The Biden administration and leaders in the U.S. Congress unveiled details of the 2,700-page, bipartisan infrastructure package on Sunday that includes $550 billion in new spending. The deal is expected to move quickly – and is likely to change in many ways – before receiving final approval later this week.
So, what’s in the deal for renewable energy? While the legislation won’t, on its own, accomplish President Biden’s climate and clean energy goals, advocates have called the bill a “down payment” on the president’s broader ambitions.
This week, we reached a historic Bipartisan Infrastructure Deal. Secretary Granholm, Secretary Raimondo, and Gina McCarthy hit the road to discuss how our agenda will invest in electric vehicle infrastructure, support good-paying American jobs, and much more. pic.twitter.com/niZHM5DbNt— President Biden (@POTUS) July 31, 2021
The bill includes $7.5 billion to build the first-ever national network of electric vehicle chargers in the United States. The White House wants to deploy EV chargers along highway corridors and within communities, with a particular focus on “rural, disadvantaged, and hard-to-reach” communities.
The bill also includes $2.5 billion to purchase zero-emission school buses.
The legislation expands the U.S. Dept. of Energy’s existing program for research and development of EV battery recycling and second-life applications by $200 million for each FY 22-26.Electric Reliability Council of Texas control room (Courtesy: ERCOT)
Citing last year’s extreme winter storm and power outages in Texas, the White House says the deal includes $73 billion in clean energy transmission investments – upgrades to power infrastructure and the building of thousands of miles of new transmission lines to facilitate the growth of renewable energy assets.
The bill also includes $46 billion in cybersecurity funding to support critical infrastructure needs and weatherization.
The bill includes $3 billion for battery material processing grants and $3 billion for battery manufacturing and recycling grants, according to center-left think tank Third Way, as part of the Biden administration’s goal of bolstering American energy storage manufacturing.
“Along with other provisions in the bill designed to help boost domestic manufacturing, such as the 48C manufacturing tax credit and reforms to DOE’s Loan Programs Office, this $6 billion investment could bring us close to the $10 billion we believe is necessary to bring US battery manufacturing up to scale,” Third Way staff wrote in a policy breakdown.
Industry experts will discuss utility-scale energy storage breakthroughs – including software solutions, battery challenges, safety, financing, and grid balancing attributes – during POWERGEN International Conference Sessions in Dallas, Texas, January 26-28. Find more information about the event, and how to register, here.
While the bipartisan infrastructure package is the Biden administration’s first step to address climate and clean energy goals, advocates are looking ahead to an upcoming $3.5 trillion budget reconciliation package, which only requires support from Democrats.
Abigail Ross Hopper, president and CEO of the Solar Energy Industries Association, commended steps taken in the bipartisan infrastructure package but said more needs to be done to support the growth of solar:
“To achieve the necessary emissions reductions, solar will have to grow four times faster than we are growing today. That cannot happen without a long-term extension of the investment tax credit, with a direct pay option, or a policy equivalent that would drive more solar installations. We look forward to working with members of Congress and the White House to promote clean energy policies that fully tackle the climate challenge and that bring millions of jobs and hundreds of billions of dollars of investment to all American communities.”
August is often seen as the end of something, whether it’s winter in the southern hemisphere or summer in the north. It’s the return to school for some and the last call for a vacation to others.
August, author Sue Monk Kidd wrote, is the “griddle where days just lay there and sizzle.” Hot, hot, hot.
The Clarion Energy series is trying to keep the griddle going this coming month with several key and informative industry webcast presentations. From T&D to on-site power and distributed energy, the webcasts take the temperature of the state of power transmission and generation at its most advanced stages.
Coming up August 17 will be a POWERGRID International session highlighting “When Traditional Overhead Construction Is Not an Option.” This hour-long webcast beginning at 11 a.m. EDT Tuesday, Aug. 17 features Brian Trager, Director of Technology and International, Marmon Utility-Hendrix Aerial Cable Systems.
He will highlight ways to overcome many overhead circuit challenges faced by electric utilities today. These include limited right of way, multiple circuits, substation exits, weather extremes, and vegetation management, among others.
A certificate of attendance is available for continuing education credit. Click here to find out more and register for the free session.
The August POWERGEN+ series also resumes late in the month with a focus on Decentralization and the New Energy Mix. Sessions on FERC Order 2222 regarding the market value of distributed energy, new microgrid projects, power reliability for data centers, trends in renewable energy build-out, behind-the-meter innovations, and clean energy alternatives including solar and wind and beyond.
POWERGEN+ August kicks off at 11:30 EDT Wednesday, Aug. 25 with a sponsored session on “The Why, How, and What of Decentralization and the new Energy Mix.” The 45-minute session will expand on the vast knowledge of several experts from Stanley Consultants, including microgrid practice lead Ernie Leaf, power generation practice lead Mathew Roling and Chris DePodesta, business development manager.
They will offer several case studies associated with trends created through the build-out of renewable energy, the challenges, and uncertainties coming to the industry both carbon-free and thermal. These roadblocks include weather events and cyber ransomware attacks, plus the financial and logistical. The Why, How and What will be well-rounded and cover a lot of ground.
Immediately following Stanley Consultants will be the editorial opener of POWERGEN+ on “The Electric Industry’s Challenges to FERC Order 2222” beginning 12:30 p.m. EDT on Aug. 25. Daniel Brooks, vice president of integrated grid and energy systems at the Electric Power Research Institute, will be joined by leaders from FirstEnergy and system operator experts to discuss the opportunities and challenges of adding distributed energy resource aggregation to the mix.
At 3:30 p.m. Wednesday, Aug. 25, engineering, procurement, and construction giant Black & Veatch will lead a session on “Microgrids and Distributed Energy,” focusing on in-depth looks and lessons learned at some of the major on-site projects the EPC firm has overseen and completed. The speakers will be Rob Wilhite, senior vice president and managing for Global Distributed Energy at Black & Veatch, and Abbey Roy, managing director for new ventures at utility leader Southern Co.
CPower Energy Management starts off the 11:30 a.m. EDT Thursday, Aug. 26 sponsored schedule of POWERGEN+ with a paramount question about the Clean Energy Future: How will you respond? Navigating to the intersection of the four Ds—decarbonization, decentralization, digitization, and distributed energy—will be key for utilities and other businesses in the near and long term.
Mathew Sachs, CPower’s senior vice president of strategy, will provide a framework for how businesses can create value by tapping behind-the-meter innovations while also achieving sustainability goals. He will be joined by fellow panelists Vic Shao, AMPLY Power’s CEO/Co-founder, and Duncan Campbell, vice president and a founding part of Scale Microgrids. CPower and Scale have worked together on several projects, including a hybrid solar-storage-gas gen-set microgrid powering Fifth Season’s indoor farming operation in Pennsylvania.
Meanwhile, some of the largest consumers for both on-site power and distributed energy resources are data centers. Dan Barbersek, director of power generation for Waukesha-Pearce Industries and a POWERGEN contributor, will detail fuel reliability issues and successes for diesel gen-sets both in data center use and for C&I facilities industry-wide. He will be joined by Zach Dean, Rolls Royce Solutions Americas, who will talk about their projects supporting generation at data centers and other mission-critical sites. “Data Centers and 100 Percent Reliability” will run from 12:30-1:15 p.m. EDT Aug. 26.
The POWERGEN+ August finale maintains the sizzle one last time with “The Wide World of Renewable Energy” beginning 3:30 p.m. EDT on Aug. 26. Jay Dauenhauer, host of the Energy Cast podcast and also a POWERGEN regular contributor, will moderate a panel looking at the entire scope of renewable energy resources, from renewable natural gas, biomass, solar, wind, and more. Representatives from divisions of Dominion and Duke Energy also will be participating.
All of these POWERGEN+ and POWERGRID webcasts are free and available on-demand beyond the live sessions.
The Indiana subsidiary of AES Corp. will acquire and oversee the building of a 250-MW solar and 180-MWh energy storage facility in that state.
AES Indiana is acquiring the Petersburg Solar Project in Pike County, Ind., from NextEra Energy Resources LLC, a division of Florida-based NextEra Energy. NextEra will continue to develop and construct the project. It will be connected to AES Indiana’s existing 2.1-GW coal-fired Petersburg Generating Station.
“The Petersburg Solar Project is a win-win solution that adds new technologies to our generation fleet, while also keeping economic benefits right here in Indiana,” said Kristina Lund, AES Indiana President and CEO. “We are excited to evolve our long-time partnership with Pike County, a community that has helped support and power the needs of Indianapolis for 50 years.”
AES hopes to have the project completed and operational by May 2024. It still needs the approval of Indiana state utility regulators.
The NextEra Energy Resources website describes the Petersburg Solar Project as totaling close to $300 million worth of investment and employing 300 construction jobs.
By Shelley Robbins, Clean Energy Group
As states and the federal government take steps to transition away from fossil fuel generation, it is important to pay attention to recent clean energy developments in states where energy legislation has historically been less proactive, and the traditional integrated utility monopoly model has held influence over the policymaking process. In those states, where clean energy is now gaining a stronger foothold, valuable lessons can be found. Actions by these states to change the direction of energy policy are a powerful confirmation that clean energy is a viable, cost-effective alternative to fossil fuels.
A perfect example is South Carolina, where the legislature passed the landmark Energy Freedom Act in 2019; and where the South Carolina Public Service Commission rejected Dominion Energy’s integrated resource plan in 2020, and then rejected Duke Energy’s integrated resource plan in 2021— both for failure to adequately consider and model available clean energy options. Now, Duke Energy, one of the state’s vertically integrated investor-owned utilities, has worked with stakeholders to create a program that addresses winter peaking with a combination of solar, time-of-use rates, smart thermostats, and soon additional technologies that will likely include battery storage.
For South Carolina, solar PV paired battery storage (solar+storage) can be more than just a tool to reduce demand and offset fossil-fuel consumption. These technologies can be used to create community resilience hubs throughout the state, providing services during hurricanes and other extreme weather events. Solar+storage can keep critical devices powered, protecting vulnerable populations during outages that may imperil their lives by leaving them too hot, too cold, or without needed medical devices that require electricity. It can also be a tool to reduce the state’s high energy cost burdens, leading to a host of positive benefits for lower-income households.
South Carolina now stands among the more proactive Southern states in clean energy policy. But it wasn’t always that way. There were numerous regulatory and political challenges that had to be overcome to make way for meaningful change. The story of how South Carolina met these challenges offers important insights for other states.
The Evolution of South Carolina Energy Policy
It is important to note that backlash resulting from a failed nuclear project had a big part to play in South Carolina’s shift to advance clean energy. Back in 2007, South Carolina’s investor-owned utilities, Duke Energy and South Carolina Electric and Gas (SCE&G), had considerable influence at the Statehouse and the Public Service Commission (PSC). That year, a piece of legislation called the Base Load Review Act (BLRA) passed fairly quietly, which allowed PSC-regulated utilities to collect revenue for major construction long before the projects were put into service —projects such as two new reactors proposed for the SCE&G/Santee Cooper VC Summer nuclear plant, approved in 2008. Construction on the nuclear reactors – the first in the U.S. in 30 years – began in 2013, but the project was abandoned in 2017 when estimated costs soared by billions.
The VC Summer failure ultimately produced the political will, via public pressure, to scrutinize the existing regulatory paradigm and then rip it apart. Backlash from VC Summer debacle also led the Legislature to replace all seven utility commissioners in 2017, and the new commissioners were chosen with a more rigorous selection process than those of previous years. In 2018, the BLRA was repealed, a Utility Consumer Advocate was created, and reforms were introduced at the PSC. In 2019, the Legislature adopted the Energy Freedom Act.
A New Clean Energy Paradigm
The Energy Freedom Act (EFA) laid the groundwork for South Carolina’s clean energy transition. It included language codifying a customers’ right to be able to reduce their electricity consumption, added “energy storage” to the definition of a customer generator, granted customers the right to their energy data and allowed data sharing with third-party vendors, and addressed the inclusion of capacity value, locational value, and ancillary service value of storage to avoided cost calculations. The legislation also enabled the PSC to require all-source solicitations for capacity over 75 megawatts and required the utilities to establish Solar Choice Net Metering tariffs (the next iteration of the net metering program). Finally, EFA established new requirements for utility integrated resource plans (IRPs) and directed the PSC to approve, deny or modify those plans within the framework of a litigated proceeding, allowing for intervenors to challenge utility assumptions and methodologies.
Beyond the enabling elements in the EFA, the two most significant developments for the expansion of solar+storage in South Carolina were the approval of a solar choice program and the rejection of Duke Energy’s IRP.
Duke Energy’s Solar Choice and Smart$aver Solar as Energy Efficiency programs open the door for more residential and small-scale commercial solar projects by creating a program that pairs time-of-use (TOU) rates with smart thermostats and rooftop solar. The programs enable customers to receive rebates as well as monthly demand-response incentives for lower both summer peak and winter peak demand if they enroll in the TOU program and allow Duke to manage the energy use during periodic peak demand events on the grid. This is an innovative way to incentivize renewable energy that recognizes its value to the grid. But even more exciting is that Duke Energy committed to expanding the programs to include “other peak load reduction technologies,” such as battery storage and heat pump water heaters, by June of 2022. Duke also committed to initiating a stakeholder process to explore a similar program tailored to low-income customers.
In the Commission’s order rejecting Duke’s IRP in June 2021, the PSC noted that Duke under-estimated the value of solar and storage, over-estimated the cost of battery storage, and under-estimated future gas prices and risks. The Commission ordered Duke to remodel the IRP using the National Renewable Energy Laboratory’s Annual Technology Baseline – Low figures for battery storage. Duke must also remodel its natural gas price assumptions. And for future IRPs, the PSC ordered Duke to correct their capital cost assumptions for battery storage compared to combustion turbines, to accurately model the capacity value for solar paired with storage on the grid (with stakeholder input), and to evaluate more robust options and emerging technology within the energy efficiency (EE) and demand-side management (DSM) programs, focusing on approaches that do not rely on behavioral changes. Since the goal of the EE/DSM programs is to reduce consumption of fossil fuels and reduce the need for expensive capital investments, it stands to reason that customer-sited solar+storage should play a role and be evaluated for cost-effectiveness as an emerging tool within the program, as has been done in several New England states.
With each of these policy changes and PSC decisions, South Carolina has put in place the elements it needs to expand the adoption of solar+storage. Notably, the state has done this without the benefit of belonging to an independent system operator (ISO) or regional transmission organization (RTO). These wholesale energy market managing constructs have helped demonstrate the value of solar+storage in other regions of the country; South Carolina’s success shows that individual states can advance distributed solar+storage markets without the support of regional energy market managers.
Lessons Learned in South Carolina: Opportunistic Teamwork
The shift from a policy that favored the monopoly utilities, shareholders, and protection of profits to a policy that increasingly values distributed renewable energy and market competition did not happen organically. It was the product of crisis, intense protracted debate, and compelling advocacy by an impressively diverse group of players, all mission-aligned with the goal of opening the state to distributed renewable energy. This lesson can be of value to other states where the shift to clean energy has been sluggish. But perhaps South Carolina’s greatest achievement was the ability of the various stakeholders — from big business to environmental advocacy groups — to work together in historic fashion to raise a solar-policy phoenix out of VC Summer’s ashes.
Now it is time to put these hard-fought policy pieces to work. As South Carolina adopts more solar+storage, it will have the potential to increase the state’s resilience to extreme weather and utility outages, protect vulnerable citizens during times of crisis, clean up its grid in a cost-effective manner, reduce energy burdens, and improve air quality as polluting fossil-fuel power plants are retired. South Carolina isn’t the only state that can do this; lessons learned there can be adopted and applied elsewhere, spurring new clean energy transformations in historically challenging regions.
Originally published at ILSR.org
Electricity customers are lining up to generate their own clean, affordable solar energy, but to get it to them, solar developers must navigate the impediments of a congested and outdated electricity grid.
For this episode of the Local Energy Rules podcast, host John Farrell speaks with Yochi Zakai, an attorney with Shute, Mahaly, and Weinberger representing Interstate Renewable Energy Council (IREC). The two discuss hosting capacity analysis and how publicly-shared grid information can help solar developers, electric customers, and others make informed decisions.
Listen to the full episode and explore more resources below — including a transcript and summary of the conversation.
Electric distribution grids were built as top-down avenues for delivering electricity from large, centralized power plants. Now, as distributed generation and energy storage become more popular, utilities are having to accommodate the two-way flow of electricity. To do so, the utility often needs to upgrade the distribution system. This is especially true in areas where there is a lot of distributed energy development.The grid was built for this one way flow of electricity. But as more customers decide to install generation in their homes, the way that the distribution grid operates is also going to change.
Solar developers looking to connect their new generation source to the grid may trigger the need for a system upgrade. In most cases, whoever triggers a grid upgrade must pay the upgrade costs — which can be severe. Larger solar gardens are more likely to trigger upgrades. If a developer is surprised by these costs, and building their solar garden is no longer feasible, they may be forced to drop their plans entirely. Hosting capacity analysis can provide key grid information proactively for individuals hoping to plug in.Hosting Capacity Analysis
In a hosting capacity analysis, utilities compile information about the electric grid and publish it online for the use of developers and other stakeholders. The resulting map has pop-ups with data on various localized grid conditions: how much generating capacity that section of the grid can still handle, the voltage of the line, and the existing generation on that part of the grid.
This information, which Zakai calls “geeky grid data,” helps customers and solar developers make decisions.The studies produce a wealth of information that developers can use to cite and design the systems so they don’t trigger upgrades. And in some cases they can even make the grid more reliable.
Utilities in seven states are required to publish hosting capacity maps. Some utilities even publish this information voluntarily. Zakai says that generally, hosting capacity analysis is most common in states with robust distributed energy development, including Hawaii, Massachusetts, and New York.Image from Xcel Energy’s Hosting Capacity Map Some Truth to California Exceptionalism
California’s hosting capacity analysis process, called integration capacity analysis, provides more useful information than the hosting capacity maps published in other states. This is thanks, in part, to a petition from Zakai and the Interstate Renewable Energy Council (IREC). IREC asked the state of California to consider all kinds of interconnecting loads, including electric vehicle chargers, electric heat, and solar generating power, when implementing its integration capacity analysis. In January 2021, the California commission filed its petition to make changes to the analysis and its resulting map.
In California, grid users also uniquely share the cost of grid upgrades, rather than the typical ‘cost-causer pays’ model used in other states.Automating and Simplifying the Interconnection Process
It is not possible to automate all new grid interconnections, says Zakai. Still, hosting capacity analysis could simplify many of the steps within this process. California is the first state in the country to try using hosting capacity analysis to reduce the complexity of the interconnection process.Hosting capacity analysis can be used to automate and increase the precision of some of the most problematic technical review processes that the utilities use when they evaluate new grid connections. Last fall, California became the first state in the country to make a final decision to use the hosting capacity analysis to automate some of these processes.
Thanks to new rules adopted by the California Public Utilities Commission, solar developers can use the public hosting capacity maps to design and site projects with more certainty. As developers make more informed proposals, utilities will not waste resources reviewing projects that will never get built.
Read ILSR’s comments to the Minnesota Public Utilities Commission detailing how Hosting Capacity Analysis Could Simplify Grid Interconnection for Distributed Energy Resources.Episode Notes
See these resources for more behind the story:
For concrete examples of how cities can take action toward gaining more control over their clean energy future, explore ILSR’s Community Power Toolkit.
Explore local and state policies and programs that help advance clean energy goals across the country, using ILSR’s interactive Community Power Map.
This is episode 135 of Local Energy Rules, an ILSR podcast with Energy Democracy Director John Farrell, which shares powerful stories of successful local renewable energy and exposes the policy and practical barriers to its expansion.
Local Energy Rules is Produced by ILSR’s John Farrell and Maria McCoy. Audio engineering for this episode is by Drew Birschbach.
NextEra Energy – owner of Florida Power & Light, Gulf Power, and NextEra Energy Resources – added 1.8 gigawatts of renewables and storage to its backlog in the second quarter of 2021, the company reported last week.
FPL made significant progress in Q2 on its plan to install 30 million solar panels by 2030, adding 373 megawatts of incremental solar. The investor-owned utility has completed 40% of its ’30-by-30’ plan and expects to have installed 15 million panels by early next year.Read More: FPL reaches major solar installation milestone
NextEra Energy Resources added 285 MW of new wind and wind repowering, 1,450 MW of solar, and 105 MW of battery storage to its backlog of signed contracts since reporting first-quarter financial results in April, the company said.
“For the second quarter, NextEra Energy Resources continued to capitalize on the terrific market opportunity for low-cost renewables and storage and added approximately 1,840 megawatts to its backlog since the release of our first-quarter financial results in April,” Jim Robo, chairman and chief executive officer of NextEra Energy, said in a statement.
Industry experts will discuss utility-scale energy storage breakthroughs – including software solutions, battery challenges, safety, financing, and grid balancing attributes – during POWERGEN International Conference Sessions in Dallas, Texas, January 26-28. Find more information about the event, and how to register, here.
FPL demolished its last coal-fired plant in Florida in June. The company plans to replace the plant with emissions-free solar energy facilities as part of its focus on “identifying smart capital investments to lower costs, improve reliability and provide clean energy solutions.”
The Biden administration – through the Bureau of Ocean Energy Management (BOEM) – is advancing the process to bring offshore wind energy development to California and North Carolina.
BOEM published a request for information from the public for commercial offshore wind in two new areas off central California – identified as the Morro Bay Call Area East and West Extensions. The extensions are adjacent to the Morro Bay Call Area with a combined total area of 399 square miles.
The agency also formally designated the Humboldt Wind Energy Area (WEA) offshore northern California – nearly 207 square miles – and will soon launch an environmental review.
“Today’s announcement builds on an earlier agreement between the White House, the Department of the Interior, the Department of Defense, and the state of California to advance areas for offshore wind off the northern and central coasts of California,” BOEM Director Amanda Lefton said in a statement.
BOEM posted the call for information on the Morro Bay Area East and West Extensions on July 29, initiating a 45-day public comment period that runs until Sept. 13.
JC Sandberg, chief advocacy officer for the American Clean Power Association, said the BOEM action in California is important to reach the Biden administration’s goal of deploying 30 GW of offshore wind energy by 2030 and the state’s goal of 100% carbon-free energy by 2045.
“Leasing the Morro Bay call area could make California a global leader in floating wind projects that will generate investment opportunities across the state, boost manufacturing and create good-paying jobs while helping meet important climate and emissions targets,” Sandberg said.The NCC in Portland, Oregon, is a state-of-the-art 24×7 generation system control room that acts as the nerve center for our entire U.S. fleet. (Courtesy: Avangrid Renewables)
Last week, BOEM granted approval to prepare an environmental impact study for wind energy development in Kitty Hawk North, 50,000 acres located 27 miles off the coast of North Carolina within the Kitty Hawk WEA.
The entire 122,405-acre Kitty Hawk WEA is expected to support up to 2,500 MW (John, you could also write this as 2.5 GW) of wind generation capacity when fully developed, according to developer Avangrid Renewables. Kitty Hawk North will contribute to offshore wind energy development goals in both North Carolina and Virginia.
“Kitty Hawk North is a game-changer for the mid-Atlantic,” Bill White, head of offshore wind for Avangrid Renewables, said in a statement. “Not only can this project help Virginia and North Carolina meet their vital clean energy goals with cost-effective power, but Kitty Hawk will help a new industry take flight in this region and create thousands of quality jobs.”
Investments in early-development offshore wind projects – like Morro Bay, Humboldt, and Kitty Hawk – now top $2.9 billion, according to a report by the American Clean Power Association.
Calpine and GE Renewable Energy this month announced completion of a 80-MWh standalone battery storage system in southern California.
The Santa Ana Storage Project, which uses GE’s Reservoir energy storage technology, entered into commercial operation. The 20-MW, 80-MWh capacity is supported by a 20-year Resource Adequacy Power Purchase Agreement.
Calpine, which traditionally has been a natural gas power plant and geothermal developer, considers the Santa Ana project as a major step forward in its plans to grow the company’s energy storage footprint.
“It is critical that consumers have affordable, reliable electricity as we work to integrate more renewable energy sources into the U.S. power supply,” said Alex Makler, Senior Vice President of Calpine’s West Region. “Calpine already operates the world’s largest geothermal facility in California, and this cutting-edge battery storage project represents another major investment in meeting the clean energy demands of an increasingly electrified world. We are proud to work with GE and the community of Santa Ana to showcase the very latest in energy storage solutions.”
California is accelerating its energy storage capacity as it needs grid support for a dramatic growth in intermittent renewable energy such as solar. The state’s near-term target is getting 60 percent of its electric power from renewables by 2030.
“The energy storage system provides targeted local capacity to enhance grid reliability during peak periods,” added Mike Bowman, Renewable Hybrids Chief Technology Officer for GE Renewable Energy. “And, as fast-acting stabilization devices, the battery energy storage systems can charge and discharge rapidly to regulate frequency and contribute to grid stability, helping to balance and facilitate the ever-growing penetration of variable renewable energy.
By Michael Castellarin and Michael Andrisani
It is a time of change and growth for the power and energy sector. One of the most important and challenging questions facing the world is how it can transition towards a more sustainable future with respect to energy generation and consumption. To make substantial progress, massive investments into the power and energy sector will be required. We are already seeing some of the world’s biggest companies and deepest-pocketed investors pile capital into the industry, in what has been coined by some as an era of “green finance.”
Companies and investors alike are seeking to get behind, and capitalize on, the decarbonization tailwinds impacting the industry. These tailwinds are likely to continue given at least 125 countries have committed to net-zero carbon emissions by 2050. The Biden administration is focused on decarbonization, having declared a goal of cutting U.S. greenhouse gas emissions in half by 2030.
Investments in renewable energy need to significantly increase if society is to meet these stated targets and sufficiently decarbonize. Wood Mackenzie estimates that at least $50 trillion in investment will be needed to reduce fossil-fuel and other greenhouse gas emissions by 2050 if we are to meet the goals set out in the Paris climate accord.
There are clear examples of reputable investors investing – directly as an asset owner — in the power and energy sector to fully capitalize on the decarbonization trend taking hold. For instance, Canada Pension Plan Investment Board, which kick-started its renewables effort in 2017, said it formed a new company, Renewable Power Capital, to boost its European investments in solar, onshore wind, and battery storage.Green finance means more than just projects
While investments in renewable energy projects, battery storage technologies, or in improving and modernizing the electricity grid are a focus for certain investors, it is not where we play at Clairvest Group. We believe that given the growth and change discussed above, the demand for certain vital services to the power and energy industry is growing significantly. For example, in our portfolio, we have partnered with a global leader in providing a robust set of operations and maintenance services to solar power project owners. For similar reasons we are now attracted to consulting and engineering firms which have a strong practice focused on serving the changing needs of the power and energy market.
We believe that consulting and engineering firms focused on the global energy transition will generate above average growth rates and industry leading profit margins. For example, firms that provide services catered to renewable energy or distributed energy should benefit from the significant growth in these projects and the necessary planning and design work that go along with them if we are to meet the net zero goals set by 2050. The breadth of the impact on the consulting and engineering space will be pervasive. Its impact will reach firms with expertise ranging from permitting and compliance to those focusing on design and construction.
We are not alone in our interest in this space as large, diversified consulting and engineering players are keen to capitalize on the decarbonization trend and continue to be acquisitive in pursuit of it. A notable example is WSP’s acquisition of Golder earlier this year which was intended to bolster the firm’s strategy and the “transition to a more sustainable and low-carbon future.”
Other consulting and engineering companies, such as Montrose and Black & Veatch, have cited decarbonization as a major growth driver and focus area for their firms. Given the growth opportunities that lie ahead, private equity investors can provide the necessary growth capital to appropriately capitalize on trends, for example, through M&A or investments in a firm’s talent and capabilities, including significant investments in technology.
In addition to growth capital requirements, we are also witnessing succession issues in the consulting and engineering sector which make the industry an excellent candidate for private equity investment and recapitalization. There is an increasing cadre of baby boomer partners or employee-owners looking to retire. The younger and rising stars in many consulting and engineering firms often do not have the financial capacity to buy out the selling partners. As a result, a private equity firm, particularly one that focuses on minority / non-control investing, can be an excellent equity partner to assist with such an ownership transition while also providing capital for growth.
In light of the potential for significant growth as well as the need for capital for orderly succession, we are confident that there will continue to be a keen interest in investing in well-positioned consulting and engineering firms. Further, acquisition activity will continue to be pervasive as firms build size, scale, and deeper capabilities to serve the power and energy sector as it transitions to a more renewables-based future.About the Authors
Michael Castellarin, with Clairvest since 2002, handles industry research and investment origination, structuring and execution with a focus on waste management, environmental services, facility services and industrial services. Michael is currently on the Board of three solid waste management investments: Winters Bros. Waste Systems, DTG Recycling and Arrowhead Environmental Partners. Since 2006, Michael has led Clairvest’s investments in seven waste management platform companies.
Prior to joining Clairvest, he worked as a management consultant at Monitor Company and as a marketing manager for the National Hockey League Players’ Association. Michael earned his M.B.A. from Northwestern University’s Kellogg School of Management and a B.Comm. with honours from Queen’s University at Kingston.
Michael Andrisani joined Clairvest in 2020 and participates in all areas of the investment process. Prior to joining Clairvest, Michael worked on a variety of M&A transactions in investment banking at Lazard (New York) and as an attorney at Cravath, Swaine & Moore (New York). Michael earned a JD from Osgoode Hall Law School and a MBA and Bachelor of Business Administration from the Schulich School of Business.
By Ian Palmer, PhD
The world can address greenhouse gases (GHG) emissions in different ways. The direct way is by reducing fossil fuel production, the main source at 73% of global GHG.
Europe is following this approach, perhaps because its companies don’t have the enormous success of a shale revolution to maintain.
In Europe, companies and countries are diversifying into renewables as illustrated by the following:
It’s clear the European continent is teeming with examples of integrating renewables into their future. But in the US, companies have adopted different approaches. One indirect way for reducing GHG is by companies greening their own operations – using wind or solar electricity to pump frac jobs, for instance. But this is only a very minor contribution to reducing the 73%.
A less direct way to reduce GHG is by cleaning up methane leaks from wells, pipelines, and processing facilities. To repeal rules installed last September, the U.S. Senate passed in June a new bill to remove methane leaks as a cause of air pollution in oil and gas operations and allow EPA to enact stricter methane regulations. However, methane emissions are only 10% of all GHG emissions in the US, and less than half are due to methane leaks. So if the cleanup gets it down to zero, this is a drop of only 5% of the total 73% fossil fuel contribution.
Another method is carbon capture and storage (CCS). ExxonMobil is storing 9 million metric tons of CO2 each year, equal to 11 million car exhausts each year. The company plans to invest $3 billion for 20 new CCS facilities and even envisages a $100 billion consortium of oil and gas entities and government to capture then bury GHG under the Gulf of Mexico. “Bury” in CCS parlance means to inject CO2 deep underground where it’s contained by non-leaking rock layers, and eventually merges chemically with the rock.
However, CCS is a non-direct approach because it doesn’t stop the emission of GHG from fossil fuels. It just captures and buries the resulting GHG. But CCS will be important for the net-zero concept because it’s an escape hatch to get rid of any leftover fossil GHG.
While the EU are clearly leading by diversifying into renewables, companies in the U.S. seem to be avoiding the direct approach of cutting oil and gas production.
The appetite of legacy U.S. energy companies has largely stayed focused on what has always been their main meal: oil and gas production — including the shale revolution.
But in the US, the demand for oil and gas will likely fall if the Biden administration achieves its goals of greening electricity and changing to electric vehicles. If supply follows demand, oil and gas could fall by 30% from now to 2035-2040.
Any of dozens of oil and gas companies thriving in the Delaware basin of southeast New Mexico could stop drilling new wells and instead invest in wind/solar systems right there in the windy Chihuahuan desert. There is money to do it — the basin made roughly $24 billion/year at the wellhead in 2019, and makes even more now in 2021. The January 2021 federal moratorium on new oil and gas well leases on federal lands provides an opportunity and motivation to do this down there.About the Author
A petroleum engineer and consultant, Ian Palmer, PhD has worked at Los Alamos, The Department of Energy, BP, and Higgs-Palmer Technologies. He is a contributor at Forbes.com and the author of The Shale Controversy.
In 2020, renewables generated a record 834 billion kWh of electricity, or about 21% of all the electricity generated in the U.S., according to the Energy Information Administration, coming in second to natural gas at 1,617 billion kWh.
Renewable energy sources include wind, hydroelectric, solar, biomass and geothermal energy. Only natural gas produced more electricity than renewables in the U.S. in 2020. Renewables surpassed nuclear (790 billion kWh) and coal (774 billion kWh) generation for the first time on record. This outcome in 2020 was due mostly to significantly less coal use in U.S. electricity generation and steadily increased use of wind and solar.
In 2020, U.S. electricity generation from coal in all sectors declined 20% from 2019, while renewables increased 9%. Wind grew 14% in 2020 from 2019. Utility-scale solar generation (from projects greater than 1 MW) increased 26%, and small-scale solar (such as grid-connected rooftop solar panels) increased 19%. The specific contribution from hydropower was not listed.
Coal-fired electricity generation in the U.S. peaked at 2,016 billion kWh in 2007, and much of that capacity has since been replaced by or converted to natural gas-fired generation. Coal was the largest source of electricity in the U.S. until 2016, and 2020 was the first year that more electricity was generated by renewables and nuclear power than by coal (according to EIA’s data series that dates back to 1949). Nuclear electric power declined 2% from 2019 to 2020 because several nuclear power plants retired and other nuclear plants experienced slightly more maintenance-related outages.
EIA said it expects coal-fired electricity generation to increase in the U.S. during 2021 as natural gas prices continue to rise and as coal becomes more economically competitive. Based on forecasts in its Short-Term Energy Outlook (STEO), EIA expects coal-fired electricity generation in all sectors in 2021 to increase 18% from 2020 levels before falling 2% in 2022.
EIA expects U.S. renewable generation across all sectors to increase 7% in 2021 and 10% in 2022. As a result, EIA forecasts that coal will be the second-most prevalent electricity source in 2021 and renewables will be the second-most prevalent source in 2022. EIA said it expects nuclear electric power to decline 2% in 2021 and 3% in 2022 as operators retire several generators.
By Jim Madej, CEO, Franklin Energy
If the clean energy industry has shown us anything the past few years, it’s that it’s booming and ready to power our economy long into the future. The price declines in solar, wind, and battery storage have shown that renewables are available, economical, and growing.
However, what’s been even more evident within the clean energy industry recently is the unstoppable trend toward the electrification of transportation. The growth in electric vehicles is raising eyebrows — spurred by vehicle innovation, favorable policy changes, and advancements in battery technology. The benefits to the economy and environment are obvious; what’s less obvious will be the changes to the way our utilities operate and grow their business.EV Growth and Questions from Utilities
According to Precedence Research, the global electric vehicle market is expected to register a compound annual growth rate of 40.7% from 2020 to 2027. Innovative technologies that make EV’s more attractive and attainable are coming to market faster. Trusted American car manufactures are quickly moving from an all-gas-powered line up to one that includes a variety of EV options. The best example is the remarkable reception to Ford’s new F-150 Lightning pick-up truck, which shows that Original Equipment Manufacturers (OEMs), have found a new EV market segment and are quickly making their way into the American mainstream.
But the explosive growth of EVs has utilities asking some questions. General concerns are centered around charging infrastructure, how the industry will support market growth, and how utilities will manage the inevitable spike in demand. How will EV’s change the way we manage the grid? Are EV’s an opportunity for additional revenue, or should we be shaping customer charging behavior even before an EV purchase is made to curb peak demand?
Here are four requirements to put EVs on our streets and in our driveways sooner rather than later.Support New EV Policies
Luckily, there have been favorable policy and utility program developments across the country. A recent analysis by the ACEEE State Transportation Electrification Scorecard shows:
This is a great start and shows the nation is on the right path. However, there is more to be done if the future includes an EV in every American driveway, and federal, state, municipal and corporate EV fleets.
All utilities must recognize electrification of transportation for the vast market opportunity and benefit that it is. Americans currently consume roughly 8 million barrels of oil a day. In the coming years and decades, that demand for oil is going to diminish as demand for EV charging grows exponentially.Engage Customers with Attractive Residential Charging Access
Some energy analysts and experts believe that most electric vehicle owners will charge their vehicles at home overnight. For most utilities this will present a significant revenue opportunity. A traditionally low-demand time of day will see increasing customers plug into the grid. For most utilities, this presents a significant revenue opportunity.
Many utilities are already partnering with car dealerships to set up new EV customers with at-home chargers and opportunities to opt into charging management programs. Utilities will increasingly have a unique opportunity to be a part of the EV buying customer experience, continuing to build and expand programs that provide demand response capabilities and economically managed charging solutions that don’t strain the grid.
The earlier utilities can be a part of this process, the more likely they’ll be able to build the grid programs and infrastructure that can provide value to customers and future revenue opportunities for themselves. The notion “If you build it, they will come” has never rung so true.
The earlier utilities can be a part of this process, the more likely they’ll be able to build the grid programs and infrastructure that can provide value to customers and future revenue opportunities for themselves. The notion “If you build it, they will come” has never rung so true.
It’s also increasingly likely that utilities will have the opportunity to build programs that use EVs to meet peak demand events. Beyond opting customers into demand-response programs to avoid charging during peak events, utilities can build programs that empower customers to provide power back to the grid during peak events. EVs are truly a new Swiss Army knife for utilities.Unlock the Fleet Charging Challenge
Many utilities and state agencies are still new to the process of permitting and building public charging stations. This will change in the not-so-distant future. It is important to streamline these processes now to enable the inevitable demand for charging infrastructure in the years ahead.
It is critical that utilities be proactive in developing processes and working with local government to ensure smooth processes and steps for electric charging construction. In some municipalities charging infrastructure must go through long bureaucratic processes that can make building charging infrastructure a +12-month pursuit. That is not going to cut it for the amount of charging we’ll soon need to support customer demand.
Identifying opportunities for fleet electrification will also be a critical component to the EV transition. Traditional fleet warehouses are not high electricity demand centers. But when a fleet of gas vehicles shift to EVs, they will be, and it is the utility that will need to service that customer segment with infrastructure upgrades. For utilities not proactively doing this, they should consider using the current moment as an opportunity to pilot, then grow programs.Make EV Charging Equitable
To ensure the promise of EV transportation and its requisite charging is realized equitably, we also need to electrify fleets of city buses, school buses, and establish charging in multi-family units.
Although many analysts believe home charging will be a significant chunk of EV charging, many people don’t own homes. As the EV revolution gains more speed, this segment can’t be overlooked. It’s essential that as this industry grows, it benefits people of all walks of life.
Let’s ensure all Americans have positive EV experiences and benefit from transportation electrification. If we do, our environment, economy and communities will be better off for it.About the Author
Jim Madej is the CEO of Franklin Energy and AM Conservation Group. With more than 1,200 employees and 60 utility and government partners across the US and Canada, the company’s turnkey energy efficiency and productivity solutions include building decarbonization programs, EV infrastructure, energy optimization for telecommunications, environmentally controlled agriculture, residential customers and much more.
Jim’s mission as a leader is to help catalyze our national transition to a clean energy economy in which all energy-related businesses profit from the end of climate change and the growth of our planet.
Before joining Franklin Energy, Jim was CEO at VEIC, Chief Customer Officer at National Grid USA, and the Director of National and Government Sales and Customer Services at Hess Corporation. He has also held numerous leadership roles at the General Electric Company, where he began his professional career.
Most people today know home solar can help you save on energy costs while reducing your carbon footprint. Plus, when you combine solar panels with a battery you don’t have to suffer through a power outage whether it’s caused by a storm, overwhelmed power grid or cyberattack. However, there are still homeowners with unshaded roofs or plenty of unshaded land for a ground mount to power their homes with sunshine who won’t even look into going solar. Sometimes it is because they perceive solar would be too expensive. (It isn’t expensive. You can literally pay $0 for panels and installation with a solar lease or PPA to lock in a lower rate than your utility.)
Once they realize how inexpensive going solar really is (you really cannot get any less expensive than no-cost panels and installation) they still might worry about what their neighbors will think of the panels on their property or that their HOA will prevent them from going solar. The fact is that HOAs in most states cannot stop you from installing solar panels due to solar access laws. However this hesitation could also be because they are unaware that panels have evolved to be more aesthetically pleasing.
In many cases with the newer monocrystalline silicon panels (shown on the homes in the picture on this page) it is actually difficult to tell you have panels on your roof at all. This is because monocrystalline silicon panels are uniform, are black in color and have a sleeker look. (Older, polycrystalline silicon panels can still have high efficiency ratings but can seem less attractive to some people because their color looks blue since they reflect the sky. This is the result of the multiple crystals that make the product.)
But what if you understand solar is affordable, you have the perfect home for solar, you can see that solar panels’ appearance has evolved, but still think they are ugly? There may be no way to change your perception of what is pretty to look at, but if you still have the desire to do your part to protect our environment, and wouldn’t mind ending up with lower or zero electricity costs, why not consider how beautiful solar panels really are compared to the alternatives?Three Things Uglier Than Solar Panels
1) POLLUTION: Air, land and water pollution from fossil fuels is hideous. If you are not solar-powered most of the energy your home uses comes from coal-fired power plants and/or dirty oil. Pollution destroys animals, plants and healthy ecosystems. It also kills humans from carcinogens and poison in water and food supplies. Even people who do not believe climate change has anything to do with human activity dislike pollution. No one wants their children or grandchildren to get sick from poison in the air and water. One of the best things about the energy generated by solar panels is that it is emission free.
2) RISING UTILITY COSTS: What’s uglier than seeing your electricity bill growing bigger every month? Rate hikes are a never-ending fact of life now unless your home is solar-powered. Even if you are in the one percent of top income earners who doesn’t have to worry about watching your budget, saving thousands of dollars on energy costs and/or earning profits from your solar investment can’t be a bad thing. Most wealthy people like to save money and generate a strong return on their investments. Solar panels can do both.
3) WAR: Fighting over oil rights and relying on foreign governments who are not our friends for our energy supply is terrible and really, really ugly. America has the means to become more energy independent without drilling, mining and plundering our public lands. The sun above belongs to all of us. Millions of American homeowners know this and proudly run their homes on sunshine. This is why a new solar system is now installed in America every 90 seconds.Homes in sunny neighborhoods without solar will become obsolete
A lesser known fact is that your whole neighborhood is rewarded when you go solar. By running your home on sunshine you benefit everyone around you because the excess energy you produce goes back into the energy grid, reducing the the chances of a power shortage due to strain on the grid. It also helps to decrease their energy costs, not just yours.
Solar adoption across the USA is increasing every day. It won’t be long before almost all sunny neighborhoods are solar-powered and homes without solar panels in those neighborhoods will look outdated and passé. Some experts predict HOAs will eventually begin to require everyone goes solar. Until that day, however, it would be wise to consider that there are much uglier things to worry about then the way a clean energy system looks.
Inspire, a company that purchases renewable energy credits (RECS) and retires them on behalf of its customers, announced it has signed an agreement to become a wholly owned subsidiary of Shell New Energies US LLC. As part of Shell, Inspire intends to rapidly scale its offering of access to sustainable energy to U.S. households.
According to its website, Inspire is licensed to do business in several deregulated states and DC. It recruits customers and sells them clean energy for a fixed price.
“We look forward to joining Shell’s talented team to achieve our energy transition goals together,” said Patrick Maloney, Founder & CEO of Inspire. “We share the belief that renewable energy should be accessible to everyone and Shell’s resources, reach and ownership of many aspects of the energy value chain will help us scale and advance our mission.”
“Our goal is to become a major provider of renewable and low-carbon energy, and this acquisition moves us a step closer to achieving that,” said Elisabeth Brinton, Executive Vice President of Renewables & Energy Solutions at Shell. “This deal instantly expands our business-to-consumer power offerings in key regions in the U.S., and we are well-positioned to build on Inspire’s advanced digital capabilities to allow more households to benefit from renewable and low-carbon energy.”
Inspire will operate under its existing brand within Shell’s Renewables & Energy Solutions integrated power business. The Inspire leadership team and existing employee base will remain in place.
The deal is expected to be completed by Q4 of 2021, subject to regulatory approvals and the satisfaction of closing conditions.
By Maren Schmidt, FIMER
As someone who has worked in the global solar PV sector for many years, recent reports outlining the huge growth in renewable energies and specifically solar PV, are very encouraging.
For example, despite the disruption of the past 12-18 months, in its recent Renewable Energy Market Update, the International Energy Agency (IEA) said that, in 2020, annual renewable capacity additions increased 45 percent to almost 280 GW – the highest year-on-year increase since 1999.
It is also forecasting that ‘exceptionally high-capacity additions will become the “new normal” in 2021 and 2022, with renewables accounting for 90 percent of new power capacity expansion globally’. It says that solar PV development will continue to ‘break records’, with annual additions reaching 162 GW by 2022 – almost 50 percent higher than the pre-pandemic level of 2019.
In particular, the share of utility-scale applications is forecast to increase from over 55 percent in 2020 to almost 70 percent in 2022.
This rapid expansion over 2020 and forecast growth for 2021-22 is fantastic news for the sector, and particularly the utility-scale market.
So, what are the key drivers supporting this robust growth outlook?Increasing cost-effectiveness
Solar PV is fast becoming the most cost-effective form of power generation and can be combined with energy storage to create a reliable source of power. This is as a direct result of the dramatic fall in solar panel prices, solar inverters and more cost-effective mounting and tracker systems, and increased efficiency of solar technology.
In addition, PPAs are proving increasingly popular and are making utility-scale projects more economically viable. For example, while the United States remains the dominant corporate PPA market, activity in Europe almost tripled in 2020, with Spain also identified as a hotspot, with a record number of PPAs signed.
While the outlook is less certain in some markets, such as Latin America, especially due to the temporary impact of Covid-19, and changes in political support in the utility-scale sector in countries such Mexico, deployments are still expected to increase.Government Policies and Regulations
Many global governments have committed to ambitious carbon reduction targets, which is driving solar growth. For example, under the Paris Agreement, the U.S. and Canada committed to cut carbon emissions by approximately 30% between 2025 and 2030; Europe is aiming for a reduction of at least 40% below 1990 levels by 2030; and India has committed to cutting emissions intensity by 33%-35% below 2005 levels and generating 40% of its electricity from non-fossil fuel sources by 2030. The UK also became the first G7 country to legislate to hit net zero emissions by 2050.ESG and the Corporate Decarbonization Agenda
The transition to renewables is now high on the agenda for developers, investors, utilities, and policymakers, and is being driven by demand from the corporate market that sees procuring energy from a renewable source as a key part of their decarbonization plans. Where installing an on-site solar PV array isn’t possible, buying from a renewable source that is generated from a utility-scale application is growing in popularity.Innovation to meet demand
With these factors driving growth, particularly for utility-scale solar PV applications, how can technologies meet this demand?
So, how do technology providers ensure that their solutions are fit for purpose in this new era for utility-scale solar?
For FIMER, a collaborative approach among solar project developers, IPP firms, EPCs, technical advisors and component manufacturers is crucial. As well as adapting and developing our technologies to meet new demands, being involved at the very beginning of the project helps to ensure that the right solution is specified that optimizes performance, increases production and keeps losses to a minimum, aiming to both increase IRR and reduce LCOE.
For example, we recently announced the launch of two new platforms for the utility market – a high-power MPPT inverter and a modular conversion platform – that can serve both centralized and decentralized plant layouts.
In conclusion, it is an exciting time for utility-scale solar projects. Projected strong growth, favourable political and regulatory environments, and increasing corporate demand for renewable energy, mean that innovative utility-scale solar projects are being deployed to fully maximize the power of the sun.
This is pushing demand for technologies that are fit for future growth – a challenge we are more than relishing rising to.About the Author:
Maren Schmidt De Angelis is managing director of FIMER’s Utility business line.
By Danyel Desa
The deployment of renewables has reached the point where balancing the electric grid requires shifting the supply of intermittent energy sources and demand on a MW-to-GW scale. Continued growth in the renewables market depends heavily on the widespread implementation of effective energy storage technologies.
The widespread use of grid storage can save utilities and their customers large amounts of money by evening out demand across time. Storage allows power plants’ baseline generating capacity to be substantially lower than that required to accommodate demand peaks.
Thus, only when augmented by affordable grid storage can renewable technologies such as solar and wind successfully compete with fossil fuel-based energy production. Looking back at data on investments in energy storage, we found a few trends which (in conjunction with the fallout from COVID-19) are setting the stage for energy storage’s near-term and long-term growth.Assessing COVID-19’s Impact on Battery Storage Deployments
Per the IEA’s World Energy Investment 2021 report, energy storage was already losing momentum at the beginning of the COVID‑19 crisis. For the first time in nearly a decade, annual installations of energy storage systems fell year-over-year in 2019. The IEA cited wavering policy support in key markets and uncertainties around battery safety as headwinds to growth, with grid-scale installations falling by 20%.
The 2020 crisis was expected to compound these effects, owing to battery manufacturers’ particularly complex and cross-border supply chains from cells, to modules, to packs and installers.
However, the IEA reported that despite the pandemic, investment in battery storage surged by almost 40% year-over-year in 2020, to USD 5.5 billion. Spending on grid-scale batteries rose by more than 60%, driven by the push for investments in renewables.
The costs of battery storage systems reportedly continued to reduce substantially, by an average of 20%. This also helped drive the impressive resilience of grid-scale batteries, especially in the United States and China – which installed over 1 GW – followed by Korea and Europe.
Given the strong momentum of the sector and the big pipeline of upcoming projects, the IEA predicts that this trend is set to continue in 2021. Research firm IHS Markit has predicted that over 10 GW of new energy storage will be deployed during 2021, more than double the estimated 4.5 GW of deployments seen in 2020.Source: IEA, IHS Markit Recent trends in Early-Stage Funding for Battery Storage Companies
The IEA, in its World Energy Investment 2021 report claimed that although clean energy startups continued to attract high levels of investment through the COVID-19 crisis, the market lost momentum in the first half of 2020. Early-stage Venture Capital (VC) investments decreased marginally in 2020 relative to 2019.
Nonetheless, investments in clean energy startups recovered in the second half of 2020 and continued strongly into the first quarter of 2021, for which data points indicate a record quarter for early-stage energy VC funding.
According to a recently published report by Mercom Capital, VC funding (including private equity and corporate venture capital) raised by battery storage companies in Q1 2021 came to USD 994 million compared to $351 million in Q4 2020. Year-over-year funding for Q1 2021 was more than five times greater than Q1 2020’s USD 164 million.Source: Mercom Capital
While these sums appear far lower than those spent on energy R&D and deployments by governments and companies, this private capital plays a vital role. It enables the market creation and scale-up of technologies that have a clear near-term value proposition, especially those that do not require high levels of upfront development and capital.
Moreover, the rebound in early-stage investments demonstrates a larger trend – investors are increasingly convinced that energy transitions are happening, with the proliferation of renewable energy companies going public through special-purpose acquisition companies (SPACs) demonstrating a growing appetite for start-ups.
The IEA suggests that this shift towards increased investor appetite for providing risk capital to early-stage energy technology companies is a significant development. However, it cautions that the impact of this shift depends on the pace at which the supply of high-potential, scalable ideas from research can rise, especially from publicly funded labs and projects.Near-term Catalysts for Energy Storage’s Growth
As energy storage becomes truly grid-scale, deployments around the globe are getting supersized. As previously highlighted, in the U.S., Florida Power & Light (FPL) recently received its first battery unit installations for its massive 400 MW/900 MWh project. Additionally, Connecticut Governor Lamont recently signed a new law that will require the state to deploy 1 GW of energy storage by 2030 with milestone requirements every three years. Finally, the Southeast Asian Clean Energy Facility (SEACEF) recently announced an investment in a 500 MWp floating solar and storage project in Vietnam, which is to include up to 200 MWh of battery storage capacity.
This indicates that grid-scale storage installations are on the magnitude of other infrastructure projects and will require deep-pocketed funding beyond early-stage investors. The U.S. Department of Energy (DOE), in its recently published Energy Storage Grand Challenge: Energy Storage Market Report, projected that global grid-storage installations would grow from about 10 GWh in 2019 to almost 160 GWh in 2030.
Per Mercom Capital, total corporate funding (including VC, Debt, and Public Market Financing) in Battery Energy Storage came to USD 4.7 billion in Q1 2021, compared to USD 3.1 billion in Q4 2020 and USD 244 million in Q1 2020. This is yet another sign that corporations and investors are increasingly including clean energy (especially battery storage) exposure in their portfolios. We think that institutional investors and capital markets will play a significant role in driving energy storage development going forward.
Even with the pandemic seemingly poised to linger on into 2021 or beyond, the fundamental imperatives impacting the world’s approach to energy production this century have not changed. The global necessity to decarbonize the electric grid will likely continue to drive technological advances as well as Corporate and VC funding initiatives in the grid storage space for the foreseeable future.About the Author
Danyel Desa is an Energy Analyst at Tata Industries, the incubation arm of the Indian multinational conglomerate Tata Group. His work involves assisting Tata Industries’ portfolio companies in achieving their objectives, as well as exploring and appraising investment opportunities in the renewable energy domain, spanning energy storage, hydrogen and fuel cells, electric vehicles and biofuels.
Prior to his time with the Tata Group, he 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. He is passionate about the energy transition, having researched and worked on both the Oil and Gas and Renewables spaces.
He received his education at the Indian Institute of Technology, Bombay with a Dual Degree (Bachelor’s and Master’s in Technology) in Electrical Engineering. He is passionate about writing and an avid researcher, continually educating himself on emerging trends and technologies in the renewables domain.
On July 23, the government of Zambia celebrated commissioning of the first unit at the 750-MW Kafue Gorge Lower hydropower station.
Dr. Edgar Chagwa Lungu, President of the Republic of Zambia, gave an address on the occasion, which was attended by many dignitaries, including representatives of project owner Zambia Electricity Supply Corp. (ZESCO) and contractor Sinohydro Corporation.
During his address, Lungu discussed the need to invest in infrastructure in the country and implement projects that will lead to more inclusive economic growth. “It is no secret that my government continues to invest in roads, clinics and hospitals, airports and power infrastructure such as the one we are witnessing today,” he said. “We … firmly believe that infrastructure development is critical to opening up development for the entire country. The economic gains that will accrue from these investments will no doubt benefit our country and outlive not just the current hurdles but will benefit all of us who are present here.”
Lungu said Zambia has seen increased demand for electricity to power mining, agriculture, tourism, industries, education, healthcare services and homes. He acknowledged that investment in power generation from 1977 to 2011 did not grow proportionately with increased demand.
“Today’s commissioning of the first unit of the flagship Kafue Gorge Lower hydro-electric power project is testimony to our commitment and resilience in ensuring that the country’s electricity needs are secured and meet our needs today and the future,” he said.
Lungu said that in less than seven years his administration introduced an additional 1,350 MW of power generation to the national grid. Arriving at a total installed capacity of 3,250 MW.
The Kafue Gorge Lower station is located on the Kafue River in the Chikankata District, Southern Province. It includes a 140-meter-tall concrete-faced rockfill or roller-compacted-concrete dam and a power plant with five 150-MW turbine-generator units.
by Kari Lydersen, Energy News Network
A conservative-led alliance of farming, construction, and clean energy groups is pushing new legislation in Wisconsin meant to create competition and accelerate the development of subscriber-backed community solar projects.
Backers of the bill (LRB 1902) say it would facilitate a significant increase in the state’s renewable generation, help customers access clean energy and save money on bills, create solar construction jobs, and provide a revenue stream for struggling farmers.
The bill is opposed by utilities, who argue that it violates the state’s regulated energy market and would force customers who aren’t solar subscribers to pick up more costs for electric grid upkeep.
State Sen. Duey Stroebel and Rep. Timothy Ramthun, both Republicans, announced the bill on July 13, though it has not yet been formally introduced. The Wisconsin Conservative Energy Forum is a leading proponent. Such conservative support is considered essential to passing bills in Wisconsin, where the legislature is Republican-dominated and powerful business interests tend to be conservative.
“The development of a competitive market — that’s a strong argument and should be a persuasive argument for conservatives who emphasize the role of competition, of private development in achieving lower cost and better outcomes,” said Wisconsin Conservative Energy Forum Executive Director Scott Coenen. “That shouldn’t be any different in solar, particularly community solar.”
Other supporters include the Land & Liberty Coalition — which includes farmers — and the growers cooperative Organic Valley, along with the Associated Builders and Contractors of Wisconsin, Advocate Aurora Health, Renew Wisconsin, and the Wisconsin Grocers Association.‘A bipartisan issue’
Under the bill, privately owned non-utility community solar facilities of up to 5 megawatts could be built through June 2031. The same owner could not build multiple facilities within a mile of each other. No one entity could buy up more than 40% of a project’s subscriptions, and at least 60% of the project’s subscriptions would need to be in amounts of 40 kilowatts or less.
Twenty-two states, according to the Coalition for Community Solar Access, have passed similar enabling legislation that allows private developers to build community solar — often on land leased from farmers — and recruit subscribers who get a credit for the solar power on their utility bill. Regulators such as Wisconsin’s Public Service Commission decide the terms of the arrangement, including how much customers are credited for the community solar installation’s power.
Matt Hargarten, campaigns director for the Coalition for Community Solar Access, said “the time is exactly right for community solar in Wisconsin.” He noted that states with robust community solar scenes are concentrated largely in the Northeast and West Coast, but Midwestern states are increasingly embracing the concept. Minnesota and Illinois have successful community solar programs, and legislation is also being considered in Michigan and Pennsylvania.
“We think this is a bipartisan issue, there’s something in it for everybody,” Hargarten said. “On the [political] right you have customer choice, competition, economic development. Other factors have motivated left-leaning states to adopt it sooner — climate change, energy equity. But now we’re seeing a second wave of right-leaning states adopting it. The inevitability of changing the grid is upon us. Republicans have to ask what the new grid looks like, in a way that aligns with conservative values.”Legality and equity
In a state like Wisconsin with a regulated energy market, the ability to generate power is typically reserved for utilities and electric cooperatives. Utilities have argued that the bill violates regulatory provisions for this reason.
“We Energies, WPS and other Wisconsin utilities have invested billions and billions of dollars in order to avoid the results of extreme weather events such as those that recently took place in Texas,” said Brendan Conway, spokesperson for We Energies parent company WEC. “That investment, electric reliability and predictable pricing will be threatened by a change in law that allows third parties to directly serve electric utility customers. The proposed legislation would undermine the regulatory system that has served Wisconsin and its electricity customers well for over 100 years.”
Opponents of the bill also include the Wisconsin Electric Cooperative Association, Municipal Electric Utilities, and other business and labor organizations.
Coenen said that passing the bill is “fraught with challenges in a vertically integrated market like ours in Wisconsin, in a highly monopolized, highly regulated market,” but given that the Public Service Commission would set the terms, he and other backers say the program is in keeping with a regulated environment.
“We think of it as fitting nicely into a regulated framework,” said Heather Allen, executive director of Renew Wisconsin. “Minnesota has one of the most successful community solar programs, and that’s a regulated state.”
In a May memo sent to legislators, the Wisconsin Utilities Association argued against the proposal, saying that customers already have access to solar including through programs where utility-owned solar is built on customers’ property (often called “rent-a-roof”) and provisions for customers to choose clean energy on their bill. Often programs where customers buy clean energy involve an additional charge. For example, We Energies’ “Energy for Tomorrow” program charges an average customer about $13 a month extra to get all their energy from renewable sources, and $6 to get half their energy from renewables.
“Programs such as WEC’s Solar Now and Nature Wise, Alliant’s Second Nature, MG&E’s Shared Solar and Xcel’s Renewable Connect programs are a success and should be expanded, not undermined by the third-party ownership’s or unregulated Community Solar’s false promises,” said the memo.
Utilities have invoked an argument they’ve also used to oppose the proliferation of residential rooftop solar: that it shifts the costs of grid maintenance to customers who aren’t receiving solar energy.
“Attempts to erode our regulated system are under consideration by some who are not bound by the regulatory compact and have no obligation to serve customers or control their rates,” said the utilities association memo. “They can cherry pick those with the highest incomes and exploit the use of the grid our utilities are required to maintain, at the expense of everyone else who pays their bills.”
Such arguments have been widely debunked, since distributed solar actually provides benefits to the grid that can lower everyone’s costs. Meanwhile community solar is actually a way that people with lower incomes — including those who don’t own homes or can’t afford the capital investment in rooftop solar — can participate in the solar economy.
Allen said that while some utilities have offered community solar to their customers, others including We Energies in the Milwaukee area have no community solar installations.
“It’s very likely if this legislation is passed, community solar would accelerate much more rapidly in Wisconsin,” she said. “The [community solar] projects utilities have created have been popular, but there are utilities that have not offered any community solar to their customers. That leaves Wisconsinites without the opportunity to subscribe to community solar. We want everyone to have access, and we want a statewide framework for that, not the patchwork we have now.”
She added, “We have a lot of agricultural communities and farmers looking for opportunities that are not at risk with fluctuating commodity markets and extreme weather events. This offers opportunity for the lease of land, for a drought resistant ‘cash crop’ that allows them to keep the family farm in the family.”
The Wisconsin Manufacturers & Commerce organization sent a memo to lawmakers voicing opposition to the bill, noting the purported cost-shifting argument that utilities have invoked. And the labor unions representing operating engineers, electrical workers and carpenters have opposed it, fearing that the community solar installations would take the place of larger utility-scale installations that would be built with union labor.
Tom Content, executive director of the Citizens Utility Board of Wisconsin, described community solar-enabling legislation as an important way to help more people access solar.
“It’s not an either-or proposition when it comes to solar. It shouldn’t be only one kind of solar that gets built,” he said. “There is value no matter who builds it. It helps meet power demand on hot days whether it’s a utility-scale or community solar project. The two worlds don’t have to be in collision, they can coexist.”Unused subscriptions?
The bill specifies that state subsidies could not be offered for community solar projects or their subscribers, a difference from neighboring Illinois where the 2017 Future Energy Jobs Act created renewable energy credits for community solar that resulted in a boom for such projects. The subsidies ran out more quickly than expected, and proposed legislation in Illinois would renew the program.
Coenen said business leaders’ research has shown there is ample interest among private developers in building community solar, despite the lack of renewable energy credits.
He and Adams said the bill as currently written does not address what would happen if a project is not fully subscribed, and the Public Service Commission would determine this issue once a law is passed.
“In every single community solar market today, unsubscribed energy is compensated at the lower wholesale rate — the price to produce electrons — giving ratepayers a deal and disincentivizing developers from having unsubscribed energy,” Coenen said. “This is why virtually all community solar facilities around the country are fully subscribed.”
Conway framed the situation differently, saying: “If the developer does not attract enough subscribers they have no worries — all of the remaining costs will be paid for by our non-participating customers.” He pointed to a section of the bill (paragraph F) that refers to higher retail rates being paid by the utility for “accumulated” credits; it is unclear from the text if this refers to unsubscribed solar generation.
Hargarten said that while some states have ultimately put provisions on their community solar programs meaning that little or no community solar is actually built, in more states community solar has flourished despite initial utility opposition.
“Generally utilities like their business models — they are very comfortable with the status quo,” he said. “They will generally unilaterally oppose anything that forces them to do something different. In almost any state utilities will oppose this legislation until it’s obvious it’s going to pass, and then they come to the table and help negotiate. Once programs pass, utilities are really important stakeholders — it is a partnership.”
The Electric Highway Coalition (EHC), a group of electric utilities working together to install fast-charging EV stations along major interstate highways, has doubled its members.
Membership in the EHC has now grown to include AVANGRID, Consolidated Edison, DTE Energy, Eversource Energy, Exelon, FirstEnergy Corp., ITC Holdings Corp., and National Grid. Formed in March 2021, EHC began its membership with American Electric Power, Dominion Energy, Duke Energy, Entergy Corporation, Southern Co., and the Tennessee Valley Authority.
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Together, the 14 members — representing 29 states and the District of Columbia and serving more than 60 million customers — are committed to growing EV charging solutions along major transportation corridors within their service territories and working with other members to enable convenient charging options and seamless travel routes for EV drivers.
In addition to expanding membership, the EHC has further defined its goals and is pursuing shared objectives. The members have agreed to work together to ensure efficient and effective fast charging deployment plans that enable long distance EV travel, avoid duplication among coalition utilities, and complement existing corridor fast charging sites. Ideally, EHC members are pursuing sites that are easily accessible for drivers located less than 100 miles apart.
The EHC is also committed to providing a positive charging experience for drivers, including having at least two charging stations with universal vehicle compatibility, and additional features where feasible, such as real-time status reporting for drivers and convenient payment collection.
DC fast charging stations are typically capable of getting drivers back on the road in 20-30 minutes. Member companies are working closely with stakeholders in their service territories to determine the best approaches to support effective EV charging buildout. Each member company will determine its own specific pricing models and select its own charging equipment providers.Member update: TVA
As a founding member of the EHC, TVA is working to ensure that EV drivers have access to a seamless network of charging stations connecting major highway systems across its seven-state service area and beyond. TVA is helping drive innovation and collaborating through partnerships within the Tennessee Valley to increase the use of electric vehicles. The shared goal is to move from the approximately 18,000 EVs in the region today to more than 200,000 EVs on Tennessee Valley roads by 2028.
TVA recently launched In Charge: Life with an Electric Vehicle, a five-episode video series aimed at dispelling myths and exploring the benefits of electric transportation. Take a road trip throughout the Tennessee Valley with a new video released every two weeks through September, to see how electric vehicles can fit any lifestyle. View the premiere episode here.
“Electric vehicles benefit the environment by reducing carbon, but the economic impact is also substantial,” said Drew Frye, TVA manager of Commercial Energy Solutions. “In the Tennessee Valley, you can buy a locally made EV, power it using electricity from TVA and your local power company, and do so knowing that you’re supporting local jobs.”Member update: AEP
AEP has committed to replacing its 2,300 cars and light-duty trucks with EV models by 2030. Additional medium- and heavy-duty vehicles will transition to hybrid or electric alternatives as models become available. The charging network announced today also will enable AEP employees to use EVs to travel throughout the company’s 11-state service territory. AEP also is working with select customers across its service territory to help them understand the benefits of electrifying their own vehicle fleets or business processes.
Across its service territory, AEP is working with regulators to create programs that benefit all customers and support EV adoption, such as off-peak charging programs, incentives for charging station installations, energy efficiency rebates, and consultative services to encourage electrification.
In 2018, AEP Ohio launched a $10 million program to deploy 375 charging stations in partnership with local governments, workplaces and multi-family dwellings to increase publicly available charging sites and demonstrate the benefit of public-private partnerships as part of the Smart Columbus initiative. The program included a requirement to locate 10% of the charging stations in low-income areas, a benchmark that was exceeded.
In 2020, Indiana Michigan Power began offering its IM Plugged In program to address residential, multi-family dwelling, fleet and workplace charging, as well as corridor fast charging. The program offers customers rebate programs that reduce EV charging infrastructure costs and EV-specific off-peak rates.
Appalachian Power offers a residential off-peak charging program for Virginia customers. Customers also receive credits for EV charging that takes place during off-peak periods, such as overnight.
Additionally, residential customers of Public Service Company of Oklahoma and Southwestern Electric Power Company in Louisiana and Texas are eligible for energy efficiency rebates on qualified EV chargers.
The EHC welcomes interested utilities to join as it seeks to extend the network’s reach. Additionally, it supports, and looks forward to working with other regional utility transportation electrification initiatives.
DISTRIBUTECH International’s live and in-person event is set to take place in Dallas, Texas, January 26-28, 2022. Registration will open soon. Click here to view registration packages and sign up to be notified when registration is open. We hope to see you in Texas!
In the recently announced ANOPR on transmission planning, cost allocation, and generator interconnection reform process, FERC is seeking comments on whether it should require transmission providers to consider grid enhancing technologies in generator interconnection studies to interconnect renewable projects. FERC is also seeking comments from transmission providers who have already implemented and have experience with these technologies.
FERC is looking for comments on transmission planning, cost allocation, and generator interconnection processes since this could be one of the most important transmission planning orders from FERC since Order 2003. Renewable developers should note the focus of this FERC on speeding up renewable project interconnections because most regional grid operators have solar projects in the queue.
As a presenter at the recent PJM interconnection policy workshop put it, FERC Chair Glick and Commissioner Clements indicated their specific concerns with the current state of affairs in generator interconnections and transmission planning. Both FERC Commissioners are concerned that transmission planning is not integrated with generator interconnection planning, and planning focuses on meeting near-term needs.
Without stating it specifically, FERC with this ANOPR has laid out the problem of lack of transmission build-out to interconnect renewable projects. Even if Commissioner Danly dissents in the final order issuance, FERC Commissioners would have a majority vote.
Based on the NOPR on transmission line ratings, we know what the responses to FERC ANOPR on GETs topic would be
FERC issued a Notice of Proposed Rulemaking (NOPR) on “Managing Transmission Line Ratings” on November 19, 2020. FERC gave all interested parties 60 days to respond. Key stakeholder comments filed in that NOPR proceeding include,
1. Previous FERC Chairman Norman Bay wrote in EDF Renewables comments that transmission congestion could limit a RE project output, and hence EDF supports transparent transmission line ratings.
2. When new generator interconnection projects are delayed by more than a year, American Clean Power Association (ACP, previously American Wind Energy Association AWEA) and SEIA support implementing DLRs.
3. Clean Energy Parties (NRDC and others), ACP and SEIA, and the WATT Coalition support an option for interconnection customers to fund a DLR study if the TO does not study DLR as an alternative for network upgrades.
4. MISO Independent Market Monitor (IMM) also supports DLRs.
FERC defined Dynamic Line Ratings DLR as: “a transmission line rating that: (1) applies to a period of not greater than one hour; (2) reflects up-to-date forecasts of inputs such as (but not limited to) ambient air temperature, wind, solar irradiance intensity, transmission line tension, or transmission line sag; and (3) is calculated at least each hour, if not more frequently.”
The real issue is the Transmission Owner (TO) incentives, and the solution lies with FERC
In the FERC NOPR on transmission line ratings, in which FERC has not issued an order, three PJM TOs (AEP, Dominion, and Exelon) do not want FERC to mandate DLRs. MISO TOs in a joint filing and PJM say the same thing.
If FERC mandates DLRs, PJM TOs want PJM to have the flexibility to implement DLRs, and that PJM should consult their TOs.
In the ANOPR, FERC is also seeking comments on the TO incentives question in sections such as, Identifying Geographic Zones That Have Potential for High Amounts of Renewable Resource Development to Meet Increased Demand, Incentivizing Regional Transmission Facilities, Participant Funding and Eliminate Participant Funding for Interconnection-Related Network Upgrades. Hence FERC is looking to incentivize TOs to adopt GETs as alternatives to network upgrades.
FERC could adopt a criterion to implement DLRs
In their comments to FERC on transmission line rating NOPR, ACP and SEIA propose a criterion for implementing DLRs based on the following conditions:
• “Congestion costs have surpassed $1 Million per year;
• New generation interconnection has been delayed by more than one year due to factors that include transmission line capacity, or
• The generation has been curtailed by more than 20 percent on average for one year due to factors that include thermal constraints on line capacity.”
This criterion can be helpful for renewable developers to support in their comments to FERC on the ANOPR because it directly answers the question FERC is asking “whether FERC should require transmission providers to consider grid enhancing technologies in generator interconnection studies to interconnect renewable projects?”. The answer is yes. FERC should require DLRs under the above-stated conditions.
Once published in the federal register, transmission providers have 75 days to respond. Reply comments are due 105 days after the federal register publication date. Assuming August 2 as the publication date in the federal register, all interested parties can reply by October 15. Stakeholders can reply to other’s comments by November 15.
FERC may collect stakeholder comments via technical conferences held in different parts of the country. It is equally likely that FERC would issue a NOPR and then a final FERC Order. Meanwhile, RE developers should look at network upgrade costs from RTO generator interconnection studies and explore the possibility of GETs like solutions.