This week two large American companies made big claims about their use of renewable energy. Oracle pledged to power its global operations, both its facilities and its cloud, with 100% renewable energy by 2025. Amazon announced several new projects that make it the top corporate buyer of renewable energy in the United States, it said.Oracle
Oracle set a goal to be powered by 100% renewables in four years, by 2025. The goal builds on its existing sustainability priorities, including:
Oracle’s European Cloud regions are already powered with 100% renewable energy, and Oracle has 51 offices around the world using 100% renewable energy.
“Relying on renewable energy is an important step toward a more sustainable future,” said Oracle Chief Executive Officer Safra Catz. “Oracle will always make its biggest impact on the environment by providing customers with technology that enables them to reduce their carbon footprint, but this new goal reflects the shared values of our customers, partners and investors.”Amazon
Amazon, which is now touting itself as a top corporate buyer of renewable energy, said it is announcing 14 new projects in North America and Europe bringing the company’s total renewable energy investments to 10 gigawatts of electricity production capacity.
Among the new projects are 11 in the U.S., including the first solar projects in Arkansas, Mississippi, and Pennsylvania. The other projects are the largest solar farm in Canada, Amazon’s first renewable energy project in Finland, and the company’s fifth project in Spain.
The utility-scale solar and wind projects will supply renewable energy for Amazon’s corporate offices, fulfillment centers, and Amazon Web Services (AWS) data centers that support millions of customers around the world. The projects will also help Amazon meet its commitment to produce enough renewable energy to cover the electricity used by all Echo devices in use.
The latest announcement means Amazon now has 232 renewable energy projects around the world, including 85 utility-scale wind and solar projects and 147 solar rooftops on facilities and stores worldwide.
Already the largest corporate buyer of renewable energy in Europe and globally, Amazon continues to advance its goal to power 100% of its activities with renewable energy by 2025 — five years ahead of its original target.
“We’re driving hard to fulfill The Climate Pledge—our commitment to reach net-zero carbon by 2040, 10 years ahead of the Paris Agreement,” said Jeff Bezos, Amazon founder and CEO.
Crews have started work installing the first energy storage battery units at Florida Power & Light’s massive Manatee Energy Storage Center.
The utility says FPL Manatee Energy Storage Center will be the biggest solar power-battery storage facility in the world when operational. The Parrish, Fla., center will have 400 MW of output and 900MWh of capacity, enough to power about 329,000 homes for more than two hours, according to the release.
It is expected to be completed later this year. Irby was awarded the contstruction contract on the project.
“Energy storage is an essential piece of the puzzle when it comes to building on our rapid solar expansion and delivering a brighter, more sustainable energy future that all of us can depend on, including the next generation,” FPL CEO Eric Silagy said. “But the Manatee Energy Storage Center isn’t just bringing the Sunshine State one step closer to around-the-clock solar power, it is also helping turn Florida into a world leader in clean energy and sustainability.”
The newly installed storage container is the first of 132 units that will ultimately be installed onsite. Each unit weighs approximately 38 tons, is roughly 36 feet long by 11 feet in height and width and will hold roughly 400 battery modules, with each battery module being equivalent to about 2,000 iPhone batteries.
The battery modules will store the extra solar energy produced by the neighboring FPL Manatee Solar Energy Center when the sun’s rays are strongest and send it to the grid when there is a higher demand for electricity.
FPL operates 41 solar energy centers across more than 20 Florida counties. In addition to completing Manatee Energy Storage Center, FPL is also in the midst of constructing nine additional solar energy centers.
By the end of the decade, FPL forecasts that nearly 40% of the company’s power will be generated by zero-emissions energy sources—a 65%-plud increase from 2020.
This week, BloombergNEF’s released estimates for its global benchmark that tracks the levelized cost of electricity, or LCOE, for utility-scale PV and onshore wind. The LCOE looks at the all-in cost to build, operate, and maintain power plants and then calculates the cost per megawatt-hour (MWh) of the energy produced based on all of those inputs.
The group found that the LCOE for large-scale solar and onshore wind fell to $48 and $41 per MWh in the first half of 2021, respectively. These were down 5% and 7% from the first half of 2020, and as much as 87% and 63% since 2010.
Because every market is different, the benchmarks as an average conceal a range of country-level estimates that vary according to market maturity, project size, local financing conditions and labor costs. The lowest LCOEs in the first half of 2021 can be found in Brazil and Texas for onshore wind, and in Chile and India for PV, all at $22/MWh.
In China, the largest market for renewables, BNEF estimates the cost of building and operating a solar farm is now $34/MWh, cheaper than the cost of operating a typical coal-fired power plant at $35/MWh. Similarly in India, new solar can achieve a levelized cost of $25/MWh, compared to an average cost of running existing coal-fired power plants at $26/MWh. Combined, China and India account for 62% of all coal-fired power capacity worldwide. Together the two countries produce around 5.5 gigatons of CO2 annually, or 44% of global power sector emissions.
“The economic incentive to deploy large amounts of solar power just got stronger in India, China and most of Europe. If policy makers can recognize this swiftly, this could prevent the emission of billions of tons of CO2.”— TIFENN BRANDILY, LEAD AUTHOR OF THE REPORT AND ASSOCIATE AT BNEF
Increased commodity pricing not a factor
In Europe, the levelized cost of new-build solar ranges from $33/MWh in Spain and $41/MWh in France, to $50/MWh in Germany. It has come down by an average of 78% across the continent since 2014. This is much lower than typical running costs for coal and gas-fired power plants in the region, which we estimate at above $70/MWh in 2021. The cost of operating coal and gas plants in the EU has risen since 2018, as the bloc’s carbon price has doubled to over $50 per metric ton.
With economies starting to reopen and the demand for commodities picking up, the first half of 2021 has highlighted the critical role of materials pricing in the industries of the power transition. Global steel prices doubled year-on-year, affecting wind turbine costs. Polysilicon, the main feedstock for crystalline photovoltaic cells, has seen its price triple since May 2020.
In China and India, BNEF has tracked increases of 7% and 10% respectively in PV module prices since the second half of 2020. Similarly, wind turbine prices in India are up 5% over the last six months. But BNEF says the impact of the commodity price hike has to be put in perspective. First, manufacturing, not materials, makes up most of the final costs for wind turbines, PV modules and battery packs. Second, supply chains will absorb part of that rise, before it affects developers. Third, some developers have longer-run purchase orders that might shield them against this rise for some time.
Seb Henbest, chief economist at BNEF, said the increased commodity prices haven’t resulted in an increased LCOE yet. However, if the increase continues throughout the year “this rise could mean that new-build renewable power gets temporarily more expensive, for almost the first time in decades,” he said.
By Bill Ireland, Logan Energy
This year’s COP26 summit is widely viewed as one of the last chances to fulfil the 2015 Paris climate agreement and ensure meaningful progress is made towards tackling our net zero targets and the climate emergency.
Hydrogen is one of the energy solutions that can significantly address climate change and has a vital role to play in decarbonization. In the last decade, green hydrogen in particular has shown great promise as an integral part of the renewable energy mix needed for a sustainable future.
But barriers to widespread hydrogen adoption remain and questions have been raised about its realistic role, scale and value within the world’s future energy mix. It’s clear that a dedicated infrastructure is currently lacking, production costs outweigh less-clean competitors, and that government policy shows technology agnosticism is a myth.
We must ask ourselves – does hydrogen have a wider future?Accelerating hydrogen activity
Rapid progress towards establishing net zero industry clusters can be facilitated by making best use of regional resources and organizations. Hydrogen cluster projects with industry, local government and communities can deliver the early steps towards net zero. To speed up rollout, the “hub and spoke” model, such as that being delivered by Menter Môn at one of the UK’s busiest heavy-haulage ports in Holyhead, North Wales, is an intelligent option. Producing hydrogen at a centralized hub then supplying to on-site refueling stations or transporting to external customers is very well suited to hydrogen.
However, if there is to be wide-spread adoption of hydrogen as a viable alternative energy source, there needs to be a national focus on establishing a network of hydrogen production and refueling — not unlike EV charging roll out — to provide the basis for resilient local supply chains. This type of coordinated energy systems approach can use hydrogen to simultaneously decarbonize transport, industry and heat by identifying and involving regional industry and consumer demand and matching this to energy supply opportunities and industry investment.Production costs
Implementing clean hydrogen solutions is not without financial challenges. It requires upfront investment to build and maintain the technology required to produce clean hydrogen, such as electrolyser systems, pipeline modifications, and carbon-capture capabilities. Green hydrogen, produced using renewable energy sources such as solar or wind power and electrolysis, is more costly to produce than its dirtier equivalents, and is dependent on the cost of electricity and available water.
Manufacturing and installing hydrogen technology at scale is one of the main ways that costs can come down — the sooner the economic landscape allows for this scale of deployment, the sooner the shift to a zero-carbon economy. Increasing manufacturing scale typically decreases cost as producing large volumes can decrease the cost contribution of overheads, improve utilization of equipment, and reduce losses by improving the process yield. Additionally, higher volumes produced increases the likelihood of cheaper automatic assembly methods to be used.
This requires investment and government backing, and vitally more education and understanding about the unique benefits of this renewable energy opportunity. With hydrogen, we have the technology and the skills needed to give our energy sector the shake-up it needs to meet our goals. We simply need to commit, think bigger and embrace what it can offer us.Policy-driven benefits
Political will must be galvanized and renewed as we emerge from the fall-out of Covid-19, and energies refocused on climate change as soon as resource is available. Strong, clear policy frameworks are key in meeting our ambitious renewable energy targets and are currently lacking. We must do more.
The industry needs long-term policy and subsidies to stimulate hydrogen demand. Production will follow. Policy that puts hydrogen on an even playing field with already-subsidized energy sources will provide investors with the basis to form robust business models that can act as a catalyst to drive real change.
Investors are typically risk-averse and need to feel secure. If policy makers can generate a predictable 5–10-year pipeline of green hydrogen projects, manufacturers will feel confident about investing in new, larger and automated production facilities and accompanying technologies. Governments can support these initiatives by setting manufacturing tax benefits, offering subsidies for production, and loans for expansion and upgrading facilities, and collaborate closely with industry to align to its needs as it evolves.
The UK Government should also adopt a Sustainable Investment Taxonomy or Sustainable Investment Hierarchy approach to inform and guide all public sector investment and procurement decisions. Classification systems such as these will help organizations understand if an initiative is sustainable, and direct capital flow to sustainable investment opportunities, and companies engaged in sustainable activities.So, what is the wider future of hydrogen?
With the highest energy density of any fuel per kilogram, hydrogen gas is stable enough to store energy longer than any other medium. It can easily be transported and stored, meaning energy from renewable sources can be used when and where availability demands, not just when the sun shines or the wind blows.
Balancing demand for renewable energy sources with these uncontrollable environmental factors means that hydrogen is an achievable, sustainable and desirable clean energy source globally. Aligning perfectly with the UK Government’s 10 Point Plan, hydrogen can advance the further installation and use of renewable technologies, such as solar photovoltaics (PV) and wind farms, driving the growth of low carbon energy.
Commercial interest is already increasing. With significant potential and appetite for hydrogen energy in both the heating and transport sectors, there have been many recent developments in the understanding of timelines and economies of scale for renewables, electrification, and green hydrogen.
However, we must not lose focus. There are technical and economic challenges to overcome for hydrogen. Infrastructure must be built, technologies developed, and communities and stakeholders educated about the benefits to increase buy-in. An imaginative, joined-up approach is key, and it can be achieved.
By strategically planning hydrogen ‘hub and spoke’ facilities we can help meet this demand across almost any territory and drive our biggest emitters, such as transport and heavy haulage, to significantly reduce CO2 output. This will act as a springboard for the wider adoption of hydrogen technologies across both commercial and domestic settings.
The UK pledged to prevent global warming from spiraling out of control by signing the 2015 Paris Agreement – enshrining into law the ambitious climate change target to cut emissions by 78% by 2035. To achieve that goal, three quarters of our electricity will need to be sourced from clean energy. Green hydrogen is a clear and available solution. We simply need to work together to realize our shared goals.About the Author Credit: Chris Watt
Bill Ireland has over 30 years’ experience in engineering with specialist knowledge in energy in the built environment, alternative technologies, sustainable design and innovation in technology. He joined Logan Energy Limited in 2008 as Director of Operations and became Managing Director and CEO in 2012. Bill is responsible for driving the business of Logan Energy in the UK, Europe and further afield.
MISO interconnection customers have the option of designating “hybrid” as fuel type when they submit an interconnection request before July 22, 2021, for the 2021 Definitive Planning Phase (DPP) cycle. In addition, there are nearly 5,000 MW of hybrid resources, mostly solar plus storage, waiting to be studied by MISO from the 2019 and 2020 cycles. But MISO does not have a tariff definition yet for hybrid resources.
MISO is preparing to file a hybrid resource definition at FERC next month because MISO expects more hybrid resource interconnection requests. Hybrid resources are not co-located resources, which happen to be at the same point of interconnection. And because storage is a big part of hybrid resource definition, there are many details that MISO is discussing with stakeholders, such as transmission charges if storage discharges to the grid as a hybrid resource and the capacity credit for a hybrid resource.
Almost a year after the FERC technical conference on hybrid resources, at MISO’s hybrid resources workshop held on June 21, 2021, MISO legal said they are updating the tariff to define hybrid resources, and they will report to FERC in July about this definition, asking for a 60-day effective date.
Even though there are no hybrid resources currently at MISO, four projects are pursuing a surplus interconnection process right now, which is outside the DPP cycle. FERC Order 845 allows adding generator interconnection requests at existing facilities to use any unused transmission reservation called surplus interconnections. Surplus generator interconnection request looks like a hybrid.Definition of hybrid and co-located resource
MISO is proposing the following for a hybrid resource definition:
“A Generator that combines more than one type of Electric Facility for the production and/or storage for later injection of electricity.”
Hybrid resources should not be confused with co-located resources. The definition of a co-located resource is multiple generators located at the same point of interconnection.
In the energy market, the asset owner manages the offer for both co-located resources and hybrid resources. Ownership of co-located resources can be separate or affiliate at the same single point of interconnection. Both of those owners don’t have to own the asset at the point of interconnection.What if a hybrid resource injects more than the generator interconnection studied amount?
When a stakeholder asked how MISO keeps track of interconnection rights and transmission, MISO legal said monitoring of hybrid resource output falls under the FERC Order 890-A requirement of “unreserved use of the transmission system,” and violation of the tariff is spelled out in the generator interconnection agreement. MISO also said penalties for excessive use of the MISO transmission system exist today in the interconnection tariff.
Additionally, MISO operations track whether interconnection services limits are met based on the unit output. Finally, the obligation exists on the interconnection customer as it relates to the interconnection performance limits.MISO market participation model for hybrid resources
NextEra, Clean Grid Alliance (previously Wind On the Wires), and Customized Energy Solutions want MISO to keep the dispatchable intermittent resource (DIR) model for hybrid resources. But DIRs cannot provide regulating or spinning reserves.
A DIR model at MISO was first established for utility-scale wind resources. MISO recently got FERC approval for applying DIR to utility-scale solar resources. DIRs cannot provide ancillary services such as regulation, spinning, and non-spinning services but can provide energy, capacity, and ramp capability at MISO.
In response to a question regarding hybrids registering as a DIR, MISO said that it could allow frequent updates to the model registration process once the new model manager process is live. MISO also took the action item to review whether they can publicly post the registration types for resources. This was taken in response to a stakeholder question as to whether MISO can be transparent about how resources had stored energy resource type II market registration when they did not go through the generator interconnection process.Hybrid resources capacity credit process
MISO gives 50% capacity credit for solar without running any analysis. To assign capacity credit for hybrid resources, MISO said they have a two-phase accredited process. In phase one, the accreditation for hybrid resources is the sum of the default Unforced Capacity (UCAP) ratings for Co-located resources upto the interconnection service amount.
In phase two, capacity accreditation is more operations-related as MISO gains experience dispatching hybrid resources. Unforced capacity considers the statistical data on forced outages and unplanned outages that are sometimes outside an asset owner’s control. Phase II is based on the forecasts provided by hybrid resources similar to DIRs or market offers for the top 8 daily peak hours in a season when MISO moves to seasonal resource adequacy construct.Hybrid and Energy Storage are tied together
While MISO is preparing to implement Electric Storage Resource (ESR) on its current market platform to comply with FERC Order 841, MISO also filed for a rehearing request at FERC. Since hybrid resources are most likely to include a storage component, the question arises if transmission charges would be assessed when storage charges from the transmission grid for later discharge?
In response to that question on transmission charges, MISO said any withdrawal for later injection is treated as a load per FERC acceptance of MISO 841 compliance filing. So, hybrid resources that include storage won’t be charged for transmission when providing ancillary service.
On the other hand, MISO said battery energy storage systems (BESS) could incur network upgrade costs in response to another question on interconnection and transmission cost. A battery withdrawing energy from the transmission grid doesn’t change the requirements of the generator interconnection process.
An ESR market participation model’s benefit is that MISO has an “available” mode for electric storage resources that show the availability for an electric storage resource available for ancillary services but not participating in energy markets. Charging, discharging, emergency charging and emergency discharging, continuous, and outage are the remaining modes for ESR’s. This market feature is available after MISO implements ESR. Hence hybrid resources and storage resources fate is tied at MISO.Next Steps
On hybrid resources at MISO, Great Plains Institute (GPI) conducted a survey, and the results should be announced by June 25. FERC staff released a white paper on hybrid resources a month ago. MISO is also planning to file at FERC the capacity accreditation process for hybrid resources in July.
With more hybrid resources interconnecting, we can expect the market to mature. The good news is that renewable developers have a path forward for including storage with solar interconnection requests.
Virgin Money has completed a deal supporting Scottish Hydro Investment Limited (SHIL) in the acquisition of two operational small hydro schemes from Guinness Asset Management.
The £8 million (US$11.1 million) long-term loan provided by Virgin Money will support the acquisition, and upgrade, of the Glen Buck and Munergie hydro schemes, located in the Scottish Highlands. The schemes have a total capacity of 3 MW and are expected to produce over 10GWh of electricity annually, after a period of upgrade work.
The deal is co-sponsored by existing bank client CRF Hydro Power Limited and corporate group Turner & Co (Glasgow) Ltd. Together these two, through the newly formed joint venture Foster Turner Hydro Limited, are providing an undisclosed level of equity.
Securing these new schemes through SHIL demonstrates the firm’s commitment to energy efficiency, as the amount of electricity produced will be enough to power over 2,600 homes and displace c.2,500 tonnes of carbon per annum. The deal further develops Virgin Money’s existing portfolio of sustainable lending and represents another step in its pledge to halve the carbon impact of its loan book by 2030, according to a press release.
“While sometimes overlooked, medium-scale hydro schemes have an important role to play in supporting the energy transition, particularly those capable of delivering power at times of peak demand, as is the case here,” said Keith Wilson, head of renewable energy at Virgin Money. “Our track record of supporting the hydro sector is already second to none and we are pleased to have concluded another two high performing schemes.”
Virgin Money previously supported CRF Hydro Power Limited with a multi-million-pound package that assisted the growth of its hydro portfolio across Scotland. CRF Hydro Power Limited owns and operates 11 hydro schemes with a combined capacity in excess of 7.7 MW. Together with Turner & Co (Glasgow) Ltd, they already jointly own one hydro scheme under construction. This new deal will be both their second and third JVs together.
Virgin Money says it continually strives to fulfil its strategic growth ambitions, including sustainable lending and green products, as well as addressing residual carbon.
Energy Toolbase today announced that it has commissioned two energy storage systems (ESS) with Today’s Power (TPI), a renewable energy company based in Little Rock, Arkansas that develops, owns, and operates renewable assets. TPI is a wholly owned subsidiary of Arkansas Electric Cooperatives, Inc. (AECI), a Little Rock-based utility service cooperative owned by 17 Arkansas electric distribution cooperatives.
The ESS projects, both sited in front-of-the-meter (FTM) and co-located with solar PV plants, have a combined system size of 4.8 megawatt (MW) / 9.6 megawatt hours (MWh).
Energy Toolbase’s Acumen EMS controls software will manage the dispatch of the Sungrow energy storage systems, which use Samsung battery modules. The Arkansas-based electrical cooperative deployed the projects to reduce yearly grid-level demand, minimize wholesale power costs, and increase grid stability for its customers.
The coop wanted the ability to have full control to manually schedule the dispatch of their storage system, which Energy Toolbase delivered via its ETB Monitor platform. The platform provides a secure, web-based portal for the customer to view real-time system performance, create alerts, and schedule dispatch commands and override events, according to Energy Toolbase, which also said it plans to launch a wider scale release of its ETB Monitor platform later this year.
Energy Toolbase provides a cohesive suite of project modeling, storage control, and asset monitoring products that enable solar and storage developers to deploy projects more efficiently. Energy Toolbase’s Acumen EMS™ controls software utilizes artificial intelligence and machine learning to optimize the value capture of energy storage systems in both behind-the-meter (BTM) and FTM settings.
“We think that this TPI project will become a template that other utilities and electric cooperatives will follow in order to extract multiple value streams from their ESS,” said Quinn Laudenslager, Senior Product Manager of Acumen EMS at Energy Toolbase. “The storage system reduces system peaks, improves stability for their customers, lowers the cost of electricity for the cooperative, and enables the asset operator to manually dispatch their battery on-demand.”
Today’s Power, Inc. is a wholly owned subsidiary of Arkansas Electric Cooperatives, Inc. (AECI), a Little Rock-based utility service cooperative owned by 17 Arkansas electric distribution cooperatives.
Albania launched its first tender for utility-scale onshore wind power plants today. Projects with a capacity of 10 MW to 75 MW can apply.
Several projects will be chosen, according to the European Bank for Reconstruction and Development (EBRD). Total tendered capacity equals 100 MW, and this may be increased to 150 MW in the coming months, in line with the country’s renewable energy targets.
The Albanian Ministry for Infrastructure and Energy is running the tender. EBRD has been supporting the Albanian authorities in the introduction of competitive procurement processes for renewable energy projects.
“We are delighted with the progress Albania is making on scaling up wind and solar energy through open and transparent tenders. This is another milestone for the diversification, resilience and sustainable development of the country’s energy sector,” said Matteo Colangeli, EBRD Head of Western Balkans.
Developers are invited to submit their qualification submissions by mid-June 2022. This will be followed by a request for proposals from applicants successful in the first phase. The launch of the tender process marks the start of a work-intensive phase for developers to meet the stringent technical, environmental and social requirements of the selection process. The announcement of the successful bidders is expected in the first half of 2023.
To assist bidders, a wind siting study has been prepared, including suitability criteria for the selection of sites, as well as a preliminary high-level screening of no-go areas. The Albanian Ministry of Infrastructure and Energy will organize a conference for prospective bidders later this year to provide clarification and answer questions.
The wind tender is expected to deliver highly competitively prices for clean power.
The Swiss State Secretariat for Economic Affairs (SECO) is providing funding for the technical assistance that covers the new tender as well as regulatory work in the energy sector to facilitate the introduction of auctions.
EBRD has been supporting Albania in the development of a sustainable and diversified energy sector through policy dialogue, technical assistance and investment. To date, EBRD has invested more than €1.5 billion in 112 investment projects in the country.
A new study from Sense and Singularity Energy demonstrates the potential for significant carbon reductions from electric vehicle (EV) charging using a combination of smart home automation and location- and time-based carbon emissions data from the power grid. The study found that by automating charging to minimize carbon impact, carbon emissions from EV charging could be reduced 8-14% on average across the U.S., with much greater reductions in California.
The potential reductions in California are more dramatic (up to 43%) because California’s grid relies on renewable energy for nearly half of its electricity, much of it from low-carbon sources such as solar and wind, which contribute to significant variations in carbon intensity, a measure of carbon emissions per unit of energy consumed and this is what accounts for the greater reduction in carbon emissions from smart charging.
As states increase their reliance on renewable energy sources, their variability will increase, too, offering similar opportunities to shift usage to times when carbon intensity is lowest.
The study examined consumers’ EV charging patterns using over 100,000 sessions of in-field EV charging data and time-based carbon intensity data for 30 major regional grid balancing authorities for utilities. It found that charging dynamically to minimize carbon utilization was consistently more effective at reducing carbon than Time of Use (TOU) rates.
The results show that smart home automation can dynamically adjust energy usage to address both grid constraints and carbon emissions goals. A separate study of 1100 California homes conducted by Sense found that 55% of electricity usage in the evening time frame could be shifted to other times during the day or reduced. Using an automated, dynamic approach, utilities can incentivize customers to reduce peak emissions by shifting their activities, including EV charging, similar to the current incentives to reduce peak demand.Not just EV charging
Carbon reductions from automated EV charging could have a significant impact on reaching carbon emissions goals to slow climate change, and while EV charging is the most obvious case, similar opportunities for savings apply to other large loads in the home. The best opportunities for load shaping are activities that can be scheduled flexibly, like running a dishwasher or washing machine during overnight hours to have clean clothes and dishes ready when they’re needed in the morning. For these cases, automation can provide the right balance of meeting consumer needs and optimizing cost, carbon emissions, and constraints of the grid.
Carbon reductions are influenced by the regional mix of energy sources, with some regions offering a potential for higher reductions because of greater variability of carbon intensity in their fuel sources. Among the top 10 balancing authorities, CAISO (California Independent System Operator) had the highest variation in carbon intensity at 307%, followed by SWPP (Southwest Power Pool) at 259%, ERCOT Electric Reliability Council of Texas) at 197% and BPAT (Bonneville Power Authority Transmission) at 181%. For more details, see the complete study.
The analysis showed that most regions can achieve significant carbon reductions by automating EV charging to take advantage of the cleanest energy sources as they come onto the grid. As more states and regions increase the share of energy produced by renewable sources, the carbon savings potential will increase across the country.
Sense CEO Mike Phillips said that the adding intelligence to the home is a key part of a low-carbon future. “As we work on decarbonizing the grid, because of the increased use of intermittent low-carbon energy sources, it is becoming increasingly important to influence not only how much power is being used, but when it is used,” he said in a press release.
“Fortunately, there are many things in the home where people only care about the result – not when the energy is used. EV charging is a great example, but automation can extend to other key consumers of energy as we build intelligence into the infrastructure of the home,” he added.
Said Wenbo Shi, CEO and co-founder of Singularity Energy explained that data-driven carbon intelligence can improve energy management strategies and cost-effectively reduce carbon emissions.
“We are filling a gap between decarbonization targets measured in tons of carbon and existing energy management strategies that are still kWh and cost driven,” he said, adding, “There is a massive opportunity to apply the technology to EVs and other smart devices at scale to rapidly accelerate the transition towards a clean energy future.”Implications for utilities’ demand management strategies
With EV adoption predicted to grow rapidly, propelled in part by the Biden administration’s plan to build out a national network of 500,000 EV charging stations, utilities are predicting big increases in electricity usage from EV charging over the coming decade. At the same, aggressive carbon reduction goals at the state and federal levels have mandated that utilities must reduce carbon emissions.Figure: Comparison of Carbon Intensity (lbs/MWh) by Grid Balancing Authorities
While meeting CO2 reduction goals and anticipating new energy loads from electric vehicles, utilities need to keep pace with more intermittent sources of power. The ability to jointly optimize for CO2, cost, and grid constraints can provide the best performance at a system level. Dynamic signals from the power grid combined with EV charging automation could be used to inform utilities’ incentive programs, influence consumer behavior, modulate peak demand as EV adoption grows, and reduce carbon.About the Study
The study examined 100,000 sessions of in-field electric vehicle charging data and analyzed the location- and time-based fuel mix of the power grid to characterize the carbon intensity of common EV charging patterns. It drew on anonymized Sense home energy data and high-quality carbon intensity data from Singularity Energy’s Carbonara platform. Previous analyses of carbon intensity have relied on annual averages that can be two or three years old. Combining these real-time data sets, the study simulated EV charging for carbon intensity to identify carbon reductions.
By Gia Schneider, CEO and co-founder at Natel Energy
Hydropower sits at the nexus of energy and water, enabling hydropower projects to be unique catalysts for positive change. If designed with both energy and water in mind, hydropower projects can increase reliable renewable generation and deliver positive co-benefits for river ecosystems and water users. Conventional approaches to hydropower did not always adequately consider the ecosystem impacts of large structures — but major shifts in the hydropower industry are underway.
What is keeping the U.S. from fully embracing a new generation of hydropower? Explained below are 5 major myths about hydropower.Myth 1: Hydropower plants have to be massive in order to be efficient.
Many people think that only the largest projects on a massive grid are efficient enough to be worth developing.
The truth is that with modern technology solutions, it is possible to develop and operate distributed hydropower projects, networked together into virtual power plants at scale and cost-effectively. By leveraging advances in distributed energy resource management, microgrids, and batteries, virtual power plants offer increased power generation without the environmental impact. Low head, fish-safe and in-stream turbine technology has a lower environmental impact, and enables a new approach to hydropower design that is far more distributed and modular than in the past.Rendering of a modular plant. Credit: Natel Energy
A recent NREL cost analysis of distributed, interconnected hydropower projects linked to create a virtual power plant demonstrated that the revenue reduction from the operational changes needed to achieve environmental objectives was small, at less than 4%.Myth 2: Hydropower and river sustainability objectives are always at odds.
Large dams built decades ago, such as the Hoover Dam, are often what comes to mind when thinking about river sustainability and hydropower. These traditional dams don’t emit carbon dioxide, however they do pose issues for river connectivity for both aquatic species (fish) as well as sediment. Such dams disrupt the ability of fish and other aquatic species to move upstream and downstream easily; and they also trap sediment, often starving downstream river reaches of nutrients and sediment. This often leads to downstream degradation of the river channel and stream-bank erosion.
However, in an unprecedented move, industry groups and environmentalists came together in what’s been called the Uncommon Dialogue to collaborate on a set of specific policy measures that could help generate more reliable, renewable electricity from some of the nation’s 90,000 dams already in place, while also agreeing to retrofitting or remove dams that are unsafe, ecologically damaging or simply beyond their useful life. This would help both increase our nation’s supply of reliable renewable energy, supporting the transition to a zero carbon grid, while also improving the safety of our water infrastructure and restoring river connectivity.
The Uncommon Dialogue resulted in a Joint Statement which was signed by the National Hydropower Association as well as environmental groups including American Rivers, the World Wildlife Fund and the Union of Concerned Scientists, showing a joint effort to align hydropower with river sustainability goals long term.
Related: The Uncommon Dialogue will be discussed at the upcoming HydroVision International event, set for September 21-23, 2021 in Spokane, Washington. Learn about the session here.Myth 3: Hydropower is a tapped out resource – everything has been developed.
Modern distributed hydropower is the future of hydropower infrastructure as it is expensive and inefficient to build new dams. At present, the majority of existing dams in the U.S.—more than 90 percent, or 80,000 dams—don’t produce electricity. These dams can be retrofitted to produce new, reliable renewable power and improve environmental impacts. Some of these dams are candidates for removal, paired with new approaches to add hydropower as part of river restoration post-removal. Finally, additional distributed projects with low-head, fish-safe turbines can be developed, again incorporating proven civil and environmental engineering designs used extensively in river restoration. In total, these potential resources in the U.S. could increase hydropower generation by up to 50%.Myth 4: Hydropower is not reliable.
Hydropower offers dispatchable power, a predictable and flexible generation source that can serve as the backbone for a mix of other power sources. Since rivers flow consistently, including at night, turbines continue to spin and produce power, unlike wind or solar power, which have more intermittent generation profiles. Rather than being at odds with wind and solar, hydropower is actually quite complementary, with its ability to easily flex up or down and provide support to the grid depending on what is happening with wind and solar at any given point. This flexibility enables hydropower to help integrate more wind and solar, and support the most cost effective utilization of battery storage to support shifting the grid towards zero carbon in the future.
Grid reliability can be impacted by hydropower in very effective ways. Texas just this past winter faced extreme grid challenges that could have been prevented with a more diverse power supply structure. In addition, as solar and wind continue their growth, large-scale storage will be needed. Surplus energy will need to be stored from periods of intense wind or sun, for use when wind slows or night falls. Hydropower is currently the most robust energy storage and pumped-storage currently accounts for 95% of all utility-scale energy storage in the United States.Myth 5: Hydropower is not part of the future of clean energy.
Hydropower is not a single solution that will magically make the transition to a reliable, zero carbon grid happen easily. However, hydropower has a substantial role to play in a clean and ethical energy transition plan for several reasons.
Energy experts have said that adding more hydropower could provide a useful tool in the fight against climate change. Over the past decade, wind turbines and solar panels have come down their cost curves to the point where they are mass deployable solutions, but they are intermittent and don’t run all the time. Hydropower can offer a backstop, providing flexible, reliable power and complementing battery storage.Conclusion
Hydropower is the generation of electricity from flowing water – rivers, streams, ocean tides and currents. It is a clean, domestic, renewable energy source that is flexible and reliable, and can serve up to one-third of grid reserve requirements – critical support to aid the integration of wind and solar as we transition to a zero carbon grid.About the Author
Gia Schneider is co-founder and Chief Executive Officer of Natel Energy. Gia has more than 20 years of experience in the energy industry in asset management, asset value, and carbon emissions trading. She has led and directed diverse teams from utility practice to establishing the energy trading desk at Credit Suisse. Most recently, she worked at Constellation Energy on optimizing generation asset value. Before that, she provided strategic solutions to major energy companies with Accenture around asset management. Schneider has a Bachelor of Science in Chemical Engineering from MIT. She founded Natel Energy in 2009 with her brother, Abe Schneider, motivated by the theme of climate change driving changes in water patterns and focused on the opportunity to innovate hydropower solutions that catalyze sustainable river outcomes while producing reliable renewable energy. Gia is passionate about finding economically viable solutions to mitigate climate change, foster sustainable development and produce inexpensive renewable energy. In her spare time, she can be found surfing, kiting, and cooking with family and friends.
by Mickey Francis, EIA
In 2020, consumption of renewable energy in the United States grew for the fifth year in a row, reaching a record high of 11.6 quadrillion British thermal units (Btu), or 12% of total U.S. energy consumption. Renewable energy was the only source of U.S. energy consumption that increased in 2020 from 2019; fossil fuel and nuclear consumption declined. Our U.S. renewable energy consumption by source and sector chart (above, larger version here) shows how much renewable energy by source each sector consumes.
We convert sources of energy to common units of heat, called British thermal units (Btu), to compare different types of energy that are usually measured in units that are not directly comparable, such as gallons of biofuels compared with kilowatthours of wind energy.
We use a fossil fuel equivalence to calculate primary energy consumption of noncombustible renewables (wind, hydro, solar, and geothermal), which are not burned to generate electricity and therefore do not have an inherent Btu conversion rate. In this approach, we convert the noncombustible renewables from kilowatthours to Btu using the annual weighted-average Btu conversion rate for all fossil fuels burned to generate electricity in the United States during that year to estimate the amount of fossil energy replaced by these renewable sources.
We use the fossil fuel equivalency approach to report noncombustible renewables’ contribution to total primary energy, in part, because the resulting shares of primary energy are closer to the shares of generated electricity. This calculation also represents the energy that would have been consumed if the electricity from renewable sources had instead been generated by a mix of fossil fuels.
Source: U.S. Energy Information Administration, Monthly Energy Review
Wind energy, or electricity generated by wind-powered turbines, is almost exclusively consumed in the electric power sector. Wind energy accounted for about 26% of U.S. renewable energy consumption in 2020. Wind surpassed hydroelectricity in 2019 to become the single most-consumed source of renewable energy on an annual basis. In 2020, U.S. wind energy consumption grew 14% from 2019.
Hydroelectric power, or electricity generated by water-powered turbines, is almost exclusively consumed in the electric power sector. It accounted for about 22% of U.S. renewable energy consumption in 2020. U.S. hydropower consumption has remained relatively flat since the 1970s, but it fluctuates with seasonal rainfall and drought conditions.
Wood and waste energy, including wood, wood pellets, and biomass waste from landfills, accounted for about 22% of U.S. renewable energy consumption in 2020. Industrial, commercial, and electric power facilities use wood and waste as a fuel to generate electricity, produce heat, and manufacture goods.
Biofuels, including fuel ethanol, biodiesel, and other renewable fuels, accounted for about 17% of U.S. renewable energy consumption in 2020. U.S. biofuel consumption fell 11% from 2019 as overall transportation sector energy use declined in the United States during the COVID-19 pandemic.
Solar energy accounted for about 11% of U.S. renewable energy consumption in 2020. Solar photovoltaic (PV) cells, including rooftop panels, and solar thermal power plants use sunlight to generate electricity. Some residential and commercial buildings use solar heating systems to heat water and the building. Overall, 2020 U.S. solar consumption increased 22% from 2019.
Principal contributor: Mickey Francis
Sappi North America Inc., a producer and supplier of paper, packaging products and pulp, announced it will sell its hydroelectric assets on the Presumpscot River in Maine to Dichotomy Power LLC, pending satisfactory completion of regulatory and other approvals.
The move will allow Sappi to focus on its core competencies and is consistent with Sappi’s recent restructuring of the Westbrook site, according to a press release.
“We are happy to have found a strategic buyer in Dichotomy Power, a company with a wealth of expertise in this area, so that Sappi can continue to focus on its core competencies,” said Mike Haws, president and chief executive officer, Sappi North America. “Today’s announcement allows us to redeploy resources to further develop our growing businesses.”
The hydroelectric projects involved in the transaction were not named.
“Dichotomy Power is pleased to have reached an agreement with Sappi North America, Inc. to acquire their Presumpscot River hydroelectric facilities,” said Ian Clark, CEO of Dichotomy Power. “We are proud to carry on a history of successful traditions that started in 1878 with mechanical waterpower. Dichotomy looks forward to investing in the facilities to increase renewable energy production while honoring the commitments made to the agencies, communities, regulators and stakeholders who helped craft the new licenses.”
The deal is expected to close by the end of the calendar year subject to regulatory and other approvals.
Dichotomy Power is a New York-based renewable-energy company engaged in acquiring, renovating as needed, and operating hydroelectric assets in the U.S., principally in the Northeast. Founded in 2019, Dichotomy creates value for stakeholders by working alongside regulators and local communities to enhance the fundamental value embedded in each operated renewable energy facility while preserving the environmental and social contributions these assets carry.
According to its website, Dichotomy owns and operates eight hydroelectric facilities.
RES (Renewable Energy Systems) and partner Cowessess First Nation are pleased to announce a tender award with SaskPower for a 200 MW-wind project located south of Kipling, in southeastern Saskatchewan, Canada.
The 200-MW Bekevar Wind Energy Project will consist of approximately 40 turbines, underground medium-voltage electrical collector system, access roads, a substation, two permanent meteorological towers, and an operations and maintenance building. SaskPower is expected to build a 10km long transmission line to connect the project to the provincial grid. The turbines are planned on a 20,000 acre area that overlaps with the RMs of Hazelwood and Kingsley, and about 500 acres of reserve land.
The project is expected to produce enough electricity to power approximately 100,000 homes and plays a significant part in de-carbonizing the Saskatchewan power generation fleet by displacing coal power dispatched by SaskPower. Bekevar Wind Energy Project will help the province achieve the federal target of phasing out conventional coal generation by 2030 and help SaskPower meet its target of 50% reduction of emissions from 2005 levels by 2030.
The project benefits of the Bekevar Wind Energy Project include:
The project is owned by Bekevar Wind L.P. a partnership between RES and Awasis Nehiyawewini Energy Development, a wholly owned Cowessess First Nation entity. Construction on the project is expected to begin in the summer of 2022 and is slated for completion by the end of 2023.
“Saskatchewan is an ideal place to build some of the most cost-effective wind power in the world. With many world-class renewables companies qualified to bid, the tender was highly competitive and RES and its partner, Cowessess First Nation, strove to deliver best value to SaskPower,” said Peter Clibbon, RES Senior VP of Development. “We are committed to delivering a quality project on schedule and deliver significant economic benefits to the host communities.”
“Cowessess First Nation has been pursuing utility scale wind energy development since the incorporation of ANEDC in 2010. This is the third Request for Proposal in nine years Cowessess has bid into SaskPower with our partners. To be awarded the Bekevar project in collaboration with RES is a milestone for our First Nation, which helps continue to lead Indigenous renewable energy development in Saskatchewan.” Said Chief Cadmus Delorme. “We look forward to utilizing what Mother Earth has granted us with, while working with RES to help Saskatchewan achieve the desired carbon reduction targets.”
The Federal Energy Regulatory Commission (FERC) and the National Association of Regulatory Utility Commissioners (NARUC) today announced the formation of a joint federal-state task force on electric transmission, which FERC established by order issued today.
Members of this first-of-its-kind task force will explore transmission-related issues to identify and realize the benefits that transmission can provide, while ensuring that the costs are allocated efficiently and fairly.
The efficient development of new transmission infrastructure is essential as the nation continues to transition to clean energy resources. Federal and state regulators will be called upon to address numerous issues, including how to plan and pay for new transmission infrastructure and how to navigate shared federal-state regulatory authority and processes. As a result, the time is ripe for greater federal-state coordination and cooperation.
FERC’s order requests NARUC to nominate up to 10 state regulators to join FERC commissioners on the task force. All task force meetings will be open to the public and will use a dedicated FERC docket for this process to provide stakeholders and the public with the opportunity to comment for the record.
Specifically, the task force will seek to:
“I am so pleased that FERC is joining with NARUC today to establish this joint task force to consider a variety of transmission-related subjects that will affect how successful efforts will be to build out the transmission grid,” said FERC Chairman Rich Glick.
“A big thank you to our friends at NARUC, including Idaho Public Utilities Commission President and this year’s NARUC President, Paul Kjellander, for their hard work in putting this task force proposal together. I’m looking forward to our joint meetings,” Glick added.
“Our partnership with FERC on this task force presents a much-needed opportunity for state and federal regulators to work collaboratively on transmission issues that affect all stakeholders,” said NARUC President Paul Kjellander. “Our shared authority over how to plan and pay for transmission infrastructure and the rapid pace of the energy transition have made such collaboration an imperative for all of us.”Industry Reactions
Gregory Wetstone, President and CEO of the American Council on Renewable Energy (ACORE) commended the governing bodies. “By bringing FERC and state regulatory commissioners together on issues of shared jurisdiction, the Joint Federal-State Task Force on Electric Transmission can help identify obstacles and develop solutions for transmission development, and we look forward to seeing its recommendations,” he said in a statement.
“Ten years after being finalized, not one interregional transmission line has been built using the process established under Order 1000. With more interregional transmission, we can connect centers of high renewable resources with centers of high electric demand, enhancing grid reliability and dramatically reducing carbon emissions,” he added.
Sean Gallagher, vice president of state and regulatory affairs at the Solar Energy Industries Association (SEIA) said the move was critical to the success of Biden’s infrastructure plan.
“The reality is that we are going to need to add hundreds of gigawatts of solar and energy storage capacity to reach President Biden’s 100% clean electricity goal. We must also find a way to connect this load to the grid and deliver it to customers that want access to solar and storage. Transmission is going to be a critical part of this process, and this new partnership promises to help overcome the regional planning challenges associated with building the transmission capacity we need to meet our goals,” he said in a statement.
By Tony Seng, Nextracker
The International Organization for Standardization, better known by its acronym ISO, is an independent, non-governmental international organization with a membership of 165 national standards bodies. The ISO family of thousands of standards covers pretty much all aspects of technology and manufacturing. One of the more familiar of those myriad families of standards is ISO 9000 and ISO 9001 in particular, which focuses on quality management systems (QMS). Getting ISO’ed is a big deal, and I’m proud to have helped lead the charge at Nextracker to achieve certification for ISO 9001:2015.
As I said in our press release about earning the ISO certification, every Nextracker solar tracker is designed and built to the highest quality standards. Our ISO 9001:2015 accreditation is confirmation of our demonstrated and ongoing commitment to reliability, quality assurance, the environment, and safety. Although that quote puts a nice bow on things, it doesn’t do justice to the heavy lift that was involved by my teammates across the Nextracker organization to get to the ISO finish line.
After kicking around the idea for a long time and knowing many of our biggest customers were pushing for us to get ISO’ed, we officially began the process in November 2020. We knew we were pretty far down the road to compliance and meeting the needs of our customers with our existing QMS, but we needed fresh independent eyes to assess our efforts and to make sure everything we were doing was best in class.
In December, we conducted “gap assessments” in our own systems and found some gaps associated with certain specific requirements of ISO 9001:2015, such as risk assessment and risk mitigation processes that we did have in place but didn’t have properly documented. One of the keys to the ISO process is “say what you do, do what you say,” which means having everything documented for repeatability and reproducibility and following those documented processes closely. It’s also important to have precise and clear wording in your documentation that aligns with the ISO specifications.
The gap-closing process ran through the first few months of 2021, after which we went right into the all-important audits. The first stage of the audit took a few days, but the second stage was a grueling 7-day stretch of deep-dive, fully focused audits. Our auditors were SGS, the world’s leading testing, inspection, and certification company.Nextracker engineering team in ISO 9001 meeting.
While much attention is paid to the quality management part of it, the audit process was more than just a quality review. As noted, it also focused on the broader business management system and customer relations. The questions we faced included:
Nextracker has grown phenomenally over the past few years – but with growth comes risk. If you don’t have a scalable process, a repeatable process, then you can find yourself in trouble. Getting ISO certified is confirmation that we have the appropriate procedures, documentation, measurement systems and corrective systems in place—a real key to achieving scalability. The other part of 9001 is the customer connection because a company can’t thrive and expand without hearing what the customer has to say and responding to what the customer needs. Believe me, we listen very closely to what our customers are telling us and have the documented processes to prove it.
Achieving ISO 9001 is by no means an end in itself, it is just the beginning: it provides the solid foundation and continuous improvement mindset on which we’re building our efforts to obtain additional ISO and other certifications. We are already working on two other ISOs–ISO 14001:2015 (for environmental management) and ISO 45001 (for occupational health and safety management)–and expect to have the audits completed and the certifications signed off before the end of the year. This ISO journey is one of the keys to our continuing success as we scale toward our first 100 GW of shipments and installed capacity.
Tony Seng is senior manager of quality engineering at Nextracker and has worked at the company since 2015.
This blog was first posted on Nextracker’s website and was reprinted here with permission.
This week Newlab and Ørsted announced the launch of the Blue Energy Studio, a collaborative initiative designed to drive innovation towards a future powered by renewable energy. The Blue Energy Studio will engage entrepreneurs, engineers, inventors, and corporate partners, beginning with Ørsted, to test and iterate innovative solutions to critical challenges across the renewable energy value chain.
With an eye towards the United States’ goal of reaching 100% carbon pollution-free electricity by 2035, the Studio aims to advance solutions to challenges across the renewable energy value chain, initially focusing on offshore wind innovation. The studio said it will recruit technology companies focused on streamlining the investigation and installation of new sites for offshore wind development; improving efficiency in site operations and maintenance; and optimizing power distribution to energy grids. With the addition of other industry partners, the Studio will expand its purview to include the geothermal, hydroelectric, and solar categories.
“We are excited to partner with Newlab and deliver on our shared goal to grow the Blue Energy Studio into a world-class program for innovation in renewable energy. We will engage the world’s leading minds to help address one of the most significant challenges facing humanity today—climate change,” said Neil Hamel, Head of U.S. Innovation & Venture at Ørsted.
“At Newlab, we are committed to leveraging our community of over 800 entrepreneurs, engineers, inventors, investors, and advisors to tackle significant, real-world challenges across industries,” said Shaun Stewart, CEO of Newlab. “Solving key bottlenecks in the renewable energy sector will be essential to ensuring the health and wellbeing of our planet for decades to come. We welcome the opportunity to work with Ørsted, along with entrepreneurs utilizing transformative technologies, to enable powerful solutions that will drive the sector forward.”
This partnership is the first of its kind for Ørsted’s Innovation Hub, based in Providence, Rhode Island, which works to identify, foster, and, where appropriate, finance enterprises related to offshore wind, focusing on next-generation technology and related innovation in the offshore wind energy field.
Countries are slowly diversifying their energy portfolio by including hydrogen in their future roadmap towards a low carbon economy. Today, several global trends and activities distinguish the renewed focus on hydrogen from what has been observed in the past. Countries like Germany, Japan, the UK, China, Australia, and others have already made plans targeting Hydrogen production and prices with a series of investments and potential policies being considered. The main focus – How do we get ‘GREEN HYDROGEN’ to compete with energy sources in the sectors like electricity generation, industrial feedstock, export, and the fuel used in the transportation sector.
Australia has the potential to become a major player in the Hydrogen market that is estimated to reach $201 billion by 2025. Factors like abundant land and energy resources, status as a major energy exporter, skilled workforce, over-reliance on imported fuels, and declining reserves make hydrogen a very excellent proposition to solve a lot of the country’s energy troubles, both short and long term.International certification scheme for hydrogen
Between 2015-2019, the Australian government committed over $146 million to hydrogen projects along the supply chain. Australian government said that $441.1 million of the 2021/22 budget would be allocated to support low-emission international technology partnerships and initiatives. Conservative estimates developed for the National Hydrogen Strategy show a domestic industry could generate over 8,000 jobs and $11 billion a year in GDP by 2050.
At $2 per kilogram, clean hydrogen becomes competitive in applications like producing ammonia, as a transport fuel and for firming electricity. To achieve this stretch goal, the industry will need to scale up quickly and cost-effectively while reducing input and capital costs. The diverse geography of the continent means not every region has the same potential for the development of the hydrogen sector and needs a different roadmap.How Hydrogen is produced
Today, Hydrogen is mainly produced from fossil fuels (Thermochemical) or through the electrolysis of water (Electrochemical).
Mature Thermochemical technologies include steam methane reforming (SMR) which relies on natural gas as an input and coal gasification which relies on coal. The potential for both SMR and coal gasification in Australia is somewhat dictated by the location of the resource and the availability of a properly characterized CO2 storage reservoir. SMR and coal gasification plants are capital intensive, and therefore must be built at scale (> 500,000 kg/day) to offset the capital cost of the generation plant and accompanying CO2 storage reservoir. While the industry is in a development phase, projects of this scale would very quickly saturate a domestic market and require a hydrogen export industry.
Although SMR, which is the most widely used hydrogen production method today (48%), is currently the cheapest form of hydrogen generation, investment in new large-scale demand may prove challenging given the current state of the natural gas industry in Australia. Further, black coal gasification has challenges in an Australian context due to coal reserves being concentrated in NSW and Queensland where there are either no well-characterised or only onshore CO2 storage reservoirs that carry a higher social licence risk. Hydrogen production via brown coal in Victoria’s Latrobe Valley, therefore, represents the most likely thermochemical hydrogen production project ($2.14 – 2.74/kg by 2030) which would have the advantage of an extensive brown coal reserve sitting alongside a well-characterised CO2 storage reservoir in the Gippsland Basin.
The electrochemical process uses an electrical current to split water into hydrogen and oxygen. Mature technologies include polymer electrolyte membrane (PEM) and alkaline electrolysis (AE).
AE is currently the more established and cheaper technology (~$5.50/kg) and will continue to play an important role in the development of the industry. PEM electrolysis is fast becoming a more competitive form of hydrogen production as it offers several advantages over AE including faster response times and a smaller footprint for scenarios with space limitations (e.g. hydrogen refuelling stations).
The cost of electricity and capital cost of electrolysers affect these processes and regions with cheaper electricity would benefit more than others. The cost of hydrogen from both types of electrolysis can be significantly reduced via R&D, scaling of plant capacities, greater utilisation, and favourable contracts for low emissions electricity. With some demonstration projects likely over the next three to four years needed to de-risk these assets at scale, it is expected that costs could reach approximately $2.29-2.79/kg by 2025.
Other emerging technologies include using biomass to produce syngas and methane cracking. Hydrogen may be produced by converting a feedstock to a chemical fuel using high‑temperature thermochemical reactions, powered by concentrated solar radiation.Hydrogen Transportation ProcessExpected Price (2025)Compression in Tanks˜0.3/kgUnderground Storage˜0.2/kgLiquefaction$1.59-1.94/kg
The transportation of hydrogen will also add to the costs of hydrogen with R&D working to improve various processes. Underground storage is expected to be cost-effective for larger volumes and higher pressure. The storage technology will have to be paired with the most appropriate transportation method for optimum results.
The government will have to play a major role in the development of the hydrogen sector. A vertically integrated approach will allow for greater optimization of assets. However, given the high capital cost, the investment risk is most likely to be shared under a joint venture arrangement.
Due to CCS, the SMR/gasification plant operator would likely form a ‘take or pay’ arrangement with a separate entity responsible for transporting and storing the CO2. While a third party could be engaged to build and operate the CO2 pipeline and storage, there is still an important role for the government in managing the long-term risk associated with CO2 storage in underground aquifers, a risk that is unlikely to be accepted by the private sector.Opportunities
Australia has a rich history of generating economic opportunities through the export of its natural resources like Uranium which has seen a downtrend and thermal coal which is a major risk as global trends favor low carbon economy. In contrast, the global hydrogen market is expected to reach $155 billion by 2022. Australia’s existing trading partners such as North Korea and Japan, who are comparatively resource-constrained, are currently implementing policy commitments for hydrogen imports and use. Continuous improvement in the cost and performance of hydrogen-related technologies has accelerated over the past three years along the entire value chain.
Australia has yet to create its own solar or storage industry, relying instead on foreign solutions. There remain serious sustainability challenges to broad adoption of lithium batteries. Hydrogen offers a new, sustainable energy storage and future transport option. Hydrogen also offers an opportunity for optimisation of renewable energy use between the electricity, gas and transport sectors.
Hydrogen can play a key role in protecting Australia from supply shocks by localising liquid fuel supplies. Gas prices currently remain high compared to some overseas markets. Hydrogen could replace natural gas as a low emissions source of heat as well as a potential feedstock for industrial processes.
Additionally, South Australia has fast become a global testbed for the integration of new energy technologies. With a high proportion of wind and solar power already in the network and a pipeline of hydrogen demonstration projects, continued investment in hydrogen production and use is likely to be a significant enabler for other Australian states in developing their local industries.
The figures for the finite indigenous reserves and imports provide a strong case for Australia moving away from oil-based energy production and the development of alternative transport fuels.Challenges and Barriers
The embryonic stage of the global hydrogen industry means a lot of barriers need to be crossed and risks need to be managed. The cost of establishing a hydrogen economy will be high. The current application of hydrogen remains mainly in the industrial sector. In terms of infrastructure, the coal extraction, transportation, and power generation industry in Australia is well established. Coal reserves for both export and domestic use are located within 200 km of the eastern Australian capitals (Brisbane, Sydney, Melbourne, Canberra, Hobart).
For both SMR and coal gasification, the LCOH is impacted by the cost of gas and coal. While significant fluctuations in the price of black coal are low risk, trends relating to the price of natural gas, particularly in an Australian context, is likely to be of greater concern.
The cost of electricity remains comparably high in Australia which adds to production costs. When using surplus renewable energy, the relatively low-capacity factor is driving the cost of hydrogen, but as more VRE is introduced, this would bring the prices down. The water required for a large-scale hydrogen production industry will be significant. Australia will need to consider how to balance hydrogen’s demands with other water priorities.
The idea of using hydrogen as a fuel source to reduce greenhouse gas emissions is an ambitious and altruistic notion. It is not without its challenges ranging anywhere from the current technology and cost to infrastructure and safety.
The expected decreased demand for fossil fuels, coupled with the falling costs associated with renewable energy projects, are driving major oil and gas companies – including bp, Total and Shell – to actively restructure their businesses to add more renewable power projects to their portfolios.
This is according to the latest research from data and analytics company GlobalData. The study shows that within the renewable power sector, solar and wind energy are expected to show the highest growth rates over the next ten years. Oil and gas companies will increasingly invest in these sectors as a way to reduce their carbon intensity and align with the changing energy mix, according to GlobalData.
GlobalData research also shows that oil and gas EPC vendors are enabling the energy transition by building capabilities to set up renewable energy infrastructure.
Ravindra Puranik, Oil and Gas Analyst at GlobalData, comments: “Global power demand is expected to grow at a compound annual growth rate (CAGR) of 2.5% from 2020 to 2030, according to GlobalData. A significant portion of this will be fulfilled by renewable power generation. This growth outlook makes renewable power a key market for players across the energy sector, including oil and gas companies whose traditional market is at risk amid the transition to low-carbon sources.”
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A key driver enabling the transition to renewable power is falling cost. Puranik adds: “Traditionally, renewable power projects had a significant cost disadvantage over coal- and gas-fired power plants. However, in recent years, their economic competitiveness has improved significantly due to government policies and incentives, as well as technological advances. This has incentivized oil and gas majors such as BP, Equinor and Shell to invest in wind power generation. BP and Total are also leading the way in terms of upcoming solar power capacity.”
According to Puranik, solar power generation, including solar PV and solar thermal, is expected to grow at a CAGR of 11.9% between 2020 and 2030, with onshore and offshore wind markets expected to grow at a CAGR of 9.4% over the same period.
Puranik states another factor spurring oil and gas companies to cleaner energy sources is that governments around the world are actively focusing on reducing carbon emissions and enacting laws to facilitate decarbonisation in their countries, thereby driving the growth of wind and solar. “Electrification, based on renewable energy sources, is an ideal approach to reduce carbon emissions. It also marks a strategic shift away from fossil fuels in the global effort to mitigate the threat to climate change,” adds Puranik.
GlobalData research suggests that the growing role of renewable energy poses a major threat to fossil fuel-based power generation. The share of natural gas-based power generation will be threatened by renewables growth and is likely to be the next biggest loser in the global power generation mix after coal.
With the increase in Electric Vehicles’ availability in Midwest states, it is time to acknowledge the opportunities for charging EVs at MISO, the regional grid operator. Aggregated EVs can be a distributed energy resource (DER). Therefore, aggregators are ideally positioned to bid EVs into the MISO market. MISO and other grid operators can enable EV prospects by allowing aggregated EVs to participate in the energy markets.
It is no secret that MISO is building the next-generation market systems platform in parallel with its existing market platform. FERC has rejected MISO’s request to extend the Electric Storage Resource (ESR) market participation model in the new platform. So, MISO is preparing to integrate ESRs on legacy market systems by June 2022.
MISO markets have plenty of experience with aggregators, mostly from Illinois, from a demand response product perspective. Demand response reduces demand, which is one of the operating modes of an aggregated EV such as Electric School Buses. As the Advanced Energy Economy (AEE) recently released report on Order 2222 suggests, 480,000 school buses serve more than 25 million students in the US. Hence, we can expect MISO to see market integration of aggregated electric school buses.
It is important to remember the FERC Order 841 definition of ESR at this stage, which states:
“A resource capable of receiving electric energy from the grid and storing it for later injection of electric energy back to the grid.” FERC also said, “ESRs located on the interstate transmission system, on a distribution system, or behind the meter fall under this definition.” Hence it is clear that aggregated EVs can operate as demand response and ESR at MISO.MISO lagging in Distributed Energy Resource (DER) penetration in real-time markets
FERC’s broad definition of DER in Order 2222 means many opportunities for distributed resources at MISO. A DER is defined by FERC as “any resource located on the distribution system, any subsystem thereof or behind a customer meter.”
A recent “State of the Market” report from MISO’s market monitor suggests MISO has 13,675 MW of different kinds of planning demand response. Planning DR means programs that participate towards meeting the MISO planning reserve margin. The majority of these DR programs are “Load Modifying Resources (LMRs).” MISO has different kinds of LMRs: behind-the-meter generation LMRs, demand response LMRs, emergency DR LMRs, and energy efficiency LMRs. These multiple market products for planning DR mean aggregated electric school buses have multiple ways to register with the MISO market registration process.
FERC Orders 841 on energy storage and 2222 on DER Aggregation push MISO to interconnect aggregated technologies
Even though MISO has a large amount of planning DR, MISO has a limited amount of operations DR. These resources, called Demand Response Resource (DRR) Type I and II, are less than 1,000 MW out of 13,675 MW. Operations DR means DR programs that can react to MISO operator signals in real-time. As the AEE report asserts, DERs such as aggregated school buses should have the ability to update their real-time offers in organized markets.
While MISO is 12 months away from implementing Order 841 ESR in the market platform, it is 9 months away from filing a compliance plan for Order 2222 on aggregated DER. This timeline means MISO is working with its stakeholders to propose a plan, take stakeholder comments and ultimately file at FERC in April 2022. We don’t know the implementation date for Order 2222 at MISO.
Order 2222 states aggregated EVs, fleets of electric trucks, and electric school buses must first interconnect with electric distribution companies. Once the distribution company studies them for distribution grid impacts, aggregated EVs must seek their state retail authority’s permission to connect to MISO’s transmission grid. Once that state approval is given, based on the desired service, aggregated EVs might have to go through the generator interconnection process for reserving transmission service on the MISO grid. Or they can directly participate in MISO real-time markets.
Interconnecting resources less than 5 MW goes through MISO’s fast-track process. Less than 20 MW falls under Small Generator Interconnection Process, and more than 20 MW are Large Generator Interconnections. While MISO is still discussing interconnection requirements for aggregated DERs and bringing together retail authorities for a workshop, there is concern about interconnections between 5 MW and 20 MW because they fall in that sweet spot between the fast track and small generator interconnection process. The former can take less than 90 days, and the latter could take years for aggregated DERs to interconnect.Conclusion
In this 3-part blog series, we started the EV journey at MISO by laying out why EV prospects are looking up given Midwest’s electric grid’s uniqueness. We next talked about MISO transmission planning assumptions and how they are looking good for EV prospects. Finally, to wrap up, we covered MISO market prospects for aggregated EV in more depth. See part 1 here. And part 2 here.
NHPC Limited and Bihar State Power Holding Company (BSHPC) have signed a memorandum of understanding (MOU) for implementation of the 130.1-MW Dagmara hydroelectric project in the Supaul district, Bihar State, India.
The MOU was signed and exchanged by the signatories in the august presence of Shri R.K. Singh, Hon’ble Minister of State (Independent Charge) Power and New & Renewable Energy & Hon’ble Minister of State Skill Development & Entrepreneurship, Government of India and Shri Bijendra Prasad Yadav, Hon’ble Energy Minister, Govt. of Bihar.
Speaking on the occasion, Shri R.K. Singh thanked NHPC for its speedy response and cooperation in taking up the project, which reflects their keen spirit toward their aim of development of hydropower. He further said that hydropower is very important in the background of climate change and in the shift from fossil to non-fossil fuel for future generation.
In his address Shri Bijendra Prasad Yadav, Hon’ble Energy Minister, Govt. of Bihar conveyed his gratitude on behalf of state government to the Ministry of Power and NHPC for taking up the implementation of the Dagmara Project. He further said that the project will bring all-round progress and development in the state.
The Dagmara project, the largest hydropower project of Bihar, is to be implemented by NHPC on ownership basis. The powerhouse will contain three turbine-generator units.
“The Dagmara H.E. Project will be a landmark project in the power sector scenario of Bihar as far as green power is concerned,” said Shri A.K. Singh, CMD, NHPC. “Apart from generating clean and green power, the execution will boost the socio-economic and infrastructure development in the area and shall also create employment opportunities.”
NHPC is a Category-A Miniratna Company under Ministry of Power, Govt. of India in the field of hydropower. NHPC has 24 operational power stations with a total installed capacity of 7,071 MW.