030?
There are hints in EIA’s and FERC’s data that renewables’ share of electrical generation in 2030 could be larger – perhaps reaching 50%.
A review of EIA’s end-of-year data reveals strong annual growth rates for wind and solar during each of the last six years (it is difficult to evaluate earlier years because of changes in EIA’s reporting methodology). On average, electrical generation by wind has grown by just over 10% per year since the end of 2014. During that same period, solar averaged an annual growth rate of over 30%, although that has slowed during the past three years to 21% per year.
If one assumes sustained future wind and solar growth rates of 10% and 20% per year respectively, wind generation in 2030 would be more than double that reported for 2020 while solar generation would grow by six-fold. These figures are more than consistent with (in fact, conservative compared to) EIA’s latest STEO forecasts which project wind-generated electricity to grow by 26.5% between 2020 and 2022 while utility-scale solar-generated electricity is forecast to expand by 63.5% over the next two years.
Should this growth scenario materialize, then by 2030 solar and wind would each be generating about the same amount of electricity. If total U.S. electrical generation by all sources remains about the same as in 2020, wind and solar could each be accounting for about 20% of the nation’s electrical generation in 2030. Adding in the 10% likely to be provided by biomass, geothermal, and hydropower combined, renewables could be providing half of the nation’s electricity within a decade.
FERC’s near-term forecasts reinforce the plausibility of this scenario – at least for solar. Over the next three years, FERC anticipates the “high probability” addition of 42.8 GW of utility-scale solar to the 57.9 GW of existing solar capacity – an increase of 74%. “High probability” wind additions would expand wind’s current capacity of 125.7 GW by another 20.5 GW. However, beyond the “high probability additions,” FERC also reports that there may be as much as 58.2 GW more wind capacity and 121.1 GW more solar capacity in the pipeline.
Further, with virtually every new monthly issue of its “Energy Infrastructure Update,” FERC scales up its three-year forecast for new solar. In its first such forecast published in February 2019, FERC projected the addition of 12-GW of solar by March 2022. In its most recent “Update,” FERC’s three-year forecast had nearly quadrupled to almost 43-GW of new solar capacity by May 2024.How likely is 80% renewables?
EIA and FERC data also indicate reaching 80% renewables by 2030 remains possible … but a challenge.
Reaching 50% renewables by the end of this decade would still remain well short of President Biden’s call for 80% clean power by 2030 (assuming “clean” means “renewable” and does not include nuclear power or fossil fuels with carbon capture).
However, EIA’s historic data also suggest a faster growth track is possible for wind and solar which comes close to Biden’s target. Three times during the past six years (2016, 2017, 2020), the annual growth rate for wind-generated electricity has increased by 12.0% or more. And, as earlier noted, while averaging only 21.1% during the last three years, the average annual growth rate for solar between December 2014 and December 2020 actually surpassed 30% (i.e., 31.1%).
If these higher growth rates (i.e., wind – 12% and solar – 30%) were replicated and sustained each year for the balance of the decade – an admittedly very challenging goal – wind could account for about 25% of U.S. electrical generation by 2030 while solar would be nearly 45%. Add in another 10% from hydropower, biomass, and geothermal and one reaches Biden’s 80% target. 
A national clean electricity standard could make such a scenario — or comparable alternatives — realistic. Yet, even without a national clean electricity standard to drive growth, other factors could still enable renewables to secure a substantially larger share of electrical generating capacity and provide more actual generation than historical trends suggest.
These additional factors include, but are not limited to:
Originally published at ILSR.org
Governor Michelle Lujan Grisham signed the Energy Transition Act (SB 489) in 2019, which introduced the idea of a community solar program, and also mandated that New Mexico move to 50% renewable energy by 2030. However, New Mexico’s community solar program was truly born in 2021, when the Community Solar Act (SB 84) established New Mexico’s official program.
After a three-hour filibuster, the Community Solar Act (SB 84) passed on April 5, 2021. The act authorized community solar projects in the state and requires that 30 percent of each community solar facility serves low-income households. The first three years of the program are capped at 200 megawatts of total generating capacity. This total does not include native community solar projects or rural electric distribution cooperatives. The bill defines “native community solar projects” as facilities located on native land that is owned or operated by “an Indian nation, tribe, or pueblo or a tribal entity or in partnership with a third-party entity.” This addresses ILSR’s third principle: that any community solar policy must be additive, rather than detract from any existing renewable energy policy. Subscriptions can supply up to 100% of subscribers’ average annual electricity consumption.
New Mexico is the second sunniest state in the United States, with an average of 300 days per year of sunshine. This climate makes the state a prime candidate for solar power. Early estimates suggest that New Mexico’s community solar program should be up and running by Spring 2022. The Community Solar Act requires that the Public Regulation Commission finalize the rules process by April 1, 2022.
In addition to investor-owned utilities, third parties can own community solar facilities ( fulfilling the Institute for Local Self Reliance’s second principle of successful community renewable energy, flexibility). The system is regulated through renewable energy certificates. In the case of community solar facilities, these certificates are actually owned by the electric utility to which the facility is interconnected. These certificates may be traded or sold, and serve as proof of compliance with New Mexico’s renewable portfolio standard. The community solar program will help to fulfill New Mexico’s requirement that investor-owned utilities are carbon-free by 2045 and 2050, respectively.Tangible Benefits
A study by the University of New Mexico’s Bureau of Business and Economic Research predicts that the community solar project will be a massive boost to New Mexico’s economy. For a small state, the numbers are staggering: 3,760 jobs over the next five years, $517 million in economic benefits, $147 million in labor income, and $2.9 million yearly in tax revenue. Community Solar also offers excellent benefits to small and medium sized landowners, like local farms, many of whom do not possess the amount of property necessary to host a full-scale solar plant. Additionally, projects can partner with local farms and offer landowners revenue for leasing space to solar gardens.
In addition to the boons to New Mexico’s economy as a whole, individual subscribers will receive meaningful benefits. Utilities must provide credits to subscribers for at least twenty-five years after interconnection. The credit rate is proportional to the kilowatt-hour production of their share of the facility, and is “derived from the qualifying utility’s aggregate retail rate on a per customer-class basis”. That amount is then credited to the subscriber’s bill from the provider. If a subscriber uses less than their allotted credit’s worth of electricity in a given month, the surplus amount is applied to their next month.
The program has yet to start, but based on these factors and predictions, New Mexico’s plan passes the Institute for Local Self Reliance’s first principle for successful community renewable energy, tangible benefits.Promoting Indigenous Power
Tribal lands cover 10% of New Mexico, the third highest of any state. There are already multiple small-scale tribal owned solar facilities, including a 115 KW system for the Santo Domingo Tribe. Native community solar gardens are exempted from the overall cap and the individual 100% of average annual consumption limits. The Act states further that “nothing in the Community Solar Act shall preclude an Indian nation, tribe, or pueblo from using financial mechanisms other than subscription models, including virtual and aggregate net-metering, for native community solar projects.Access To All
Beyond the Indigenous-focused pieces, the program contains further components designed to ensure access for a wide variety of subscribers, fulfilling ILSR’s fourth principle. All subscriber material must be printed in English, Spanish, and, if applicable, native or Indigenous languages. New Mexico’s Public Regulation Commission vows to seek input from a variety of stakeholders, which the Act notes includes “low-income stakeholders… disproportionately impacted communities… (and) Indian nations, tribes, and pueblos.” The program’s 30 percent capacity carveout for low-income subscribers compares favorably with other programs.
For more on solar in New Mexico, check out these ILSR resources:
Learn more about community solar in one of these ILSR reports:Designing Community Solar Programs that Promote Racial and Economic EquityMinnesota’s Solar Gardens: the Status and Benefits of Community SolarBeyond Sharing — How Communities Can Take Ownership of Renewable Power
For podcasts, videos, and more, see ILSR’s community renewable energy archive.
Featured photo credit: formulanone via Flickr. (CC BY-SA 2.0)
The Constellation Prize was new to me (and most everyone) in 2020 when I got word of the nomination for some work that I had been involved in with the New York State Capitol, also known as the “Governor Nelson A. Rockefeller Empire State Plaza” in Albany.
When I found out about the nomination of Keith Schue and I for the Constellation Prize for Policy Impact, I thought that it was an honor, not expecting to receive the actual award. I didn’t exactly know how to process such an honor. The first thing I had to do was get my head around how it was that we were awarded this honor for policy change in New York state.
As I looked into the Constellation Prize, I saw that the prize sheds light on how engineering can be done to promote new modes of engagement, research, development, and design that elevate the values of environmental protection, social justice, human rights, and peace.Jay & Kristy Egg and Keith Schue
In our work with the Sheridan Hollow Alliance for Renewable Energy (SHARE), my wife Kristy and I had noted that our involvement with SHARE and the Plaza, especially in the areas of environmental justice, human rights, and reduction of greenhouse gas (GHG) emissions had been quite a long path. We owe the success to this collaboration to key people including Merton Simpson (Albany County Legislator), SHARE and Keith Schue.
As I looked further into the prize, I noticed that it recognizes thoughtful collaborations between engineers and individuals, communities, and organizations that are striving to promote these ideals.The websites states that, “In totality, we seek to create a constellation of people and efforts that can help reimagine what engineering is for.”
Before Kristy became involved, I had been treating the collaboration with Keith Schue and the SHARE as a Good Samaritan type of duty. I simply could not turn the other way while seeing that something could be done to help the community of Sheridan Hollow, and the good state of New York. When Kristy heard of this effort, it was turned from a passing contribution to a full-fledged effort to reverse the funded efforts to install a combined heat and power (CHP) plant at the Empire State Plaza.
Keith Schue and I were introduced through email in 2017 by the executive director of New York Geo, Bill Nowak. Once Keith shared what he knew from his engagement with the project, it became clear to me that the New York Power Authority NYPA did not have correct information about geothermal exchange technology. It was quite a process to convince the state of New York that the $100 million-dollar CHP Plant was not a good choice. A much better choice was to switch the existing chillers from gas-fired steam turbine chillers to electrified chillers, significantly reducing the carbon footprint to cool the massive complex. After numerous trips to New York, countless hours of meetings, and with thanks for the significant contributions from other engineering firms from around the world, we were able to prove our point.
The focus of our argument beyond reduction of GHG emissions was that the installation of natural-gas-fed electric power generators would be a “stranded asset.” Stranded assets are unable to earn their original economic return due to changes in the landscape in which the assets operate. In this case, New York’s laws regarding reduction of GHG emissions were such that natural gas (combined heat and power) power plants would be illegal, due to high GHG emissions in coming years. See the New York Climate Leadership and Community Protection Act CLCPA.
Take a few minutes to look at the other award winning projects on the Constellation Prize Website.
Who do you know that is changing the world through new modes of engagement, research, development, and design that elevate the values of environmental protection, social justice, human rights, and peace? Please share their story with the Constellation Prize Committee at this link:https://www.constellationprize.org/contact or by email to email@example.com
Public support for clean energy is growing at a pace of knots and most governments now also view climate change as a non-negotiable priority to tackle. Additionally, the business case for transitioning to a low carbon economy is now better understood and stacks up as a means of future-proofing any country from energy deficits or financial downturns.
With all of the above in mind, the UK’s Government has been looking very closely at its green policies, cognisant that switching to low carbon technologies will boost the British economy by billions of pounds over the coming years.
Just last year, in the wake of the Covid-19 pandemic, the Government set out its Ten Point Plan for a Green Industrial Revolution. This ambitious document outlines support for the low carbon sector via the creation of 250,000 new green jobs and via direct industry investment. It’s anticipated that the bulk of the earmarked funding will go towards electrical vehicle manufacture, construction and installation of offshore wind farms around the coast, and the retrofitting of homes across the country.
As part of the Ten Point Plan, the Government also announced the creation of the Green Jobs Taskforce. This new body is responsible for identifying and directing action around the job market as we transition to a high-skill, low carbon economy.
Just this week, the newly minted task-force released their first report, outlining their recommendations for what they think the Government’s priorities should be in order to achieve the ambitious ‘green jobs’ targets. Happily, the report is optimistic and illustrates that the UK can go much further and faster than previously thought.A call to arms for the #GreenRevolution
The task-force’s main observation is that “green jobs and skills should not be considered as niche or restricted to certain sectors of the economy. Every job has the potential to become ‘green’ as the world moves to combat climate change, and there are a huge range of skills which will support the transition to a net zero economy.”
The report also states that “one in five jobs in the UK (approximately 6.3 million workers) will require skills which may experience demand growth (approximately 10% of UK jobs) in the transition.”
The assessment of the taskforce is that if the UK is to grasp the opportunities afforded by a green industrial revolution, we must develop a comprehensive view of the skills challenge first.
Their wide ranging recommendations include:
Clearly, there’s a lot to be done but if the nettle grasping can be done now, the UK looks set for rapid and dramatic change for the better.
Ruth Chapman, MD at renewables consultancy Dulas writes that, “all sectors in the UK are about to go through enormous transformation as we focus on achieving net zero.”
“There are already nearly half a million jobs in low carbon businesses, with their output worth approximately £7bn to the economy. If we scaled that up as per the recommendations of the Green Jobs Taskforce, it would benefit every single person in the UK and the country would be permanently changed for the better.”
PowerGen, a developer of on- and off-grid distributed energy said this week that it has secured long term project financing to connect 55,000 people to electricity in rural Nigeria from CrossBoundary Energy Access with construction financing provided by Oikocredit, Triodos Investment Management (Triodos IM) and EDFI ElectriFI (the EU-funded Electrification Financing Initiative).
The project is supported by grant funding from the World Bank and the Nigeria Rural Electrification Agency’s Nigeria Electrification Project (NEP), which provides a fixed grant for each customer connected. The electricity will be provided by 28 distributed renewable energy (DRE) systems, designed as solar PV and battery-powered mini-grids.
Oikocredit, Triodos IM, and EDFI ElectriFI are acting as the construction financiers for the transaction, providing $9m of financing for the construction phase of the project. Once operational, CBEA will purchase the portfolio, becoming the long-term owner of the systems and providing the construction financiers with an exit.
CBEA’s ‘take-out at completion’ transaction structure allows the construction financiers to segment their investment to the construction phase, and CBEA as an asset owner to segment its investment to the long-term operations phase. This is a first for mini-grids in Africa at this scale and shows that innovative financing structures can bring private capital into the sector, said the company.
PowerGen will build the systems and continue to act as the long-term operator of the project after the transfer to CBEA. The project will serve a base of residential, commercial and productive use customers.
PowerGen has already commissioned 6 sites, including the pilot site, Rokota, which was the first to be commissioned under the NEP Performance Based Grant (PBG) program. The financing will be used to develop and build the remaining sites in the portfolio.
Nigeria is Africa’s largest economy, but is plagued by poor energy access, particularly in rural areas, where only 25% of people have access to electricity. This has led many to turn to fossil-fueled alternatives, like diesel generators and kerosene. The result is poor air quality, greenhouse gas emissions, and noise pollution. Together, these represent an undue burden on the health of rural populations, who are already marginalized.
The long-term funding makes the renewable energy possible. The DRE systems developed as a result will provide clean, reliable electricity to 55,000 people and will mitigate over 2,000 MT CO2e annually, which is equivalent to removing 500 cars from the road per year. PowerGen’s service further empowers communities to increase local economic activity by reducing the cost of power and increasing access to productive power, which enables agricultural processing to be mechanize, the use of power equipment such as welding machines and electric cooking appliances, and enabling electric mobility. These benefits are critical as low-income individuals manage the economic downturn brought on by the COVID-19 pandemic.
The transaction is facilitated by CBEA’s project finance structure, which proves a model for bringing long-term infrastructure capital into the mini-grid sector at scale. The systems are being built into a special purpose vehicle (SPV) which will be fully acquired by CBEA once the systems have met the pre-agreed technical standards. Oikocredit, Triodos IM, and EDFI ElectriFI are able to provide construction financing because they have a contracted exit from a long-term financier. Once CBEA becomes the owner of the project, PowerGen will step into a long-term contract to operate and maintain the assets and provide customer service.
The U.S. Energy Storage Association intends to merge with the American Clean Power Association in a move to spearhead transformative growth for renewable energies.
The merger would unify groups representing wind, solar, storage and transmission companies within the membership.
“Our Board sees the merger with ACP as a powerful new chapter for our industry and a pathway to achieving 100 GW of new energy storage by 2030,” said Kiran Kumaraswamy, the Vice President of Market Applications at Fluence and the Chairman of the Board for ESA. “The ESA Board of Directors is confident that a merger will elevate advocacy, research, and educational efforts on behalf of the energy storage industry, with significant benefits and expanded opportunities for ESA’s staff and membership.”
The American Clean Power Association was formed at the beginning of this year. The merger with ESA would already be its second, as ACP combined with the American Wind Energy Association in January.
“Energy storage is foundational to a cleaner energy future for the country.” said, Jim Murphy, President of Invenergy and the Chairman of the board for ACP. “Joining together with ESA strengthens the unified voice of the clean power industry as we continue to transform the US power grid to a low-cost, reliable and renewable power system.”
The U.S. Energy Storage Association includes about 200 companies in the manufacture, deployment and operation of energy storage systems both in the U.S. and globally.
If completed, the merger would take effect January 1, 2022.
Natel Energy announced a $20 million funding round, led by Breakthrough Energy Ventures (BEV) and supported by Chevron Technology Ventures, to build momentum in deploying its flagship product, the Restoration Hydro Turbine (RHT).
“As more solar and wind power solutions are deployed, the role of hydropower will become increasingly important due to its inherent reliability, flexibility, and ability to integrate other renewables onto the grid,” said Carmichael Roberts, BEV. “Natel’s Restoration Hydro Turbine is the most cost-effective and environmentally safe solution for fully unlocking the power of additional sustainable hydropower generation. Additionally, the company’s digital solutions help the existing hydro fleet optimize production, creating a powerful combination of technology to enable a truly 100% renewable grid.”
Two project deployments of this technology have accumulated two years of commercial operation. One example, the Monroe Hydro Project in Madras, Ore., makes use of an existing irrigation canal and the 1-MW class D190 RHT.
“Natel Energy is on pace to grow the footprint of modern, distributed, fish safe hydropower as a climate-resilient solution supporting the transition to a reliable, zero carbon grid,” said Gia Schneider, chief executive officer and co-founder of Natel. “The future of renewable energy, and specifically hydropower, hinges on the ability to consider environmental impacts of deployment alongside the urgent need to shift our grid for a more sustainable future, and Natel’s solutions do just that.”
Natel’s RHT is a compact propeller-style turbine with specially designed blades that allow fish to pass safely. The RHT has a compact footprint that reduces total installed cost and enables plant designs that maintain or improve river connectivity. The RHT is suitable for upgrading or repowering existing small hydro plants; for adding new generation to existing non-power dams; and for new hydro development through Natel’s Restoration Hydro design approach.
Natel combines its hardware and software solutions into a design philosophy called Restoration Hydro to build cost-effective hydropower projects that help to restore watersheds, providing environmental co-benefits – including habitat creation, improved water quality, and sustained increases in groundwater and aquifer recharge rates — while supplying reliable renewable energy. Natel’s Upstream Tech HydroForecast solution enables more accurate forecasts of water flow, helping optimize power production from both RHT and conventional hydro projects, while the Lens solution delivers cost-effective, easily scalable monitoring of landscape change across large project areas to deliver effective natural resource management.
“We are excited about Natel’s potential to unlock distributed hydro resources, further advancing the integration of lower-carbon power into the grid,” said Barbara Burger, vice president, Innovation and President of Technology Ventures at Chevron. “This is the latest investment from our recently launched $300 million Future Energy Fund II, which invests in lower carbon technologies with the potential to enable more affordable, reliable, and ever-cleaner energy.”
With the additional support from this funding round, Natel Energy plans to scale deployments of the RHT, HydroForecast and Lens through direct sales as well as through developing a targeted portfolio of Restoration Hydro projects in the U.S. and Europe.
BEV invests in cutting-edge companies that will lead the world to net-zero emissions. BEV has more than $2 billion in committed capital to support bold entrepreneurs building companies that can significantly reduce emissions from agriculture, buildings, electricity, manufacturing, and transportation.
Northern California has some of the strongest offshore winds in the U.S., with immense potential to produce clean energy. But it has a problem. Its continental shelf drops off quickly, making building traditional wind turbines directly on the seafloor costly if not impossible.
Once water gets more than about 200 feet deep – roughly the height of an 18-story building – these “monopile” structures are pretty much out of the question.
A solution has emerged that’s being tested in several locations around the world: making wind turbines that float. In fact, in California, where drought is putting pressure on the hydropower supply and fires have threatened electricity imports from the Pacific Northwest, the state is moving forward on plans to develop the nation’s first floating offshore wind farms as we speak.
So how do they work?Three main ways to float a turbine
A floating wind turbine works just like other wind turbines – wind pushes on the blades, causing the rotor to turn, which drives a generator that creates electricity. But instead of having its tower embedded directly into the ground or the sea floor, a floating wind turbine sits on a platform with mooring lines, such as chains or ropes, that connect to anchors in the seabed below.
These mooring lines hold the turbine in place against the wind and keep it connected to the cable that sends its electricity back to shore.
Most of the stability is provided by the floating platform itself. The trick is to design the platform so the turbine doesn’t tip too far in strong winds or storms.Three of the common types of floating wind turbine platform. Josh Bauer/NREL
There are three main types of platforms:
Each platform must support the weight of the turbine and remain stable while the turbine operates. It can do this in part because the hollow platform, often made of large steel or concrete structures, provides buoyancy to support the turbine. Since some can be fully assembled in port and towed out for installation, they might be far cheaper than fixed-bottom structures, which requires specialty boats for installation on site.The University of Maine has been experimenting with a small floating wind turbine, about one-eighth scale, on a semi-submersible platform. It plans to launch a full-scale version with corporate partners in 2023. AP Photo/Robert F. Bukaty
Floating platforms can support wind turbines that can produce 10 megawatts or more of power – that’s similar in size to other offshore wind turbines and several times larger than the capacity of a typical onshore wind turbine you might see in a field.Why do we need floating turbines?
Some of the strongest wind resources are away from shore in locations with hundreds of feet of water below, such as off the U.S. West Coast, the Great Lakes, the Mediterranean Sea, and the coast of Japan.
In May 2021, Interior Secretary Deb Haaland and California Gov. Gavin Newsom announced plans to open up parts of the West Coast, off central California’s Morro Bay and near the Oregon state line, for offshore wind power. The water there gets deep quickly, so any wind farm that is even a few miles from shore will require floating turbines. Newsom said the area could initially provide 4.6 gigawatts of clean energy, enough to power 1.6 million homes. That’s more than 100 times the total U.S. offshore wind power today.Some of the strongest offshore wind power potential in the U.S. is in areas where the water is too deep for fixed turbines, including off the West Coast and offshore from Maine. NREL
Globally, several full-scale demonstration projects are already operating in Europe and Asia. The Hywind Scotland project became the first commercial-scale offshore floating wind farm in 2017, with five 6-megawatt turbines supported by spar buoys designed by the Norwegian energy company Equinor.
While floating offshore wind farms are becoming a commercial technology, there are still technical challenges that need to be solved. The platform motion may cause higher forces on the blades and tower, and more complicated and unsteady aerodynamics. Also, as water depths get very deep, the cost of the mooring lines, anchors, and electrical cabling may become very high, so cheaper but still reliable technologies will be needed.
Expect to see more offshore turbines supported by floating structures in the near future.
Researchers at Sandia National Laboratories have designed a new class of molten sodium batteries for grid-scale energy storage. The new battery design was shared in a paper published today in the scientific journal Cell Reports Physical Science.
Molten sodium batteries have been used for many years to store energy from renewable sources, such as solar panels and wind turbines. However, commercially available molten sodium batteries, called sodium-sulfur batteries, typically operate at 520-660 degrees Fahrenheit. Sandia’s new molten sodium-iodide battery operates at a much cooler 230 degrees Fahrenheit instead.
“We’ve been working to bring the operating temperature of molten sodium batteries down as low as physically possible,” said Leo Small, the lead researcher on the project. “There’s a whole cascading cost savings that comes along with lowering the battery temperature. You can use less expensive materials. The batteries need less insulation and the wiring that connects all the batteries can be a lot thinner.”
However, the battery chemistry that works at 550 degrees doesn’t work at 230 degrees, he added. Among the major innovations that allowed this lower operating temperature was the development of what he calls a catholyte. A catholyte is a liquid mixture of two salts, in this case, sodium iodide and gallium chloride.Basics of building better batteries
A basic lead-acid battery, commonly used as a car ignition battery, has a lead plate and a lead dioxide plate with a sulfuric acid electrolyte in the middle. As energy is discharged from the battery, the lead plate reacts with sulfuric acid to form lead sulfate and electrons. These electrons start the car and return to the other side of the battery, where the lead dioxide plate uses the electrons and sulfuric acid to form lead sulfate and water. For the new molten sodium battery, the lead plate is replaced by liquid sodium metal, and the lead dioxide plate is replaced by a liquid mixture of sodium iodide and a small amount of gallium chloride, said Erik Spoerke, a materials scientist who has been working on molten sodium batteries for more than a decade.
When energy is discharged from the new battery, the sodium metal produces sodium ions and electrons. On the other side, the electrons turn iodine into iodide ions. The sodium ions move across a separator to the other side where they react with the iodide ions to form molten sodium iodide salt. Instead of a sulfuric acid electrolyte, the middle of the battery is a special ceramic separator that allows only sodium ions to move from side to side, nothing else.
“In our system, unlike a lithium ion battery, everything is liquid on the two sides,” Spoerke said. “That means we don’t have to deal with issues like the material undergoing complex phase changes or falling apart; it’s all liquid. Basically, these liquid-based batteries don’t have as limited a lifetime as many other batteries.”
In fact, commercial molten sodium batteries have lifetimes of 10-15 years, significantly longer than standard lead-acid batteries or lithium ion batteries.Long-lasting batteries that are safer
Sandia’s small, lab-scale sodium-iodide battery was tested for eight months inside an oven. Martha Gross, a postdoctoral researcher who has worked on the laboratory tests for the past two years, conducted experiments charging and discharging the battery more than 400 times over those eight months.
Because of the COVID-19 pandemic, they had to pause the experiment for a month and let the molten sodium and the catholyte cool down to room temperature and freeze, she said. Gross was pleased that after warming the battery up, it still worked.
This means that if a large-scale energy disruption were to occur, like what occurred in Texas in February, the sodium-iodide batteries could be used, and then allowed to cool until frozen. Once the disruption was over, they could be warmed up, recharged and returned to normal operation without a lengthy or costly start-up process, and without degradation of the battery’s internal chemistry, Spoerke added.
Sodium-iodide batteries are also safer. Spoerke said, “A lithium ion battery catches on fire when there is a failure inside the battery, leading to runaway overheating of the battery. We’ve proven that cannot happen with our battery chemistry. Our battery, if you were to take the ceramic separator out, and allow the sodium metal to mix with the salts, nothing happens. Certainly, the battery stops working, but there’s no violent chemical reaction or fire.”
If an outside fire engulfs a sodium-iodide battery, it is likely the battery will crack and fail, but it shouldn’t add fuel to the fire or cause a sodium fire, Small added.
Additionally, at 3.6 volts, the new sodium-iodide battery has a 40% higher operating voltage than a commercial molten sodium battery. This voltage leads to higher energy density, and that means that potential future batteries made with this chemistry would need fewer cells, fewer connections between cells and an overall lower unit cost to store the same amount of electricity, Small said.
“We were really excited about how much energy we could potentially cram into the system because of the new catholyte we’re reporting in this paper,” Gross added. “Molten sodium batteries have existed for decades, and they’re all over the globe, but no one ever talks about them. So, being able to lower the temperature and come back with some numbers and say, ‘this is a really, really viable system’ is pretty neat.”The future of sodium-iodide batteries
The next step for the sodium-iodide battery project is to continue to tune and refine the catholyte chemistry to replace the gallium chloride component, Small said. Gallium chloride is very expensive, more than 100 times as expensive as table salt.
The team is also working on various engineering tweaks to get the battery to charge and discharge faster and more fully, Spoerke added. One previously identified modification to speed up the battery charging was to coat the molten sodium side of the ceramic separator with a thin layer of tin.
Spoerke added that it would likely take five to 10 years to get sodium-iodide batteries to market, with most of the remaining challenges being commercialization challenges, rather than technical challenges.
“This is the first demonstration of long-term, stable cycling of a low-temperature molten-sodium battery,” Spoerke said. “The magic of what we’ve put together is that we’ve identified salt chemistry and electrochemistry that allow us to operate effectively at 230 degrees Fahrenheit. This low-temperature sodium-iodide configuration is sort of a reinvention of what it means to have a molten sodium battery.”
The development of the new sodium battery was supported by the Department of Energy’s Office of Electricity Energy Storage Program.
A joint venture owned by utility giant National Grid has secured $150 million in new credit to help grow its renewable energy investment over the coming years.
Emerald Energy Venture LLC secured its $150 million portfolio revolving facility structured by SMBC, which is also lead arranger and agent. The portfolio revolver can be expanded to $250 million midway through next year.
The new credit will allow National Grid’s EEV to fund construction of solar, battery storage and wind projects currently under development by National Grid Renewables, the utility holding company’s competitive renewable energy arm.
“Adding more renewable energy to the grid is just one of the many ways in which National Grid is supporting the transition towards a cleaner energy landscape,” said Alexandra Lewis, Group Treasurer of National Grid plc. “This new green facility will help accelerate the work National Grid Renewables is doing in the renewable energy space in the U.S., which not only generates significant environmental benefits, but also drives economic activity and creates green jobs in communities across America.”
National Grid Renewables develops, owns and operates large-scale renewable energy projects across the U.S., including solar, wind and battery storage. This facility is expected to help fund part of the construction of an estimated 1.05 GW of clean energy generation capacity, enough to avoid more than 1.6 million metric tons of carbon dioxide annually according to the Environmental Protection Agency’s greenhouse gas equivalencies calculator.
National Grid Renewables recently completed 40 MW of new solar projects in Michigan.
A legal challenge by two lakeview condo dwellers seeking to block Lake Erie’s first offshore wind farm faces a high legal bar before the Ohio Supreme Court — with equally high stakes for clean energy in the region.
The Icebreaker Windpower project’s six turbines would sit roughly 8 to 10 miles northwest of Cleveland and produce roughly 20.7 megawatts of electricity per year. The Lake Erie Energy Development Corporation, or LEEDCo, has worked on the project for more than a decade.
The Ohio Power Siting Board approved the project in October, putting it on track to become not just the first offshore wind project in Ohio but also the first freshwater offshore wind project in North America.
The developer has achieved several regulatory wins, including the removal of a “poison pill” from an earlier version of the siting board’s approval, which would have mandated nightly shutdowns of the turbines for eight months of the year. There was no evidence that the shutdowns would have been necessary to protect wildlife.
LEEDCo and others asked the board to reconsider that proviso. A bipartisan group of 32 lawmakers also wrote to then-board chair Sam Randazzo, detailing why the nightly shutdown condition was unlawful. The board issued its revised order on Oct. 8, 2020. Randazzo, a longtime foe of renewable energy, had initially favored the shutdown requirement. He resigned the next month in the wake of the House Bill 6 conspiracy scandal.
In the end, the Ohio Power Siting Board “thoroughly considered the abundant evidence in the record,” including testimony from eight days of evidentiary hearings, as well as findings in a revised stipulation, lawyers for the board wrote in their brief. That stipulation “represents a fully-negotiated agreement containing numerous protective conditions, benefits the public interest, and comports with all applicable regulatory principles and practices,” they added.High bar
The project’s primary resistance now comes from two intervenors in Bratenahl, Ohio, a suburb east of Cleveland with median annual earnings above $80,000, according to U.S. census data. W. Susan Dempsey watches birds and sunsets from her balcony, and Robert Maloney enjoys birding and regularly takes his boat out to fish on Lake Erie, their lawyers wrote in 2018.
Their case challenging the siting board’s decision, now before the state’s top court, faces a much narrower path than it had before the board. The Ohio Supreme Court won’t overturn the Ohio Power Siting Board’s ruling unless it was unlawful or unreasonable. Generally speaking, the court is supposed to affirm the Ohio Power Siting Board as long as it correctly applied the law to the facts before it. And the board’s factual findings depend in large part on its technical expertise.
So, the court won’t disturb those findings unless they are manifestly against the weight of the evidence or so clearly unsupported as to show misapprehension, mistake or a willful disregard of duty, the state’s brief noted.
“The court gives deference to the technical opinions of the agencies,” said Dave Karpinski, who heads up LEEDCo. In his view, “there are really no new arguments in their appeal,” which haven’t already been considered and rejected by the board.
“Because Icebreaker Wind is the first ever offshore wind project proposed in Ohio, it is one of the most thoroughly reviewed projects ever to be approved in the state, having been comprehensively studied and analyzed at length,” said Miranda Leppla, vice president of energy policy for the Ohio Environmental Council.
Attorneys John Stock and Mark Tucker represent Dempsey and Maloney. Neither Stock nor Tucker responded to a request for comment for this article.
The lawyers’ 2017 engagement letter with Maloney indicates that the legal fees were being paid by Murray Energy Corporation. The company began bankruptcy proceedings in late 2019, but nonetheless made payments to the lawyers’ firm that year and while the bankruptcy was pending, Dave Anderson at the Energy and Policy Institute has reported.
“Murray Energy has not paid the Bratenahl Residents’ fees for quite some time, and yet the Bratenahl Residents continue their vehement opposition to this misguided Project,” said a footnote in Stock and Tucker’s June 17 reply brief.
Left unsaid was whether Dempsey and Maloney have since paid any legal fees out of pocket, or whether fees have been paid by American Consolidated Natural Resources, Inc. That company is Murray Energy’s successor after its emergence from bankruptcy in September 2020. Media personnel for American Consolidated Natural Resources, Inc. likewise have not responded to questions about legal fees in the case.High stakes
The stakes go far beyond the Icebreaker Windpower project, because the work could help prove the viability of offshore wind in the Great Lakes.
“The fact that it’s been done off the East Coast is good, but it doesn’t really pave the way for the Great Lakes, because there are so many differences,” Karpinski said.
Among other things, fresh water freezes before ocean water does. Because of that, the turbines will need to deal with surface ice. The maximum winter ice cover forecast for Lake Erie is 67% — the highest for the Great Lakes, according to the National Oceanic and Atmospheric Administration. So, turbines’ ability to deal with ice there should bode well for other Great Lakes projects.
The Great Lakes’ wind energy potential could be huge, according to a March 2021 report from Environment America and Frontier Group. Calculations show that the lakes could supply up to roughly one-fifth of combined electricity needs projected by 2050 for Ohio, Michigan, Wisconsin, Minnesota, Illinois, Indiana and Pennsylvania. Among those states, Michigan, Wisconsin and Ohio have the greatest potential — up to 72%, 27% and 19% of their projected 2050 needs.
“A demonstration project in the Great Lakes would be an important step toward reaching our offshore wind potential,” said Bronte Payne, Go Solar campaign director for Environment America. For too long, offshore wind has been “an untapped tool poised to deliver large amounts of renewable electricity,” she said.
“Right now, the Great Lakes region is experiencing the effects of climate change with both warmer weather and increased flooding,” Bronte continued. “This makes it even more important that we are using all of the tools in our toolbox to repower our communities with 100% renewable energy. Offshore wind is a part of that.”
Leppla said the project has taken on additional significance as the state legislature has made it more difficult to site renewable projects. “Ohio should be leaning into the clean energy future and all of the benefits that come with it — from environmental benefits to economic development and job creation.”Next steps
Briefing in the Ohio Supreme Court case wrapped up last month. Oral argument will likely take place within the next two to four months. A decision in the case will probably follow by sometime in 2022. However, there’s no statutory timeline for the court to act.
“That’s really just put things in a holding pattern,” Karpinski said.
If the court upholds the power siting board, LEEDCo will still need time to mobilize and line up contractors, Karpinski said. “We’ve got to restart it. You’re not just picking up where you left off.”
As and when that does happen, LEEDCo also will need to comply with various permit conditions incorporated into the Ohio Power Siting Board’s October 2020 order, including pre-construction testing to show that any avian collisions will be reliably detected. Pre-construction requirements are not unusual.
“All permits have conditions,” Karpinski said. “There’s so much compliance — not only during construction, but for the life of the project, that we have to satisfy.”
For the time being, LEEDCo will wait for the Ohio Supreme Court’s ruling. “Right now we want to make sure we have permanent certainty before we do anything,” Karpinski said.
The need to ensure renewable energy resources can meet baseload power demand is intensifying the race for giant battery storage systems across Europe.
Siemens Smart Infrastructure and German grid operator Zukunftsenergie Nordostbayern GmbH are the latest companies to join the race to improve battery storage, by planning to develop a 100-MW lithium-ion battery storage facility in the town of Wunsiedel.
The battery will be able to power 20,000 average German households once complete by providing them with electricity generated from renewable energy resources for use during peak demand periods.
Fluence, a joint venture of Siemens and AES, will provide the batteries for the project set to be constructed on a 5,000 square meter piece of land.
Siemens will be responsible for project management, including a technical implementation concept, as well as the construction of a medium-voltage switchgear system and connection to the high-voltage grid. Siemens and Zukunftsenergie Nordostbayern GmbH will also work together to develop a financing concept.
Marco Krasser, Managing Director of SWW Wunsiedel GmbH, one of the partners in Zukunftsenergie Nordostbayern GmbH, said: “Electricity storage facilities are an important building block for shaping the future of energy.
“They can help stabilize the grid and make better use of energy generated from renewable sources. They draw surplus power from the grid and feed it back when electricity demand is higher. Smart storage technology will increase the local and national supply of green power. That is why we are gradually expanding the capacity.”
Bernd Koch, Head of Technology Performance Services at Siemens Smart Infrastructure Germany, adds: “This also benefits the upstream grid operator because it gives them more flexibility to compensate for voltage fluctuations, which are increasingly common because of the expansion of renewable energy generation.”
Siemens’ project manager Andreas Schmuderer, reiterates: “For the network operator, the solution promises significant relief. Switching on and off large industrial plants in the grid area requires a lot of electricity.
“Up to now, the network operator has had to maintain considerable reserves. If these can be eliminated in the future, there will be great potential for reducing CO2 emissions in the local energy market.”
Enel Green Power North America has acquired a 3.2GW solar portfolio, including 450MW solar-plus-storage projects, from Dakota Renewable Energy.
The portfolio comprises 24 projects in the development stage, will be located in the Mid-Atlantic, Midwest and Western United States and are planned for commercial operation beginning in 2023.
“While momentum continues to build for clean energy in the United States, we are accelerating our own growth plans by adding this substantial portfolio of solar projects to our medium-term development pipeline,” said Georgios Papadimitriou, President & CEO of Enel Green Power North America.
“These projects will play a key role in our efforts to help states reach their clean energy targets, spur job creation and meet rising corporate demand for renewables.”
Several of the Mid-Atlantic solar projects included in the transaction will feature paired battery storage to capture additional value streams and add resiliency to the power grid as the nation transitions to clean energy.
“We’re very happy to work with Enel Green Power North America as they grow their renewable energy portfolio in the US,” said Jay Schoenberger, Dakota’s Co-Founder and Principal.
“Under Enel Green Power’s stewardship, this outstanding portfolio of solar farms will produce cost-effective zero-emissions power, create jobs, and deliver major economic benefits to the communities hosting these significant investments.”
The projects were initiated and development work was performed by Dakota Renewable Energy, a joint venture between affiliates of Dakota Power Partners and project developer Eolian.
Hawaiian Electric said this week that it is now accepting applications for Battery Bonus, a new program that will pay a cash incentive for residential and commercial customers on O‘ahu to add energy storage (a battery) to an existing or new rooftop solar system.
The incentive will help move Hawai‘i toward its goal of 100% clean energy by 2045 and add more renewable resources to the grid in the short-term when the AES coal-fired plant is retired in September 2022.
The program is capped by the Public Utilities Commission (PUC) at a total 50 megawatts (MW) supplied from storage among all participants. Incentive payments are:
Applications will be accepted through June 23, 2023, or until the cap is reached.
Homeowners and businesses with an existing solar system enrolled in a customer energy program (such as Net Energy Metering, Customer Grid Supply or others) will continue to receive full benefits from these programs. Up to 5 kW of new panels may be added under existing programs. There is no limit on the size of an individual customer’s battery.
The total program term is 10 years. Customers who participate must use and/or export electricity stored in the battery at the contracted amount on a firm two-hour schedule specified by Hawaiian Electric between 6 p.m. to 8:30 p.m. daily (including weekends and holidays) through December 31, 2023. (Example of two-hour period: 6:05 p.m. to 8:05 p.m.) After that date, customers will have the option to transition to the program’s next phase to be defined by the PUC for the rest of the 10-year term.
“This one-time offer is an excellent opportunity for new or existing solar customers to enjoy the added benefits of home energy storage, support the grid that serves all customers and move us closer to our 100% clean energy for electricity goal by 2045,” said Yoh Kawanami, Hawaiian Electric co-director of Customer Energy Resources.
Customers must work with a solar contractor to add storage to an existing system or install a new solar-plus-storage system. Contractors will be able to help fill out forms and submit them to Hawaiian Electric. Contractors may also take advantage of Quick Connect, an existing “pre- approval” program that allows customers who meet certain requirements to install and energize their systems first and send Hawaiian Electric information on their system later.
Securing a building permit from the City & County Department of Planning and Permitting or proof of permit application is required as part of the submission and will determine the final incentive amount.
The solar-plus-storage system owner will receive the incentive. That can be the residential or commercial customer owning the system or a company leasing the system to the homeowner or business. Customers may end participation before the 10-year commitment by notifying Hawaiian Electric and repaying a prorated portion of the incentive.
The incentive payment is considered income. Hawaiian Electric will provide participants with tax forms and report information to the IRS and Hawaiʻi Department of Taxation.
Hawaiian Electric expects the Battery Bonus program to accelerate renewable energy on Oahu and is encouraging customers to apply.
ScottishPower and Shell have joined forces to bid to develop the world’s first large-scale floating offshore windfarms in the north-east of Scotland, they announced last week. The group submitted multiple proposals for new floating offshore windfarms as part of Crown Estate Scotland’s ScotWind Leasing, which closed for submissions on July 16.
Shell expects to use its decades of experience working offshore coupled with ScottishPower’s presence in Scotland to provide the right blend of skills and experience to successfully deliver these projects, it said in a press release.
Floating offshore wind is suitable for use in deeper water zones where fixed foundations aren’t feasible making it ideal for Scottish waters. It will become an increasingly important part of the energy mix in the UK as more and more offshore wind power is brought on to the grid to meet Net Zero targets.
“With just a few months until the COP26 UN Climate Change Summit in Glasgow, ScotWind will help create a whole new industry in floating wind that will play a crucial role in putting the country on course for a cleaner and greener future,” said ScottishPower CEO, Keith Anderson
Shell UK Country Chair, David Bunch said that if the bid is selected, the companies are “fully committed to working with Scottish communities and businesses to help develop supply chains and expertise which could make Scotland a world leader in floating wind.”
ScotWind Leasing is the first round of seabed leasing for offshore wind in Scottish waters in over a decade and will grant property rights for new large-scale offshore wind project development, including floating wind for the first time.
The combined ScottishPower Renewables/Iberdrola and Shell portfolio includes over 2GW of operational offshore wind, over 11GW of offshore wind in development and additionally over 700 MW of floating wind in various stages of development, according to the companies.
Crown Estate Scotland is expected to announce the results of this round of ScotWind Leasing in early 2022.
Clean Path New York today announced a $270 million fund to provide an opportunity for all New Yorkers to thrive in the new green economy.
The fund will serve both communities near generation facilitates and those located along the 175-mile 1,300 megawatt HVDC transmission link that will deliver clean energy generated Upstate to load centers in New York City.
The transmission project team — a collaboration between New York Power Authority (NYPA), energyRe and Invenergy — will make $270 million in investments focused on job training, education, community health and the environment. The companies said the money will be divided as follows:
The $270 million community investment fund compliments additional financial and health benefits of the project including:
The Clean Path New York project will play a critical role in helping New York State meet the targets outlined in the state’s landmark climate legislation, the Climate Leadership and Community Protection Act, which requires New York’s electricity supply to be 70 percent carbon-free by 2030. The long-term ownership of the transmission line will transfer ownership to NYPA, continuing to benefit New Yorkers for generations to come.
“Developing a clean energy future is not only essential in the fight against climate change, it is also an economic opportunity that should directly benefit New Yorkers,” said Jeff Blau, Founding Partner of energyRe. “We’re proud to initiate an investment fund to compliment a public infrastructure project that will create a more environmentally just New York and employ thousands of New Yorkers in the process.”
Generate, a sustainable infrastructure company, yesterday announced it has raised $2 billion in corporate equity from institutional investors to accelerate the deployment of sustainable infrastructure. Existing investors AustralianSuper and QIC led the fundraising round with new investment from Harbert Management Corporation, Aware Super, and CBRE Caledon.
Generate said the fundraising tapped many of the world’s largest long-term oriented pension funds and institutional investors from Australia, the U.S., and Europe, including additional commitments from existing investors AP2 of Sweden, Railways Pension of the UK and The Wellcome Trust.
The company, which says it is now the most well-capitalized sustainability-focused enterprises in the world, builds, owns, operates and finances sustainable infrastructure for companies, governments and communities.
Since 2014, Generate has built a portfolio of about $2 billion in sustainable infrastructure assets across the energy, waste, water and transport markets, deploying solutions that redue greenhouse gas emissions and improve resource efficiency, it said in a press release. The company works with more than 40 technology and project development partners, manages more than 2000 assets and has more than 1,000 customers, including companies, universities, school districts, cities and non-profits across North America.
The company attributes part of its success to its Infrastructure-as-a-Service model, which means customers don’t need to make large capital commitments to meet their sustainability goals. Because Generate manages infrastructure assets, customers don’t have to take that financial and operational risk, a key barriers to adoption of decarbonization and resource efficiency solutions.
Generate’s holding company structure allows project developers and technology companies pioneering the Infrastructure Revolution have access to any and all types of financing and help needed to rebuild the world, according to the company. The company recently launched its Generate Credit unit dedicated to creating more credit solutions for green projects and companies, and geographic expansion beyond North America is also underway.
The asset base the company owns, operates and finances includes renewable power, community solar, energy efficiency, microgrids, energy storage, electric mobility, hydrogen, wastewater, and waste management. Generate’s projects create thousands of jobs across communities and the infrastructure assets already on its balance sheet are expected to prevent over 43 million metric tons of CO2e from entering the atmosphere over the course of their operating lives.
Clearing the current queue backlog is the focus of the Southwest Power Pool (SPP) generator interconnection staff. However, they are missing a key long-term solution to address the root cause of backlog, identifying network upgrade costs for developers.
Indeed, renewable energy (RE) developers could check if alternatives to network upgrades exist if these developers have study results in hand.
SPP staff should run multiple Definitive Interconnection System Impact Study (DISIS) study cycle models to identify the portfolio of network upgrades. That study would indicate possible costs for developers. As a result, they would then choose to stay in the queue or drop out. If RE developers default in PPAs due to SPP queue delays, that ultimately would increase the cost of the renewable projects.
SPP has 100 GWs of capacity of renewable energy projects in its backlog. These are from 533 interconnection customer (IC) requests. Unlike PJM, SPP is focused solely on clearing out the generator interconnection queue backlog. SPP’s generator queue backlog is not higher in volume than PJM’s 2000 projects and 200 GWs backlog.
Similar to PJM, SPP must seek multiple stakeholder committee approvals before FERC tariff filing. In SPP’s case, the Markets and Operations Policy Committee (MOPC) is the top committee that must review and approve the SPP stakeholder’s perspective.SPP’s recent reforms
SPP’s lower stakeholder committee, Strategic & Creative Re-Engineering of Integrated Planning Team (SCRIPT), recently approved unanimously 3 strategies to reduce their current backlog. These include
None of the SPP SCRIPT changes address the core problem in the generator interconnection queue backlog – network upgrade cost estimates. If ICs know the transmission upgrade cost of interconnecting their solar project at the point of interconnection, they would be prepared to stay in the queue or drop out after submitting their request. But those upgrade costs are not unknown until SPP staff runs the model. And when ICs drop out, SPP must restudy.
The only way to avoid this would be for SPP staff to indicate potential transmission upgrade costs for each DISIS cycle.What are the possible solutions?
I see at least 2 possible solutions in the interim for projects already in the queue waiting for SPP’s DISIS study results.
The first possible solution is IC having the option to trigger a study on their own to evaluate alternative Grid Enhancing Technologies (GETs) such as SmartValves or Dynamic Line Ratings (DLRs). That option would provide SPP staff and the Transmission Owner (TO) data on the possible options for the IC without dropping from the queue because the alternative is that a SPP study result shows a need for more than $10 million upgrade costs, which typically leads to the customer dropping out.
The second possible solution is to avoid this need for multiple DISIS restudies and reduce the SPP and TO back and forth with the IC for study results.
What if SPP staff did proactive generator interconnection planning by studying all the network upgrades needed to accommodate DISIS 2018 cycle? This list of network upgrades needed to accommodate one interconnection cycle is the “portfolio of projects,” and their combined interconnection costs provide ICs an overall range for what could be their cost estimate.
Running an iterative process, SPP staff could perform a similar analysis for DISIS 2019 cycle. And similarly, for DISIS 2020 cycle. Knowing what the needed network upgrades and their overall costs are is crucial for the ICs. Then, the customers would be able to choose to either stay in the queue or drop out much sooner than the current practice, clearing the SPP staff workload. Additionally, this approach would provide TOs the data on what transmission projects would be needed in the long term to accommodate multiple generator requests.Why is it important to know common network upgrades that apply to multiple DISIS cycles?
If SPP or PJM staff follow their normal queue cycles, renewable developers could be missing the In-Service Date (ISD) for their Power Purchase Agreements (PPAs). Once PPAs are in default, that has a downstream impact of increasing the costs of entering into future PPAs due to legal costs from tighter default controls and consolidation of RE developers who can afford those legal costs.
Lack of a diverse RE developer supplier pool means higher RE project costs to ratepayers. All this is avoidable at SPP, where the queue volumes are not as high as PJM’s! If SPP planning staff were to simply run combined DISIS cycle studies to determine the overall network upgrade portfolio, many problems could be avoided.
Shaking the queue backlog tree takes multiple paths. None shakes the tree stronger than providing what the RE developers need first and foremost – a network upgrade cost estimate. This idea of a common network upgrade identification for multiple DISIS studies would provide that desired data for ICs.High hopes for MISO SPP joint interconnection study
A joint MISO SPP interconnection study underway could serve as a template for future MISO and PJM joint interconnection studies and other joint RTO studies. Stakeholders expect that MISO and SPP generator interconnection staff will identify the common network upgrades on their “seam.” The truth of the matter is Affected Systems studies are dragging the interconnection study timelines.
Developers could miss ISDs when their project has an impact on neighboring RTO’s transmission system. That coordination is not seamless yet because RTO-RTO coordinate first, then the RTO-TO coordinates. Unless developers are proactive, studies that impact multiple RTOs take even more time than regular DISIS studies in SPP or Definitive Planning Phase (DPP) studies in MISO.Does SPP have staff to keep both FERC and interconnection customers happy?
The bottom line is that RTOs have limited interconnection engineers. RTOs must continue to plan for the transmission system while processing IC requests. Hiring more interconnection engineers is possible, but that takes time, as evidenced by recent PJM interconnection staff turnover. As soon as RTO engineers develop expertise, they get hired away by reputable renewable developers.Conclusions
There is no grand solution that solves RTO interconnection queue backlogs in an instant. SPP RTO staff are right to focus on the existing queue backlog. However, they are missing the crucial piece of data that RE developers need regarding network upgrade costs.
Allowing ICs to find if GETs are a viable alternative to network upgrades for projects with the study results and identifying the portfolio of network upgrades needed for multiple DISIS cycles would help shake the queue backlog tree more. If that were implemented then only the ICs who could pay those network grades would stay in the queue. That reduces the overall cost of RE projects in the long term; otherwise, if RE developer’s default in their PPAs because they cannot meet the in-service dates, nobody wins. Also, SPP staff workload frees up for FERC tariff and other transmission planning work.