South Korean lithium-ion battery system manufacturer Kokam has entered into a contract to supply a Tahiti utility with a 15 MW/10.4 MWh battery energy storage system (BESS).
Electricité de Tahiti (EDT), a subsidiary of ENGIE, will obtain the country’s first Virtual Synchronous Generator to replace the utility’s spinning reserve diesel generators. The move works to decarbonize and strengthen the grid while allowing for more renewable energy.
“Electricité de Tahiti’s BESS demonstrates how innovative and intelligently designed battery solutions can help utility and industrial customers lower greenhouse gas emissions while also improving their bottom line and increasing grid reliability,” said Ike Hong, chief marketing officer of Kokam.
EDT expects to reduce fuel costs by up to ~€1.25M per annum by incorporating more renewable generation sources and improving the performance of its diesel genset.
Ultra-luxury electric vehicle maker Faraday Future completed a 2,270 mi. road test of its FF 91 model as the company prepares for production.
The test along the historic U.S. Route 66 gathered data from real-world conditions and user behaviors, stretching from Chicago, Illinois to Santa Monica, California.
“This testing journey along historic Route 66 allowed us to put FF 91 through many diverse environments and conditions found only in the central and southwest portions of the U.S. and allowed us to capture real-world data on FF 91,” said FF Global CEO Dr. Carsten Breitfeld. “FF’s overall testing and validation strategy will ensure best-in-market performance, safety, and user confidence, and to make sure the battery, electric propulsion, chassis, suspension, and other vehicle systems perform under these harsh conditions, while also ensuring a smooth and comfortable and connected experience with the driver and passengers in the FF 91.”
The company said the test, which included evaluations of the battery and propulsion components, validated the FF 91’s production timeline to launch in 2022.
The FF 91 is equipped with interior cameras and microphones to support videoconferencing through a Rear Seat Display. The vehicle features a 130 kWh battery pack.
FF was listed on NASDAQ last month as FFIE.
by Lisa Prevost, Energy News Network
Connecticut regulators have finalized new rules paving the way for a major expansion of battery storage and electric vehicle charging, part of a broader effort to modernize the state’s electric grid.
Since the wide-ranging “grid mod” proceedings began in fall 2019, all but one of the 11 subject-area tracks in the docket have either concluded or made significant progress, according to Marissa P. Gillett. Gillett set the process in motion when she took over as chair of the Public Utilities Regulatory Authority.
While “anyone who knows me knows that I wish I’d been done with this six months after I started,” Gillett said she is nonetheless proud that the agency managed to “largely stay the course” despite a pandemic, the fallout from Tropical Storm Isaias, rate cases and considerable staff turnover.
The ultimate goal of the proceeding is to make the electric grid more efficient, resilient, equitable, and supportive of clean energy. Over the past two years, the authority has held multiple technical meetings and listening sessions in each of the subject areas, and solicited comments from interested stakeholders before issuing the final initiatives.EV charging and ‘equitable distribution’
The charging infrastructure program was guided by the state’s commitment to a 10-state memorandum of understanding, signed in 2013, to collectively deploy 3.3 million zero-emission vehicles by 2025. Connecticut’s target is 125,000-150,000 electric vehicles by that time, a major jump from the current 17,000.
The plan provides incentives for installing charging stations, and sets specific deployment targets for residential single-family and multifamily charging stations, workplace charging stations, and fast-charging stations. Setting those targets should help “drive toward a more equitable distribution,” Gillett said. “It’s reserving funding for the different sectors.”
The plan also includes a lease option, whereby multifamily dwelling owners may opt to pay a monthly fee to the utilities to supply charging stations. Gillett said that option could help boost deployment in affordable housing developments.
Homeowners installing a charger will receive rebates of up to $500. Multifamily and commercial building owners will be rebated up to half of the charging station cost, and the utilities will cover the cost of any infrastructure investments required between the distribution system and the charger.
The maximum incentive per site is $20,000, although sites in underserved communities will be eligible for up to $40,000. (Those maximums rise to $150,000 and $250,0000 for fast-charging stations.) The program will be funded through electric rates, but will be reviewed every three years to determine whether ratepayers are receiving the expected benefits.
Paul Vosper, chief executive officer of JuiceBar, a charging technology manufacturer based in Norwalk, said he thinks the $20,000 cap is too low because installation costs run as high as $5,000 per charger. A commercial site owner installing three or more chargers would easily exceed the cap, he said.
While the program will help Connecticut begin to catch up with surrounding states, as measured by chargers per capita, Vosper said what would really drive deployment is if lawmakers approve the Transportation Climate Initiative. That multi-state program, supported by Gov. Ned Lamont, failed to win lawmakers’ support this past session after gas station owners and Republican lawmakers blasted it as a gas tax.
The regional cap-and-invest program is designed to reduce vehicle emissions by requiring wholesale fuel suppliers to purchase allowances for the pollution created by their products. States could use the proceeds to make infrastructure investments to further clean up the air, including installing charging infrastructure.
“We have to take action now — we’ve got about 10 years to sort this out,” Vosper said. “This is a very smart way to invest today in our infrastructure and address climate change at the same time.”
The electric storage plan follows the legislature’s passage this year of a law establishing a statewide goal of deploying 1,000 megawatts of energy storage by 2030. Connecticut is the eighth state to set such a target.
The nine-year program includes a set of upfront incentives that will reduce ratepayer costs to purchase and install storage systems, which are typically paired with solar. Customers will receive additional performance incentives if they agree to allow the utilities to draw on their storage systems during critical demand periods.
Residential customers will be eligible for upfront incentives up to a maximum of $7,500, with the highest incentives reserved for low- to moderate-income customers. Those customers include households with incomes below 60% of the area median, as well as those in environmental justice communities and distressed municipalities.
Commercial and industrial customers will be eligible for incentives covering up to a maximum of 50% of the project cost.Exploring ‘possibilities for innovation’
In addition to those plans, the Public Utilities Regulatory Authority also recently issued a draft proposal for how to drive the adoption of “non-wires alternatives” to traditional transmission and distribution methods. Instead of simply expanding substations and replacing transformers, the proposal envisions a method for exploring ways to upgrade less expensively by using such technologies as battery storage, demand response, and microgrids.
The authority calls for a program overseen by an independent consultant, who will review all proposed distribution system upgrades over $500,000 and, working with various stakeholders, determine if lower-cost or more resilient alternatives are feasible. The consultant would also review proposals for alternatives submitted by the distribution companies — Eversource and United Illuminating — as well as third-party competitors.
The proposal requires Eversource and United Illuminating to provide potential bidders with access to their distribution system data, which the authority said is necessary to make the planning process “much more open and transparent.”
Eversource had argued that the process should be run by the utilities, since they already have the expertise. Eversource spokesperson Mitch Gross said that the company agrees with the objective of transparency, but thinks that bringing in a third-party administrator is unnecessary and will add duplicative costs.
“Transitioning to a modern, clean and resilient electric distribution system, while meeting the mandate to provide safe and reliable service, cannot occur by outsourcing planning and engineering, and leaving the utility as a bystander in the process — an option of last resort,” Gross said.
But Oliver Tully, a policy strategist at the Acadia Center, said having a neutral facilitator for soliciting projects, reviewing proposals and making recommendations to regulators will help eliminate potential conflicts of interest.
“I could see a situation where there would be a conflict on projects where the utilities would make a return as opposed to ones where they might not earn as much money,” he said. He noted that Maine also has a third-party coordinator for their non-wires alternatives program.
Tully praised the proposal for placing a priority on transparency and open access to energy system data.
“They recognize the importance of not having restrictions in terms of potential ownership models for the non-wires alternatives,” he said. “That opens up more possibilities for innovation.”
We are six months away from PJM and ISO-NE filing their compliance plans for FERC Order 2222. CAISO and NYISO already filed their plans because they didn’t seek an extension. MISO and SPP compliance plans are due in April 2022. If renewable developers want to engage in RTO committees on Order 2222, now would be the right time to participate. At least 3 issues are ripe for RE developer participation because they hit on the revenue streams offered in Order 2222.
Net metered solar eligibility to participate in wholesale markets, distribution utility override leading to non-performance penalties, and multiple entity interconnection processes are the main issues at this stage of RTO proposed compliance frameworks.
FERC Order 2222 offers Aggregated Distributed Energy Resources (DERs) the opportunity to participate in the wholesale energy, capacity, and ancillary services markets. Without any stakeholder process, both CAISO and NYISO filed their compliance plans at FERC. These filings might lead to protests from stakeholders who need missing details from those RTO plans.
MISO and SPP RTOs are in a unique position given the vertically integrated states in their footprint. But both MISO and SPP have started DER Task Force meetings in earnest and are regularly filing their quarterly reports at FERC as a condition of FERC approval for their extension request, which is due in April.
PJM and ISO-NE are only 6 months away from filing their compliance plans. Stakeholders are participating in and commenting on PJM and ISO-NE proposed compliance frameworks. Since it is difficult for a small RE developer to follow all RTO markets, this blog summarizes the 3 key issues to date.
Is Net Metered Solar ineligible to participate in wholesale markets?
RTOs are specifically calling out net-metered solar programs. [Slide 89 in PJM presentation] They are saying one cannot participate in both wholesale and retail when Order 2222 allows both. There is room for discussion because it is unclear what happens in states with mandated net-metered solar. Net metered solar sends excess solar energy back to the distribution grid. And it depends on the solar customer contract with the distribution utility. One distribution utility contract specifies that they don’t expect the end-use customer to engage in the business of selling energy in the following statement,
“primary business is not the generation of electricity for retail or wholesale sale from the same facility.”
According to the DSIRE website that N.C. Clean Energy Technology Center at N.C. State University operates, there are more than 40 states that have net-metered solar. So, it is unclear whether all these state’s solar is ineligible to participate in wholesale markets. Hence this is the first issue for distributed solar developers to engage in RTO proceedings on Order 2222.
Developers may incur non-performance penalties in a scenario when an Electric Distribution Company (EDC) overrides RTO dispatch.
More representatives of distribution utilities are participating in RTO meetings and expressing concerns about DERs. [Slide 8 in SPP presentation] Since distribution utilities are responsible for the safety and reliability of the distribution system, where RTO has no jurisdiction, they are planning to override RTO dispatch for an aggregated DERs in those emergencies. RE developers need to know this because there is room for misinterpretation on the reliability-driven curtailment versus the economic-driven curtailment of DERs.
None of the developers or stakeholders have any issue with distribution utility override in situations that impact the safety and reliability of the distribution grid. However, the concerns for developers would be non-performance penalties from the market operator when output is reduced for the distributed asset as a result of override. It is unclear at this stage how many of these distribution company overrides would occur and whether they would be mostly for distribution system outages as the initial case might be, and what penalties the RTO assesses for non-performance. This override is why developers should pay attention to this issue.
Many handoffs in aggregated DERs interconnection lead to possible delays.
Finally, interconnecting DERs could be time-consuming. [Slide 5 in MISO presentation] Before market registration, most RTOs require prior approvals from state authorities, called RERRAs, including EDC and TO interconnection study approvals. These multiple approvals could lead to delays.
The specific point of discussion at the RTO stakeholder committee level is what happens in that 60-day window for distribution utilities to process the aggregator’s interconnection request. Some SPP distribution utilities want SPP staff to stop processing the registration process while dealing with anomalies in the paperwork, such as attestations if small utilities have “opted-in” wholesale market participation.
Interconnecting large generators is squarely within the RTO jurisdiction, but in Order 2222, DERs don’t have to go thru RTO interconnection queues. That means DERs must knock on the doors of each state and each distribution utility for interconnection. Hopefully, states would step in and provide a transparent interconnection queue on the distribution grid, much like RTOs on the transmission grid.
If developers have no resources to participate in RTO meetings, they must send comments via associations.
Now is the time for RE developers to engage RTO staff and other interested stakeholders to get their comments across. One way to do that is via used cases. If developers have specific scenarios like net-metered solar + storage, solar + demand response, or other situations that apply to their business models, now would be the time to raise the issue at RTO meetings.
If that is not an option given limited resources, developers should send comments through the associations such as Advanced Energy Economy (AEE) and Advanced Energy Management Alliance (AEMA). Both AEE and AEMA have a track record of commenting in FERC dockets and RTO committees.
FERC Order 2222 brings more aggregated distributed energy resources on the transmission grid for the grid services benefits that they provide. Hence now is the time for RE developers to engage at RTOs such as PJM, ISO-NE, MISO, and SPP, because there is time before RTOs file compliance plans.
North Star Renewables has secured a $131 million loan to build a new fleet of offshore wind farm support vessels in the UK.
The company will build three new Service Operations Vessels (SOVs) to be delivered to the Dogger Bank offshore wind farm on long-term contracts. Allianz Global Investors backed the loan, valued at £96 million.ABERDEEN, SCOTLAND, JUNE 2021: North Star Shipping provides 24/7 support for clients in one of the world’s busiest and most hostile marine environments. They invest in people and vessels and are focused on delivering safety, service and quality across four key areas: offshore support, tanker assist and emergency response and rescue. (Photo: Ross Johnston/Newsline Media)
“This investment from AllianzGI is a first for our industry and attracting project finance from such a well-respected, global investor demonstrates the confidence in our capabilities to deliver and operate our new SOVs which have been a transformational step for the company in terms of our energy transition,” North Star CEO Matthew Gordon said in a statement. “We are highly motivated and driven by our ability to innovate through our technology partners, and our ambition to deliver best-in-class vessel solutions for the offshore wind market in the UK and abroad.”
North Star’s vessels provide accommodations to offshore wind turbine technicians and act as a warehouse for supplies.
The first vessel of the new fleet is expected to be delivered in Summer 2023.
Most of America’s 107,000 gas stations can fill several cars every five or 10 minutes at multiple pumps. Not so for electric vehicle chargers – at least not yet. Today the U.S. has around 43,000 public EV charging stations, with about 106,000 outlets. Each outlet can charge only one vehicle at a time, and even fast-charging outlets take an hour to provide 180-240 miles’ worth of charge; most take much longer.
The existing network is acceptable for many purposes. But chargers are very unevenly distributed; almost a third of all outlets are in California. This makes EVs problematic for long trips, like the 550 miles of sparsely populated desert highway between Reno and Salt Lake City. “Range anxiety” about longer trips is one reason electric vehicles still make up fewer than 1% of U.S. passenger cars and trucks.
This uneven, limited charging infrastructure is one major roadblock to rapid electrification of the U.S. vehicle fleet, considered crucial to reducing the greenhouse gas emissions driving climate change.The Conversation, CC BY-ND
Over many decades, the U.S. has built systems of transportation, heating, cooling, manufacturing and agriculture that rely primarily on fossil fuels. The greenhouse gas emissions those fossil fuels release when burned have raised global temperature by about 1.1°C (2°F), with serious consequences for human lives and livelihoods, as the recent report from the U.N. Intergovernmental Panel on Climate Change demonstrates.
The new assessment, like its predecessor Special Report on Global Warming of 1.5°C, shows that minimizing future climate change and its most damaging impacts will require transitioning quickly away from fossil fuels and moving instead to renewable, sustainable energy sources such as wind, solar and tidal power.
That means reimagining how people use energy: how they travel, what and where they build, how they manufacture goods and how they grow food.Gas stations were transport infrastructure, too
Gas-powered vehicles with internal combustion engines have completely dominated American road transportation for 120 years. That’s a long time for path dependence to set in, as America built out a nationwide system to support vehicles powered by fossil fuels.
Gas stations are only the endpoints of that enormous system, which also comprises oil wells, pipelines, tankers, refineries and tank trucks – an energy production and distribution infrastructure in its own right that also supplies manufacturing, agriculture, heating oil, shipping, air travel and electric power generation.
Without it, your average gas-powered sedan wouldn’t make it from Reno to Salt Lake City either.
Fossil fuel combustion in the transport sector is now America’s largest single source of the greenhouse gas emissions causing climate change. Converting to electric vehicles could reduce those emissions quite a bit. A recent life cycle study found that in the U.S., a 2021 battery EV – charged from today’s power grid – creates only about one-third as much greenhouse gas emissions as a similar 2021 gasoline-powered car. Those emissions will fall even further as more electricity comes from renewable sources.
Despite higher upfront costs, today’s EVs are actually less expensive than gas-powered cars due to their greater energy efficiency and many fewer moving parts. An EV owner can expect to save US$6,000-$10,000 over the car’s lifetime versus a comparable conventional car. Large companies including UPS, FedEx, Amazon and Walmart are already switching to electric delivery vehicles to save money on fuel and maintenance.
All this will be good news for the climate – but only if the electricity to power EVs comes from low-carbon sources such as solar, tidal, geothermal and wind. (Nuclear is also low-carbon, but expensive and politically problematic.) Since our current power grid relies on fossil fuels for about 60% of its generating capacity, that’s a tall order.
To achieve maximal climate benefits, the electric grid won’t just have to supply all the cars that once used fossil fuels. Simultaneously, it will also need to meet rising demand from other fossil fuel switchovers, such as electric water heaters, heat pumps and stoves to replace the millions of similar appliances currently fueled by fossil natural gas.The infrastructure bill
The 2020 Net-Zero America study from Princeton University estimates that engineering, building and supplying a low-carbon grid that could displace most fossil fuel uses would require an investment of around $600 billion by 2030.
The infrastructure bill now being debated in Congress was originally designed to get partway to that goal. It initially included $157 billion for EVs and $82 billion for power grid upgrades. In addition, $363 billion in clean energy tax credits would have supported low-carbon electric power sources, along with energy storage to provide backup power during periods of high demand or reduced output from renewables. During negotiations, however, the Senate dropped the clean energy credits altogether and slashed EV funding by over 90%.
Of the $15 billion that remains for electric vehicles, $2.5 billion would purchase electric school buses, while a proposed EV charging network of some 500,000 stations would get $7.5 billion – about half the amount needed, according to Energy Secretary Jennifer Granholm.
As for the power grid, the infrastructure bill does include about $27 billion in direct funding and loans to improve grid reliability and climate resilience. It would also create a Grid Development Authority under the U.S. Department of Energy, charged with developing a national grid capable of moving renewable energy throughout the country.
The infrastructure bill may be further modified by the House before it reaches President Joe Biden’s desk, but many of the elements that were dropped have been added to another bill that’s headed for the House: the $3.5 trillion budget plan.
As agreed to by Senate Democrats, that plan incorporates many of the Biden administration’s climate proposals, including tax credits for solar, wind and electric vehicles; a carbon tax on imports; and requirements for utilities to increase the amount of renewables in their energy mix. Senators can approve the budget by simple majority vote during “reconciliation,” though by then it will almost certainly have been trimmed again.
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Overall, the bipartisan infrastructure bill looks like a small but genuine down payment on a more climate-friendly transport sector and electric power grid, all of which will take years to build out.
But to claim global leadership in avoiding the worst potential effects of climate change, the U.S. will need at least the much larger commitment promised in the Democrats’ budget plan.
Like an electric car, that commitment will seem expensive upfront. But as the recent IPCC report reminds us, over the long term, the potential savings from avoided climate risks like droughts, floods, wildfires, deadly heat waves and sea level rise would be far, far larger.
Offshore wind development offers an answer to California’s reliability problem, and could greatly help the state reach its net-zero goals, according to a new report.
The University of Southern California’s Schwarzenegger Institute for State and Global Policy report, California’s Offshore Wind Electricity Opportunity, states that offshore wind could provide $1 billion in resource cost savings, improved reliability of services and more stand capacity factors, and thousands of new jobs.
An estimated 20 GW of viable offshore wind capacity exists in California, the report says, with the potential to provide 25% of the state’s future electricity needs and reduce the need for backup gas generation.
“California could reap additional economic co-benefits from the development of a local offshore wind industry, boosting manufacturing and creating still additional jobs,” the authors wrote. “Additionally, OSW has the potential to advance environmental justice through its reduction of ordinary air pollutants in urban areas and can bring economic opportunities to lagging areas of the state.”
But the report outlines significant challenges for offshore wind growth in California, too.
The cost of offshore wind is still double that of solar-PV and onshore wind and isn’t expected to reach parity until at least 2030. Additionally, new transmission infrastructure and upgrades are likely needed.
“Despite these hurdles, offshore wind has the potential to play a pivotal role in meeting the goals set by SB 100, as well as turning California into a global hub for offshore wind development,” the authors wrote.
Meanwhile, California, in the midst of an energy crisis due to high temperatures, wildfires, and drought, is seeking relief with the import of five 30-MW gas-fired emergency generators, according to multiple news sources.
Bloomberg, California Energy Markets and others have reported that the California Department of Water Resources is procuring the gen-sets on a temporary basis. Gov. Gavin Newsom declared an energy state of emergency earlier.
Contributed by Mike Phillips, CEO and co-founder of Sense
The IPCC report on climate change has been called a “code red” for humanity, with its finding that temperatures rose more in the past 50 years than any time over the past 2000 years, and is continuing to rise more rapidly than expected. Scientists say a catastrophe can be avoided only if the world acts fast to make huge cuts in carbon emissions immediately – actions we take now will bake in future emissions.
These dire scenarios tell us that we all need to get serious about eliminating carbon fuels from our lives. Consumers make buying decisions every day that can have a big, collective impact on slowing climate change. The renewable energy industry and utilities have a unique opportunity to educate consumers about how that buying power can turn into climate action.
Starting now, any new appliance in a home should be electric. Homeowners should be buying and installing air conditioners with heat pumps. They should stop installing gas or oil-powered furnaces in their homes. Consumers should not buy another gas-powered car. The bottom line is, from today forward, everyone needs to stop burning fuels in their houses and electrify everything instead.
This approach is important because each purchasing decision a consumer makes will impact the next 20 years. Each new gas car could be on the road for a decade or more. A new gas furnace creates 15-20 years of carbon emissions. We have the technology today that can make a dent in carbon emissions and we must stop adopting technology that sustains the carbon-based approach.
News stories about the utility industry are more common as extreme weather events affect peoples’ lives. This general interest gives energy providers an opening to tell consumers how they can contribute to slowing climate change by following three principles in their day-to-day lives:
1. Electrify everything in your home. We need to do everything we can to eliminate carbon fuels like natural gas, oil, and propane from our homes. Replace oil and gas burning furnaces with heat pump technology, either air-source or geothermal. Replace gas stoves with induction stoves, which use less energy and don’t emit noxious fumes. Use an electric or solar-powered hot water heater.
Include vehicles in your home’s electrification. There have never been more EV choices from automakers, and the Biden administration plans to build out more EV charging stations across the country. A typical passenger vehicle emits about 4.6 metric tons of carbon dioxide annually according to the EPA. Transportation is responsible for more greenhouse gas emissions than any other sector and vehicles are responsible for about a quarter of global CO2 emissions.
2. Make the move to clean energy. Install solar panels on your roof or choose solar energy from your utility. Solar panels are the quickest way to get an all-electric home to net-zero energy usage, and the initial investment typically pays off in 8 years – or less, depending on state and local incentives and utility rates. The industry and government policy should support rebates and tax breaks that make solar panels attractive to more homeowners at every income level.
3. Become an energy-savvy consumer. Every utility should be providing a way for their customers to easily monitor their energy usage at home in real-time so they can see how to reduce it or shift it to lower cost and lower carbon times. Most homeowners can save 20% of their electricity usage through energy awareness at home.
Instead, the fossil fuel industry is perpetuating the carbon economy. The industry’s “Cooking with Gas” campaign targets young people on social media, although cooking with gas leads to high kitchen concentrations of nitrogen oxides—respiratory irritants implicated in asthma and other illnesses. The American Petroleum Institute’s “Energy for Progress” ad campaign describes natural gas as “clean” or “environmentally friendly” when it has become clear that its production and rapidly increasing use have major climate change impacts.
Meanwhile, utilities are spending ratepayer dollars to put outdated “smart” meters on peoples’ houses while there are next-generation meters with energy intelligence built into them that can truly help with climate change by tracking electricity in real-time, giving residents insights, and encouraging them to work with utilities to shift loads to lower carbon times, update wasteful appliances, or avoid peak demand events.
Utilities’ energy efficiency programs keep looking for small, incremental gains rather than collaborating with their customers to make the biggest, fastest impact possible. For example, many energy efficiency programs are focused on tightening up the home’s envelope, with incentives for insulating, which makes good sense because heating and cooling can account for 43% of a year’s total energy spending in most homes. But smart home technology can go a step further by telling consumers if their HVAC system is less efficient than other similar homes, making them an ally in the utility’s efforts to target potentially big gains in energy efficiency.
The ENERGY STAR program has had a major impact on home energy savings, to the extent that entire categories of appliances like refrigerators have made big improvements in efficiency. Similarly, LED light bulbs have made lighting amazingly efficient. These categories are no longer areas for future gains.
Now it’s the hidden energy hogs that are undermining efficiency efforts. Whether it’s old consumer electronics, inefficient HVAC systems, always-on pool pumps, or heated towel bars, when the cost of these hidden energy hogs becomes visible to consumers, they can take action to address them.
In the near future, smart home technologies will go a step further by automating household appliances to reduce carbon emissions. A recent study by Sense and Singularity Energy found that carbon emissions from charging EVs could be reduced by up to 43% in California by automating charging at times when the carbon intensity of electricity on the grid is lower. Similarly, smart home apps will let you automatically schedule your dishwasher to run when energy from the grid is cleanest.
This latest report from the UN is a call to action. It’s time to make every consumer an ally in the epic battle to slow climate change.
About the author:
This article was contributed by Mike Phillips, CEO and co-founder of Sense, which brings energy intelligence to homes, making them smarter and more efficient. Learn about real-time home energy monitoring at sense.com.
Canada’s largest municipally-owned electric utility has launched a pilot program that allows customers with distributed energy resources (DERs) to participate in an energy marketplace using blockchain technology.
Alectra has launched a transactive software platform, GridExchange, to enable customers with solar panels, battery storage, and electric vehicles to participate in a marketplace. Twenty-one households in Ontario will participate in the three-month pilot program.
“The GridExchange pilot project plays a pivotal role in supporting consumers by offering them greater control over their energy usage,” said Brian Bentz, president and CEO, Alectra Inc. “In alignment with Alectra’s commitment to be net-zero by 2050, the launch of GridExchange will help us continue to lower emissions and create value for customers and the Ontario power grid.”
Customers in the pilot program will be compensated with cash and rewards for participating in clean energy transactions.
Broad Reach Power is on a battery buying spree.
The Houston-based independent power producer – owner of 13 gigawatts of utility-scale solar and solar projects across four states – entered into an agreement with Sungrow Power Supply Co. to purchase 1,000 MW/1,200 MWh of energy storage technology to build out six standalone battery storage projects in Texas.
Doug Moorehead, Broad Reach Power’s managing partner and chief technology officer, said the order is one of the largest ever for the energy storage industry.
“Broad Reach is committed to investing in and developing energy infrastructure to help support the grid in key markets such as Texas,” Moorehead said. “Broad Reach’s energy storage projects, connected at both distribution voltages and high voltage transmission, are critical in the further growth of solar and wind renewable generation in the US as well as the resiliency and reliability that US grid operators will increasingly demand in the future.”
Despite ERCOT lacking a market for storage capacity, Moorehead sees incredible growth opportunities for battery storage in the region. But he said a market for storage capacity would encourage a more rapid shift toward renewable sources.
“I do think ERCOT is going to be the first one to be 100% renewable resources and it’s going to be for some energy storage capacities that are going to get it there,” he said.
Currently, wind and solar make up about 28% of generating capacity in ERCOT.
Broad Reach Power owns 13 gigawatts of utility-scale solar and energy storage power projects in Montana, California, Wyoming, Utah, and Texas.
Mitsubishi Electric announced the acquisition of Smarter Grid Solutions — a UK-based company providing software management for the distributed energy resources market.
SGS’ DER management system facilitates the integration of DER into markets and grids, including grid capacity management, interconnection, and energy as a service.
“We are very excited to bring SGS into Mitsubishi Electric. They are committed to the mission of decarbonizing electric power production and have spent the last decade developing world-class products and processes. We look forward to marrying their products with our suite of grid control products to help our customers respond to changes and still get the best performance from their electric grids.” said Brian Heery, president and CEO of Mitsubishi Electric Power Products, Inc (MEPPI).
The acquisition is expected to close in the coming weeks. ME did not disclose the acquisition cost of SGS.
Trina Solar’s 210 PERC solar cell has achieved 23.56% efficiency, a record for 210 P-type monocrystalline silicon PERC cells, the company said this week.
The efficiency rating was independently confirmed by the National Center of Supervision and Inspection on Solar Photovoltaic Product Quality.
“We are proud to announce the latest achievements developed by our technical team, to realize the batch efficiency over 23.5% for larger-area 210mm high-efficiency PERC cells in production,” said Dr. Yifeng Chen, head of the high effiency cell and module R&D center at Trina Solar. “This demonstrated that 210 cells can achieve very high efficiency in reality. Our technical team will continue to focus on transfer innovative technologies to manufacturing to consolidate our technology leadership in high efficiency cells mass production.”
The Chinese company announced in June that its Vertex high-efficiency p-type monocrystalline silicon module reached a record aperture module efficacy of 23.03%.
The Dept. of the Interior announced the next steps for a proposed 1,000-megawatt wind project in southern Idaho.
The Bureau of Land Management is seeking public input on the Lava Ridge Wind Energy Project, which would double the state’s wind energy production. The project would feature 400 wind turbines and up to seven new substations.
“Renewable wind projects are a critical component of the Biden-Harris administration’s commitment to confronting climate change, promoting clean air and water for our current and future generations, creating thousands of good-paying union jobs, and jump-starting our country’s transition to a clean energy future,” Interior Secretary Deb Haaland said in a statement. “At the Interior Department, we are doing our part to ensure these projects are done thoughtfully and avoid impacts to surrounding communities. The Department is committed to public input and meaningful Tribal consultation to uphold our trust and treaty responsibilities.”The Bureau of Land Management is seeking public input on the Lava Ridge Wind Energy Project, which would double the state’s wind energy production. The project would feature 400 wind turbines and up to seven new substations. (Courtesy: Magic Valley Energy)
Project plans also include a 500-kilovolt transmission line to interconnect with an existing Idaho Power Midpoint substation. Turbine height would range from 460 to 740 feet tall.
A final decision on whether Magic Valley Energy can move forward with the project is expected next fall.
The BLM is seeking public comments on issues, planning criteria, concerns, potential impacts, alternatives, and mitigation measures that the agency should consider in analyzing the proposed Lava Ridge Wind Project. The BLM will hold public meetings to provide information on the proposed project and to explain the Environmental Impact Statement development process as follows:
Both meetings will be virtual. Please visit BLM’s Lava Ridge Wind Project webpage and click on How To Get Involved for information on registration.
Anheuser-Busch announced plans this week for what will become the largest solar project at a brewery in the U.S. — part of a $64 million investment in the company’s Los Angeles facility.
The solar project will generate 10% of the brewery’s total electricity use and create 16 new jobs at the facility. Anheuser-Busch’s Los Angeles brewery supports more than 100 brands.
“With this investment, we are continuing our support for the local economy and reaffirming our leadership on sustainability and product innovation,” said Eric Gutierrez, senior general manager of the Anheuser-Busch Los Angeles brewery. “Reducing our environmental impact while at the same time adding jobs and expanding our ability to brew some of America’s most beloved brands is a “win-win” for the Los Angeles community.”
Construction on the solar project is currently underway and is expected to be completed later this year, the company said.
The coalition of Southern utilities petitioning to form a new market exchange has responded to a second deficiency letter from the Federal Energy Regulatory Commission (FERC).
Southeast Energy Exchange Market (SEEM) members requested a shortened comment period and prompt decision from FERC, which is expected to take action on the proposal over the next two months.Expected members of the Southeast Energy Exchange Market (SEEM)
Duke Energy, Southern Company, Dominion Energy, and TVA are among the 15 member utilities behind SEEM. They argue that the new bilateral market would “materially benefit” the approximately 5 million households within the proposed coverage region by enhancing opportunities for competition and access to lower-cost energy.
Several advocacy groups have opposed SEEM, however, claiming the proposal would not deliver customers the greatest possible benefit and would not lead to additional renewable energy on the grid.
“The SEEM proposal lacks the ability for independent or small developers or projects to participate, and would not change how utilities plan future resources (i.e. would not change how Southeast utilities develop their Integrated Resource Plans),” the Southern Alliance for Clean Energy wrote last March. “It is possible SEEM could derail true market reform efforts if allowed to move forward in its current form.”
Jeff Dennis, managing director and general counsel for Advanced Energy Economy, joined Renewable Energy World’s John Engel to discuss the latest back-and-forth between SEEM and FERC, and what comes next. Before joining AEE, Dennis spent over a decade at FERC.
“Unfortunately, the utilities that formed SEEM, did it mostly behind closed doors,” Dennis told Renewable Energy World. “While we wouldn’t expect that FERC would necessarily direct the region to take a particular path, we do think that the commission has a role in fostering conversations that we have not been able to have to this point.”
FERC has sent a second "deficiency letter" to the utilities sponsoring SEEM, asking them to answer more questions about the proposal. Response due August 16; FERC will then have 60 additional days to act. Interesting Qs here. 1/ https://t.co/vb6Sh2EFXO https://t.co/KNLCcUR6jW— Jeff Dennis (@EnergyLawJeff) August 6, 2021
Gulf Power, a subsidiary of Florida Power & Light, began installing the first of 600,000 new solar panels planned at two solar farms in Northwest Florida.
The Cotton Creek Solar Energy Center in Escambia County and Blue Springs Solar Energy Center in Jackson County will begin generating clean energy for customers by early 2022, the company said.
“With each solar farm we build, we are driving down costs that will ultimately lead to lower bills for our customers,” said Mike Spoor, Golf Power vice president. “We are also reducing our carbon footprint and providing cleaner air for our region, ensuring we keep Northwest Florida beautiful for generations to come, while also benefitting the local economy with the contribution of hundreds of thousands of additional tax dollars.”Solar panels are stacked up at Blue Springs Solar Energy Center in Jackson County waiting to be installed on the racking. (Courtesy: FPL)
Together, the 500-acre sites will have the capacity — 150 megawatts — to generate enough energy to power 30,000 homes, joining Blue Indigo Solar Energy Center in Gulf Power’s portfolio.
Florida Power & Light operates 42 solar energy centers in the state.
Contributed by Benedikt Sobotka, CEO of Eurasian Resources Group and co-chair of the Global Battery Alliance
The recent report from the UN’s Intergovernmental Panel on Climate Change clearly outlines that climate change is widespread, intensifying, and ‘unequivocally’ caused by human activities. Greenhouse gas emissions are responsible for approximately 1.2C of warming since 1850-1900, with global temperatures expected to reach or exceed 1.5C of warming in the coming decades.
In order to prevent extreme heatwaves, rising sea levels, droughts, and other effects of climate change, urgent action must be taken. Governments, NGOs, and businesses need to work together to support the switch to renewable energy sources and clean energy technologies, such as batteries.
This is the primary aim of the Global Battery Alliance (GBA), a public-private partnership founded in 2017 to establish a responsible battery value chain, in recognition of batteries’ role as a key technology to achieve the Paris Agreement. Since being launched, the GBA has grown to over 70 members, ranging from OEMs to tech and mining companies to civil society organizations, including BP, Microsoft, and Eurasian Resources Group. The GBA is developing solutions such as a ‘Battery Passport’, which will act as a digital representation of a battery, allowing end-users to measure the environmental impact of the batteries in their electric vehicles, mobile phones, and other devices.
Batteries can play a pivotal role in decarbonizing transport through electrification. According to GBA research, by 2030, they can achieve 30% of the required reductions in CO2 emissions in the transport and power sectors, which currently comprise roughly 40% of global GHG emissions. They can also provide 600 million people with access to electricity and create up to 10 million jobs.
However, the expected 19-fold increase in global battery demand over the next decade must occur sustainably. This means accelerating and scaling up efforts towards creating a battery value chain that is characterized by low emissions, safe working conditions, and improved recycling processes. Solutions such as the Battery Passport, which are borne out of cross-sector collaborative efforts, can help align the transport and power industries with the goals of the Paris Agreement by 2030.
About the author:
Benedikt Sobotka is the CEO of Eurasian Resources Group (ERG) and Co-Chair of the Global Battery Alliance (GBA), a multi-stakeholder initiative aimed at achieving a sustainable battery supply chain.
Benedikt was born in Germany and has extensive experience in advisory/management roles in the natural resources and energy sectors. At Boston Consulting Group, he advised leading companies and held various management positions in the Global Natural Resources Practice Area. He founded Minerals Values Service (MVS), among other high-tech startups, which was sold to Platts/Dow Jones in 2015.
Benedikt holds a degree in management, studied in Europe, Russia and China and co-authored “China Champions”, a Financial Times publication.
Vistra finished Phase II expansion of its Moss Landing Energy Storage Facility in California, the company announced Thursday, adding 100 MW/400 MWh to the world’s largest battery facility.
The facility is now storing power and supporting the California grid, when needed, with a total capacity of 400 MW/1,600 MWh.
“This facility provides a solution California desperately needs and this expansion was able to come online at the right time – as the summer heat intensifies and demand for electricity is at its highest,” Vistra CEO Curt Morgan said in a statement. “The state’s laudable immense buildout of intermittent renewable power has both lowered emissions and presented a reliability challenge… Our Moss Landing battery system helps to fill that reliability gap, storing the excess daytime power so it doesn’t go to waste and then releasing it to the grid when it’s needed most.”
The expansion, which began in Sept. 2020, finished ahead of schedule, despite the impact of the COVID-19 pandemic. The lithium-ion battery system is co-located on the site of the existing Moss Landing Power Lant in Monterey County.
Morgan said the site is capable of support expansion up to 1,500 MW/6,000 MWh.
“California leads the country in the transition away from fossil fuels and the Moss Landing Energy Storage Facility stands as a model for how batteries can support intermittent renewables to help create a reliable grid of the future,” Morgan said.
Japan’s PowerX is developing the world’s first vessel to transport electricity generated by offshore wind farms to shore.
The automated “Power Transfer Vessel” aims to support Japan’s goal of increasing offshore wind power generation from 20 megawatts to 10 gigawatts by 2030 and 30-45 GW by 2040. PowerX will also construct a large-scale battery packing facility to produce EV fast-charging, grid, and marine batteries.
“PowerX will design and build an automated Power Transfer Vessel with a massive battery payload that is integrated with the ship’s controls to transport offshore wind power to shore,” the company said in a press release. “An undersea power cable typically requires expensive construction that comes with substantial environmental impacts.”NamePower ARK 100SizeLOA: 100.5 m / Width: 21.9 m / Draft: 5 mDWT2,200tRange100-300km (When running purely on electricity）SpeedCruise: 7 knots, Max: 14 knotsPower Capacity222MWhNavigation and SensorsSonar, Lidar, AIS, Radar, Weather sensors, Autonomous navigation software and sensing equipmentNavigationGNSS-GPS, INS, FOG/ARHS, PPU, Collision avoidance systems
The Power ARK 100, the first model in the power transfer vessel series, is expected to be completed in 2025. The vessel will carry 100 grid batteries with 200MWh of power. The vessel will be able to travel up to 300 km while running only on electricity and can unlock long-distance transmission when powered by electricity and sustainable biodiesel fuels, the company said.
PowerX will mass-produce batteries for the vessels with the construction of a giga-scale assembly facility in Japan. The company expects annual production capacity to reach 1 GWh by 2024 and 5 GWh by 2028.
Contributed by Danyel Desa, energy analyst for Tata Industries
Oil and gas companies have long delivered the fuels that form the bedrock of today’s energy system, but against a backdrop of persistently high global emissions, they are coming under increasing pressure to deliver solutions to climate change. While these may sound like binary choices, most companies will likely try to do both. In practice, the two are closely interlinked, as most of the financial resources for diversified spending, at least initially, will come from traditional investments in oil and gas supply.
While individual company approaches to the energy transition vary, capital expenditure on clean energy is seeing an increasing share of overall investment. Companies – most notably the large European players – are now actively seeking to ramp up their transition to renewables.Source: IEA World Energy Investment 2021
BP says it will increase its annual clean energy investment from USD 500 Mn in 2019 to USD 5 Bn per year by 2030, with an interim goal of USD 3-4 Bn per year by 2025. Total has announced that some USD 2.5 Bn of its planned total investment of USD 12-13 Bn in 2021 will go into renewables and electricity (including gas-fired power). Shell is targeting a 25% share of investment on clean energy capital expenditure by 2025. Eni’s
strategic plan for 2021-24 targets 20% of average yearly capex of EUR 7 Bn to clean energy projects. Additionally, several companies including Saudi Aramco and ADNOC, are exploring possibilities to develop low-carbon hydrogen production, as well as investments in CCUS.
The IEA’s World Energy Investment 2021 report suggests that these commitments are already starting to have an impact. If the current trajectory is maintained for the full year, the share of capital investment going to clean energy investments could rise to more than 4% in 2021 from 1% in 2020.
The Oil and Gas Industry’s Eye for Hydrogen
According to a survey of over 1,000 oil and gas executives by consulting firm DNV GL, the proportion of oil and gas companies intending to invest in the hydrogen economy doubled from 20% to 42% in 2020. Half of senior oil and gas professionals expect hydrogen to be a significant part of the energy mix by 2030, with a fifth of surveyed oil and gas companies already active in the hydrogen market.
For over a century, oil companies have spent tremendous sums of money to deliver fuel to the power and industrial sectors. If hydrogen is supposed to replace petroleum in that equation, no one could reasonably be expected to have better expertise than Big Oil.
As of the end of June 2021, there were 244 large-scale green hydrogen projects planned, according to the Hydrogen Council, an industry group, up more than 50% since the end of January. It estimates tens of billions of dollars have already been earmarked for hydrogen projects.
BP, Shell and Total are all pursuing multimillion-dollar hydrogen projects themselves, often with government support, as they seek to redefine their future role in a world less reliant on fossil fuels.
BP is exploring the use of hydrogen to replace natural gas in industries such as steel, cement, and chemicals, and also as a substitute for diesel in trucks. Overall, BP forecasts hydrogen could account for about 16% of the world’s energy consumption by 2050—if net-zero carbon emissions goals are to be achieved—up from less than 1% today. However, BP doesn’t expect green hydrogen to be a material part of its business until the 2030s, and it has yet to make a final investment decision on any new hydrogen projects.
Shell also is grappling with high costs. This month, the company started up what it said is Europe’s largest green hydrogen plant, to supply its Rhineland refinery in Germany. But that hydrogen is between five and seven times more expensive than the fossil-fuel-based product it predominantly uses.
Shell hopes it can reduce costs by building hydrogen projects in strategic locations alongside customers’ plants, like at ArcelorMittal’s steel mill in the German port of Hamburg, where it can also add hydrogen refueling stations for trucks.
The industry is also getting government support. The European Union paid half the roughly $23 Mn cost of Shell’s Rhineland project and has earmarked funding for hydrogen as part of its pandemic recovery program.
Notably, The EU’s proposed ~$558 bn plan to switch to hydrogen by 2050 is dwarfed in comparison to the typical spending of the oil and gas sector (~US$500 bn) in developing new fields every year. Shifting just a small share of the sector’s spending into hydrogen could be enough to drastically increase the technology’s scale and economics.Source: IEA
Another key expected area of overlap between the current petroleum economy and a hydrogen future is likely to be in midstream infrastructure: pipelines, ships, and storage facilities.
Salt caverns — artificial caves already widely used to store oil and gas, including the U.S. strategic petroleum reserve — are likely to be critical nodes in the hydrogen network. A few are already in use for industrial hydrogen, but many more will be needed. One study conducted in 2020 estimated a capacity to store about 7.3 PWh (1 PWh = 1 billion MWh) of hydrogen in salt caverns near Europe’s coasts, equivalent to nearly two years of the continent’s electricity demand. Depleted oilfields can play a similar role in areas where salt formations aren’t available. No industry understands this geology better than the oil and gas sector.
Engineered infrastructure will also be key. In the Netherlands, a consortium including Shell is planning to put green hydrogen produced by a giant 10 GW offshore wind farm through pipelines serving the declining Groningen gas field, which would otherwise be scrapped. At the port of Rotterdam, another group is hoping to spend about EUR 2 Bn re-powering the local industrial cluster with blue hydrogen instead of conventional fuel.
Critics of Big Oil’s push towards hydrogen
Consultants and oil company executives argue that an interim step to reaching large-scale green hydrogen production is to capture and store carbon generated by making hydrogen from natural gas to reduce emissions—making what is known as blue hydrogen.
Critics contend that the fossil fuel giants have been heavily talking up hydrogen as most of the world’s hydrogen supply is currently produced from natural gas. Blue hydrogen may offer an intermediate step towards green hydrogen. However, it may also end up like coal power with CCS: previously hailed as a promising way of reducing emissions but now seen as a costly dead-end that provided cover for the last burst of coal investments in Asia.
Others argue that oil and gas companies are pouring money into lobbying efforts to direct public investment towards building a hydrogen economy (with considerable success notable in Canada, Germany, and the UK) to delay the transition to electrification. These companies will be key players embedded in the hydrogen value chain if the fuel “works”, and will have slowed the shift to electricity if it does not.
Either way, the scale of the challenge before us is vast. The world will need to produce 80 exajoules (or 660 million tons) of hydrogen a year by 2050, according to the Hydrogen Council. Doing that with electrolyzers, the only viable zero-carbon pathway, would require more electricity than the entire world produced in 2019. That will need about nine times more wind and solar generators than exist worldwide to date, according to BloombergNEF.
Whether Big Oil’s advance into the hydrogen economy will help or hinder the global effort to decarbonize the planet remains to be seen.
About the author:
Danyel Desa is an energy analyst at Tata Industries, the incubation arm of the Tata Group. His work involves two key responsibilities – supporting Flisom AG, a Tata portfolio company and Swiss manufacturer of flexible, thin-film solar modules as well as exploring and appraising investment opportunities in energy storage, hydrogen, electric vehicles, and biofuels spaces.
Prior to his time with the Tata Group, Danyel worked as an equity research analyst at JP Morgan, covering the North American Oil and Gas Services Sector where he wrote Investment Research Reports for the firm’s clients. You can find a link to his LinkedIn profile here.