Renewable Energy News

Syndicate content Renewable Energy World
Your premier source for the latest news in Green Energy.
Updated: 5 hours 27 min ago

800-MW Vineyard Wind offshore wind farm to be first commercial-scale project in the US

Tue, 05/11/2021 - 20:53

Vineyard Wind, a joint venture between Avangrid Renewables and Copenhagen Infrastructure Partners (CIP), today passed the final major step in the federal review process, which means it will likely become the first commercial scale offshore wind farm in the United States.  

This final major federal approval from the Bureau of Ocean Energy Management (BOEM) will enable the developers to begin construction later this year. Avangrid said the approval represents the beginning of an energy transition in New England where clean power will be created by harnessing the region’s strong coastal winds.

“Today’s Record of Decision is not about the start of a single project, but the launch of a new industry,” said Vineyard Wind CEO Lars T. Pedersen.

“Receiving this final major federal approval means the jobs, economic benefits and clean energy revolution associated with the Vineyard Wind 1 project can finally come to fruition.  It’s been a long road to get to this point,” he added.

Since 2017, the Vineyard Wind 1 project has been through an unprecedented and exhaustive public review process that generated more than 30,000 public comments, more than 90% of which supported the project. The Construction and Operations Plan (COP) was reviewed by more than two dozen federal, state, and local agencies over the course of more than three and a half years. 

The project design includes the GE Haliade-X, with a capacity of 13 megawatts (MW). The larger turbine capacity has allowed the project to reduce the total number of turbines from 108 to 62 while still delivering a total capacity of 800 MW to Massachusetts customers. The turbine layout, which features consistent spacing of one nautical mile between turbines, was endorsed by the United States Coast Guard for transit, fishing and navigational safety.

“We are very excited and proud to be part of the birth of an incredibly important new industry,” said AVANGRID CEO Dennis V. Arriola. “We appreciate the thorough review by BOEM as well as the considerable input from stakeholders. The broad engagement from many parties throughout this process has improved the project and positioned both Vineyard Wind 1 and the broader offshore wind industry for long-term success,” he added.

In response to comments and direct engagement with neighboring communities, environmental organizations and advocates, fisheries organizations, and governmental and tribal entities, the project has incorporated significant mitigation measures, including:

Protections for the North Atlantic Right Whale (NARW):

  • Commitment to invest millions of dollars to develop and deploy innovative technologies and undertake scientific research to further safeguard marine mammals. 
  • Institute comprehensive monitoring protocols to ensure that construction doesn’t take place when NARWs are near the lease area. 
  • Deploy technology to dampen construction noise during installation in order to protect the NARW and all marine species.

Fisheries Investment and Mitigation Funding:

  • Agreements with the states of Massachusetts and Rhode Island to provide millions to compensate fishermen for potential loss of revenue and gear and to enhance their ability to fish in and around the lease area 
  • Commitment to continue funding pre- and post-construction survey studies with both the University of Massachusetts Dartmouth School for Marine Science and Technology (SMAST) and the Massachusetts Lobstermen’s Association (MLA) to measure what impact, if any, the windfarm is having on the marine environment.   

Cultural and Historical Protections:

  • Install an Aircraft Detection Lighting System (ALDS) to ensure that nighttime lights will only operate a few hours a year when aircrafts are present
  • Paint turbines to reduce visual impacts to historical properties 
  • Allocate funds to conduct ethnographic studies for local Native American Tribes that will serve as the basis for submissions to the National Register of Historic Places to allow for greater recognition of tribal heritage sites. 

“Massachusetts should be proud that this decision launches the nation’s first commercial-scale offshore wind project here on the Commonwealth’s shores,” said Governor Charlie Baker. 

“This groundbreaking project will produce affordable, renewable energy, create jobs and prove Massachusetts developed a successful model for developing offshore wind energy.  We appreciate the federal government’s partnership to grant this approval and look forward to working with Vineyard Wind to create thousands of jobs and set the Commonwealth on a path to achieve Net Zero emissions.”

Prior to construction, Vineyard Wind must submit a facility design report and a fabrication and installation report. These engineering and technical reports provide specific details for how the facility will be fabricated and installed in accordance with the approved Construction and Operations Plan.

Wanted – creative transmission owners willing to try alternatives to network upgrades!

Tue, 05/11/2021 - 17:20

Renewable energy project developers spend a lot of money in the generator interconnection queue for the queue position. This capital outlay is because the developer expects the transmission grid operator to study their request and approve it according to the tariff filed at FERC. With so many interconnection queue requests at most RTO’s that are under FERC jurisdiction, as an industry, we are unable to connect the dots and see that it’s the lack of engineers and the lack of creative thought processes to implement short-term solutions that is keeping us from being able to mitigate the queue backlog issue.

For example, take a case where both a transmission owner and an interconnection customer agree on the number of network upgrades needed to interconnect a renewable project request. The interconnection customer is a renewable project developer in this case. This situation is straightforward if there are tens of interconnection requests in any transmission owner footprint. But in today’s current reality, transmission owners are dealing with hundreds of renewable project developer requests. So, the transmission owner needs to be creative in designing a transmission system to accommodate the renewable project developer requests sooner than later without impacting the grid’s reliability.

Yes, the reliability of the transmission grid is important for both RE developer and transmission owner.

Suppose we start with the common assumption that the developer and the transmission owner want reliability to be the primary goal of the transmission grid. In that case, it is in the best interests of both the interconnection customer and the transmission owner to look at grid enhancing technologies to accommodate the interconnection requests while waiting for a detailed transmission study. Since interconnection studies include system impact and feasibility studies, and more intensive facility studies, better served is the industry by including grid enhancing technologies as alternatives to network upgrades in the thermal analysis portion of interconnection studies.

System stability studies that are part of the facility studies, which are the last stage in any interconnection study, would still need to be performed. And those studies might show a need for the network upgrade, which is usually a new transmission line or a new transformer or a switching station or a substation. However, if we include SmartWires or LineVision types of grid enhancing transmission technologies (GETs), we can squeeze more capacity out of our existing transmission systems while waiting to build a new transmission system.

The headline is, “Advanced Transmission Technologies Shown to Double Regional Renewable Energy Capacity.”

There is evidence that GETs provide value to both interconnection customers and TOs. A report that Working for Advanced Transmission Technologies (WATT) Coalition produced with Brattle Group shows “dynamic line ratings, advanced power flow control, and topology optimization could enable Kansas and Oklahoma to integrate 5,200 MW of wind and solar generation currently in interconnection queues by 2025, more than double the development possible without the technologies.”

We need additional examples from TOs in the MISO and PJM footprint.

RTOs are not the first hurdle to overcome; the TOs are!

For regional transmission organizations to embrace grid enhancing technologies, their member transmission owners should first include these new ideas as alternatives to network upgrades in the interconnection study process. The FERC interconnection tariff at any RTO does not prohibit either the RTO or the transmission owner from looking at network upgrades alone. By thinking creatively, transmission owners can help interconnection customers and drive change at the RTO interconnection queue while addressing the backlog issue. If FERC needs evidence that grid enhancing technologies work, all it needs to see is proof of current implementations at some of the investor-owned utilities and transmission owners who have taken steps to pilot these grid enhancing technologies.

Transmission owners may find that including GETs in interconnection studies is not in their financial best interests, as their business model is based on investments in new lines. FERC is looking for opportunities to align TO incentives at a technical conference on September 10.

Take SPP TOs as an example.

If we take Southwest Power Pool (SPP) as an example, we learn about the following definitions for network upgrade and interconnection facilities from their generator interconnection tariff. Pay close attention to the words in the bold.

“Network Upgrades shall mean the additions, modifications, and upgrades to the Transmission System required at or beyond the point at which the Interconnection Facilities connect to the Transmission System to accommodate the interconnection of the Generating Facility to the Transmission System.”

And

“Interconnection Facilities shall mean the Transmission Owner’s Interconnection Facilities and the Interconnection Customer’s Interconnection Facilities. Collectively, Interconnection Facilities include all facilities and equipment between the Generating Facility and the Point of Interconnection, including any modification, additions or upgrades that are necessary to physically and electrically interconnect the Generating Facility to the Transmission System. Interconnection Facilities are sole use facilities and shall not include Distribution Upgrades, Stand Alone Network Upgrades or Network Upgrade.”

This blog asserts that grid-enhancing technologies should be considered “additions, modifications, and upgrades to the Transmission System” in definitions of network upgrade and interconnection facilities. Once TOs agree with this definition, they should let the RTO management know by a stakeholder vote. Then, the problem is solved when the RTO interconnection engineer has to re-study if a developer drops out of the queue. The engineer would consider alternatives to network upgrades, resulting in fewer upgrade costs, faster interconnection agreements, and less queue backlog.

Conclusion

If we’re not creative as an industry and incorporate new emerging technologies in transmission planning, more renewable projects get behind in the interconnection queue. This backlog means neither the transmission owners nor the interconnection customers would interconnect large utility-scale renewable projects. This backlog leads to the off-takers of those renewable projects not able to meet their carbon-free goals. This queue backlog then leads to a lack of jobs that impact economic development in each state. We can nip this problem in the bud right now by creative transmission owners willing to consider grid enhancing technologies as alternatives to expensive network upgrades.

How big utilities’ climate pledges fall short

Tue, 05/11/2021 - 14:09

Originally published on ILSR.org

Can a utility company be carbon neutral by 2050 if it builds a gas plant now? Maybe if it shuts off the gas plant well before its 40 years of useful life are complete, leaving electric customers to pay off millions in debt.

For this episode of the Local Energy Rules podcast, host John Farrell speaks with John Romankiewicz, Senior Analyst for the Sierra Club’s Beyond Coal Campaign. Romankiewicz and the Sierra Club released a report in January scoring utilities on their plans to transition from fossil fuels to clean power. Farrell and Romankiewicz discuss how utilities are doing far too little to retire coal, replace it with renewable energy generation, and fulfill their promises. The two had the conversation for a recent episode of ILSR’s Building Local Power podcast, republished here for Local Energy Rules.

Listen to the full episode and explore more resources below — including a transcript and summary of the conversation.

https://player.blubrry.com/?media_url=https%3A%2F%2Fmedia.blubrry.com%2Flocal_energy_rules%2Fp%2Fcontent.blubrry.com%2Flocal_energy_rules%2F2021-5-ler129-utility-climate-pledges.mp3&podcast_link=https%3A%2F%2Filsr.org%2Fdirty-truth-utility-climate-pledges-ler-129%2F#darkOrLight-light&shownotes-ffffff&shownotesBackground-ef7f00&download-ffffff&downloadBackground-003366&subscribe-ffffff&subscribeBackground-ef7f00&share-ffffff&shareBackground-003366

Podcast (localenergyrules): Play in new window | Download | Embed

Subscribe: Apple Podcasts | Stitcher | RSSEpisode Transcript

With Great Power Comes Great Responsibility

U.S. electric utilities were granted monopoly control because building competing sets of delivery wires in one area would be costly, wasteful, and would have delayed electrification. This market dominance, because it was granted with the condition of state oversight, then comes with a responsibility to customers, and as a result, a responsibility to the climate.

As much as utilities don’t like to move too fast, unfortunately the burden really rests on them, and everyone is looking to them to do something ambitious in this critical moment.

Utilities are meeting their responsibility with ‘net zero’ and ‘carbon-free’ pledges, but are they holding to their promises?

Romankiewicz and the Sierra Club’s Beyond Coal campaign track utility clean energy commitments and whether they correspond with utility resource planning (in most cases, they don’t). To present this information to the public, the Sierra Club has released The Dirty Truth About Utility Climate Pledges.

Grading Utilities on their Climate Action

The Sierra Club describes The Dirty Truth report as “a comprehensive assessment of whether utilities are committing to the actions needed to avert a cataclysmic climate crisis.” The report grades utility plans for the next decade on a scale from A to F.

Many utilities have made clean energy pledges with a target date of 2050 — nearly 30 years away, says Romankiewicz. Meanwhile, their energy resource plans only account for the next 15 years. Romankiewicz is interested in the steps that utilities are taking now, rather than lofty goals with no implementation plan.

The 79 companies analyzed in the report “account for 68 percent of the remaining coal generation in the United States.” Together, they only plan to retire 25 percent of that coal by 2030. The utilities also plan to build 36 gigawatts of new gas this decade, but only 100 gigawatts of new clean energy, says Romankiewicz. He predicts that to reach carbon neutrality and avoid climate disaster, the U.S. should install 400 to 500 gigawatts of renewable generation capacity by 2030.

The report also evaluates utilities on their energy efficiency investments – which are critical for reducing energy burden and increasing equity. Romankiewicz believes that two percent of retail sales should be the minimum for utility energy efficiency investment. Altogether, the utility companies studied only invest 0.7 percent of their retail sales in energy efficiency improvements.

We’re Way Beyond Coal

Coal-fired power isn’t cost effective. This is not news; no one has built a coal plant in the United States since 2013. Furthermore, regulated utilities are wasting billions of dollars by ‘self-scheduling’ when to employ existing coal plants. Given the security of a captive customer base, monopoly utilities can carelessly dispatch coal “more often than is dictated by market conditions.”

To prevent further losses, Romankiewicz asks utility regulators to step up to the plate for coal plant retirement — protecting the interests of consumers, rather than utility shareholders.

Billions of dollars are being wasted just in terms of… you’re just operating the coal units way too much. And customers are getting pinned with those costs at the end of the day.

Coal plants have disproportionately burdened low-income communities and communities of color with their toxic emissions. Retiring coal plants now would prevent additional damage to our climate and ease additional burden on these same communities, which are especially vulnerable to the impacts of climate change.

Doing the Same Thing and Expecting a Different Result

Often described as a ‘bridge fuel,’ gas-fired electricity generation faces the same trajectory as coal. It may become uneconomic to run existing gas plants as early as 2030. Besides, gas may have a lower carbon footprint than coal, but it is far from clean. Given the risks of stranded investments and continued greenhouse gas emission, gas-fired electricity is energy we can’t afford.

Romankiewicz resists the idea of gas as a bridge for retiring coal plants. He believes that utility resource planning, when done properly, will find that renewable energy is the real bridge to the future.

Don’t count out distributed solar within utility resource planning! Find out why utilities in Minnesota and other states need to plan for more competition in our Utility Distributed Energy Forecasts report.

Cities Can’t Reach their Goals Without Utilities

Another campaign from the Sierra Club is Ready for 100: a campaign to support communities as they commit to 100 percent clean, renewable energy. So far, eight states and more than 170 cities have made the pledge. Though the committed cities range in size and geographic location, there is a common factor that determines when they might reach their goal: utility cooperation.

Find interviews with leaders from ‘Ready for 100’ cities in our Voices of 100 series of the Local Energy Rules podcast.

Cities that own their utility have had the most success transitioning to 100 percent renewable energy. For communities served by a regulated utility, Romankiewicz lists several ways to leverage more control: municipalize (or threaten to), form a community choice aggregation (in the nine states that allow it), negotiate using a franchise agreement, form a clean energy partnership, or intervene at the public utilities commission.

Individuals can pressure their utility using the Sierra Club’s Dirty Truth report card. Romankiewicz also suggests pressuring investment companies, such as Black Rock and Vanguard, that own large shares in utility companies.

Citizens there could take our report card, and wave it in front of the utility as a more accessible way for any normal citizen to say, ‘What are you doing on coal and clean energy? Because this report card says you’re getting an F.’

Outside of utility pressure, Romankiewicz hopes that a state or federal requirement for all source “requests for proposal” in energy sourcing would help level the playing field for renewable resources. He also endorses compensation for consumer advocates who engage in regulatory intervention.

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 129 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 by Drew Birschbach.

This article originally posted at ilsr.org. For timely updates, follow John Farrell on Twitter, our energy work on Facebook, or sign up to get the Energy Democracy weekly update

Featured Photo Credit: Robert Daly via iStock

Fortum and Uniper team to manage operations of generating assets

Tue, 05/11/2021 - 13:02

Fortum and Uniper have finalized the first planning phase in three strategic cooperation areas: Nordic hydropower and physical trading optimization, wind and solar development, and hydrogen.

Under the proposed plans, Fortum would lead the operations of both companies’ Nordic hydro assets while Uniper would take the lead in the development of both companies’ wind and solar and hydrogen businesses.

In December 2020, Fortum and Uniper announced three joint cooperation areas to ensure the focused and effective implementation of the group strategy. The overall aim is to create more value for Fortum and Uniper in Nordic hydro and physical trading optimization and to better exploit growth opportunities in the areas of wind and solar and hydrogen. Based on the “One Team” approach, one of the companies will take the lead in each of these business areas.

The cooperation teams have developed the preliminary plans for the operating models, which will be further elaborated and conclusively assessed in the next phase. Implementation of the intended strategic cooperation in the three areas is subject to final approval by Fortum’s and Uniper’s governing bodies, as well as consultation with the relevant employee representation bodies in both companies.

Nordic hydro and physical trading optimization

The proposed plan anticipates that Fortum would become operationally responsible for Uniper’s hydro asset management and operations in Sweden, as well as its physical trading and optimization activities in the Nordics. The proposal would primarily affect about 180 Swedish hydro employees at Uniper. No redundancies are expected, and all existing locations of Fortum and Uniper in the joint Nordic portfolio are planned to remain in operation. Ownership of Uniper’s hydro assets would stay with Uniper.

The new operating model is planned to be implemented at the beginning of 2022.

By adopting best practices, tools and processes from both companies, the new combined Nordic hydro and physical trading team would be able to develop better digital solutions for daily operations management and improve safety performance. Fortum and Uniper believe the new operating model would create more value for both companies than continuing to optimize the two portfolios separately.

The combined activities would be led by Simon-Erik Ollus, head of Fortum’s generation division. These businesses employ around 400 people mainly in Sweden and Finland.

Wind and solar development

Fortum and Uniper plan to establish a joint organization for European onshore wind and solar activities. The initial focus will be on the most attractive European markets, starting from existing core regions. Fortum and Uniper plan to grow a sizeable portfolio of onshore wind and solar-based power generation, primarily in Europe. The target is to build 1.5 GW to 2 GW of new capacity by 2025.

The approach for European onshore wind and solar would establish a joint renewables development business that would bundle the competences in solar and wind development, asset and operations management, and expansion planning and commercialization to fully leverage the existing competences and different geographical footprints of both Uniper and Fortum. A special focus would be taken on project development to enable sizeable growth through a build-operate-transfer business model and selective investments on balance sheet.

Hydrogen business

Uniper’s presence throughout the hydrogen value chain, combined with Fortum’s strong presence in the Nordic countries, gives both companies the opportunity to take a leading position in the future hydrogen market. The joint approach for the hydrogen business under the leadership of Uniper will include the complementary technical and commercial capabilities of both companies. The new operating model for hydrogen will facilitate the development of a joint project and deal pipeline.

Creating cooperation benefits for both companies

In December 2020, Fortum and Uniper announced they identified cooperation benefits with a positive cash impact of about €100 million annually on a consolidated group basis. More than €50 million of these annual benefits are estimated to be achieved by the end of 2023, with full effect of about €100 million annually in 2025.

In Pictures: Building Canada’s largest remote solar + storage microgrid

Mon, 05/10/2021 - 18:43

Fort Chipewyan is an isolated community in Canada that is not connected to the main power grid. The community, which used to rely on diesel for power generation, is now home to the country’s largest community solar and storage microgrid project. Before the microgrid, diesel fuel was the source for all electricity production but since delivery of fuel depends on a shrinking window of winter ice road access, a new solution for electricity was needed. 

The microgrid was developed in cooperation with ATCO and Hitachi ABB Power Grids. It consists of approximately 2.6 MW of solar PV generation capacity and 1600kVA/1600kWh in battery energy storage and microgrid controls. The BESS will store excess solar generation during the day to be returned to the grid to meet evening demand or subsequent cloudy day. In all, the project reduces diesel consumption by 800,000 liters per year and allows Fort Chipewyan to be 100% powered by clean renewable energy. 

Building Canada’s largest remote solar + storage microgrid

Catalyst Partners makes its HQ a living demo for sustainable buildings

Mon, 05/10/2021 - 15:37

Allen Austin, ABB

Catalyst President Keith Winn is one of the founding members of the U.S. Green Building Council (USGBC). It’s not surprising, then, that his company helps clients to meet the requirements of LEED and other green building standards.

Catalyst focuses on energy efficiency services including auditing, modeling, and incentives and aims to become a supplier of choice on sustainable building projects. These typically require energy management, water metering, advanced energy metering, and energy performance optimization.

In 2020, the company set out to make its Grand Rapids, Michigan headquarters a showcase for the required sustainable technology.

Catalyst Partners’ rooftop solar array

Solar PV generation supplies 20 percent of the site’s power, reducing utility bills, but Catalyst needs to implement at least three energy conservation measures to reduce their Energy Use Intensity (EUI). Their hope is to reduce the building’s EUI by roughly 15% beyond the current level, which is already LEED Platinum certified.

When the reductions are dialed in, Catalyst plans to repurpose its 10-year-old solar system, replacing it with an updated system with sufficient annual production to achieve their 2030 net-positive goal.

“We had a metering system in place, but it failed and by then it was even out of production, so we needed something new,” recalls Kyle Rieth, Commissioning Authority and Energy Assessor at Catalyst Partners.

Catalyst turned to ABB, which installed a CMS-700 circuit monitoring system, enabling multi-channel measurement in AC and DC circuits. The CMS-700 consists of a control unit and sensors, allowing easy monitoring of the individual lines of a facility using any of several industry standard communication protocols.

ABB’s Ekip E-hub gathers the data (and optionally sends it to cloud-based storage where it can be accessed by any number of applications). Catalyst elected to use ABB Ability Energy and Asset Manager for the monitoring and control interface to understand what electricity is supplied by the utility vs. that by their solar panels. The new equipment was integrated with existing devices like circuit breakers.

“ABB also helped with installation remotely which was a big help since the pandemic prevented us from having more people on site,” notes Rieth.

With the ABB system in place, Catalyst is now able to track progress toward their net-zero electricity goal and is using Energy & Asset Manager’s analytics to optimize operations of the solar plant in relation to energy use in the building.

“We inform the design of buildings with energy modeling tools,” says Rieth. “ABB enables us to measure and verify targets have been achieved.”

Why 2021 could be the perfect year to deploy your solar portfolio

Mon, 05/10/2021 - 06:38

By Shaun Laughlin and Frank Teng

Grouping solar projects into larger portfolios is certainly not a new practice. After all, placing smaller projects into larger project groups is often the only way some smaller projects can find financing. It can also save funding organizations money because it can rationalize costs by allowing companies to purchase materials (like panels and racking) in bulk, thereby bringing down the overall price of the project. 

But 2020 was a challenging year for all solar, and it was especially so in the portfolio sector, where the complexity of doing such deals often put them out of reach for companies without the wherewithal, knowledge and expertise to get them done.

Financing projects in the midst of a global pandemic was challenging enough, but with many sites and supporting companies closed down for a time or working with smaller teams put logistical challenges in the way as well. One example: the difficulty in getting notices to proceed (NTP) since many permitting offices were completely closed. And with only so many people allowed on the construction site at one time due to safety measures, that increased the level of difficulty in bringing projects to completion.

Now that pandemic-related obstacles are lessening in many areas, what are the prospects for portfolio solar in 2021? Whether it’s the stabilization of the ITC or the Biden Administration’s commitment to investing in infrastructure, the prospects for portfolio solar are looking better than ever. Here are the four items we believe that will make 2021 a breakthrough year for the segment.

The ITC Extension

When the investment tax credit (ITC) was extended in 2020 for three years, it provided stability for the portfolio market when it came to funding. Absent the extension, the ITC was scheduled to drop to 10% for commercial projects, which would have stopped some projects from being financially viable — even in a portfolio setting.

The extension, passed in December, should provide new levels of comfort to companies who want to use tax-equity financing to fund portfolios of solar projects in 2021. It’s impossible to overestimate how important it was for the solar industry for the ITC extension to pass so the industry’s growth and expansion could continue. 

Financing Is Becoming More Widely Available

There are two different parts of the capital stack that are involved in portfolio solar financing. One part is the debt side, meaning who will provide the money to pay for the construction of the projects, among other project-related items. Most solar-industry analysts over the past two and a half years have said that there is currently significant debt financing currently waiting for projects to become available. Stability in the overall market in 2021 (with the passage of the ITC extension, as discussed above) will coax more of that capital off of the sidelines and into the industry as projects become available to fund.

The other side of the capital stack is the equity portion of the financing, which means answering the question of who will monetize the project and reap the profits through the use of the tax credits, renewable energy credits (RECs) or accelerated depreciation, among other profit-enabling mechanisms.

In 2020, when overall corporate revenues fell because of pandemic-related restrictions on business activity, corporations had less incentive to do tax-equity deals because they didn’t need the tax write-off as they had in previous years. If you didn’t have captive tax equity or long-standing relationships with tax-equity lenders, there was no way for developers to access that side of the capital stack if they were interested in investing in solar portfolios.

As 2021 unfolds, we expect more capital to come off the sidelines on both sides of the capital stack as company profitability returns to more normal levels. It’s important to partner with companies that have access to both sides of the stack to fund your solar portfolio needs and have the wherewithal to handle large portfolio projects.

Pent-Up Demand 

2020 put a large percentage of portfolio projects on hold because businesses weren’t as interested in investing in long-term solar projects given the difficult economic conditions last year. As the economy gets back on track, building owners and enterprises are now focusing on reduction of climate risk and its associated costs. 

In part, it’s a move to reduce carbon emissions in line with their corporate leadership commitments and leverage their properties for additional savings and revenue potential. Companies may need guidance on how to bundle their solar portfolios, and it would behoove them in 2021 to partner with companies that can do the essential blocking and tackling that’s necessary before a portfolio can seek funding.

In addition, solar is an opportunity to provide increased distributed resiliency during a time when the traditional electrical grid has shown itself to be fragile. When solar and storage is combined, it’s the perfect backup plan when it comes to maintaining electrical service in the face of climate-change induced severe weather. 

These factors mean the demand that built up over the past year will be ready to be fulfilled in 2021. As a result, it’s not surprising that the amount of portfolio solar that is expected to be built this year will be significant.

Job Creation

Since the ITC was first implemented in 2006, the Solar Energy Industry Association says the industry has grown 52% per year and created hundreds of thousands of jobs in just 15 years. When combined with the Biden Administration’s aggressive infrastructure plan, including the goal of making the United States carbon free by 2050, the future is bright for those seeking jobs in the solar industry.

More importantly, deploying solar on roofs, parking lots and other underused space right now is a direct way to create a win-win-win-win for everyone involved, from property owners to the community grid to the environment and the economy. In addition, as electrical vehicles become more omnipresent throughout the country, solar will be a key piece to powering our mobility in the future—bringing more jobs and economic growth to the areas of the country that need it most.

Related: Energy jobs are key to economic recovery from the pandemic

How Do We Get There?

The key to the growth of portfolio solar depends on partnering with companies with the financial strength to leverage the financing necessary to get those deals done. And while it may sound like the process is complicated, there are also companies out there that can help do the initial assessment of a portfolio to make sure it makes economic sense for the businesses interested in building solar networks for their properties. When two companies like that can get together and partner, the sky is often the limit.

As 2021 evolves, the portfolio solar market will continue to grow and expand. Make sure you’re ready to take advantage of it.

About the Authors

Shaun Laughlin is the Head of U.S. Strategic Development at Standard Solar, a leader in the development, funding, ownership and operation of commercial and community solar assets.

Frank Teng is Head of Business Development at OnSwitch Commercial Solar, a commercial solar+technology firm. The two companies recently partnered on a large Fortune 1000 portfolio to deploy ten projects in CA, NJ, and other states.

Solar and wind’s competitiveness over coal is accelerating, analysis shows

Fri, 05/07/2021 - 14:48

by Kathiann M. Kowalski, Energy News Network

Roughly four-fifths of U.S. coal plants are either scheduled to close by 2025 or now cost more to operate than new nearby solar or wind power would, new research shows.

The May 5 analysis comes from Energy Innovation: Policy & Technology, based in San Francisco. The work highlights the accelerating pace of the clean energy transition, even aside from the social costs of coal plant pollution.

What trends does the report show?

“Out of the 235 plants in the U.S. coal fleet, 182 plants, or 80 percent, are uneconomic or already retiring,” according to the report, which counted plants in service in 2018. Put another way, the share of total U.S. coal plant capacity from that year that won’t be competitive beyond the next few years has climbed from roughly five-eighths to three-fourths in just two years.

What does the report mean for planning ahead?

“I think of these numbers as a barometer,” said lead author Eric Gimon at Energy Innovation. “It’s a strong indicator of what’s happening in the field, but it’s not the exclusive indicator. And the fact that the barometer is changing so fast I think is significant.”

Why are more coal plants becoming noncompetitive?

The levelized costs for new solar or wind are falling faster than previously anticipated, Gimon said. Those are all-in lifetime costs for a facility divided by its energy production.

Meanwhile, the capacity factor for existing coal plants fell to 40% last year, down from 53% in 2017. A lower capacity factor means plants are being run less often and not providing full output, which increases operating and capital costs.

A comparison of Energy Innovation’s original analysis of renewables and coal cost-competitiveness, which includes a 2025
projection, to the most recent analysis. The comparison highlights that the projected 2025 coal uneconomic status
was almost reached by 2020, indicating that the coal cost crossover is happening faster than anticipated. How does this report compare to similar work done two years ago?

Earlier work by Energy Innovation and Vibrant Clean Energy in 2019 showed that a majority of U.S. coal plant capacity already costs more to keep running than new nearby solar or wind would cost.

Numbers are not directly comparable between the reports. The new analysis uses more complete data, Gimon said, and information about estimated costs has been more rigorously reviewed. Also, relevant areas for new solar or wind are now based on grid management balancing areas and their subdivisions, as defined by the National Renewable Energy Laboratory’s Regional Energy Deployment Systems model.

With adjustments, the 74.8% share of total U.S. coal capacity in 2020 that was either noncompetitive or already retiring was nearly as much as the 77.2% share that would have been predicted as of just two years ago. “We’re well ahead of pace,” Gimon said.

What’s special about the small share of U.S. coal plants that are still cost-competitive now, without accounting for the social costs of their pollution?

Those plants tend to be newer and larger, Gimon said. Some plants also have had access to relatively cheaper coal from Wyoming or other places.

Nonetheless, “every plant is to some extent vulnerable,” Gimon said. For example, a solar developer has acquired options for land near Nebraska’s largest coal-fired power plant and other coal plants, with an eye toward taking advantage of transmission if plants close sooner or cut back capacity.

In Ohio and elsewhere in the Midwest, most coal-fired power plants are older. A separate December 2020 analysis by Emily Grubert at the Georgia Institute of Technology found that less than one-sixth of the expected lifespan for U.S. coal-fired power plants’ capacity would remain by 2035 in any case.

What’s more competitive in Ohio?

New nearby renewables in Ohio would generally cost less than or are already within striking distance of the state’s remaining coal-fired generation. New solar power would have a slight edge over wind for more locations in Ohio, although there are about half a dozen places where costs for solar and wind would be within 10% of each other.

How do the environmental costs of coal power factor in?

The Energy Innovations analysis does not factor in the social costs of coal-fired power plants. Those include health and environmental impacts from sulfur dioxide, nitrous oxides and particulate pollution, as well as the plants’ greenhouse gas emissions that add to human-caused climate change.

In Gimon’s view, the economics undermine any justification for those harms that might once have existed. And while people who suffer health impacts aren’t easily identifiable, the harm is nonetheless real. As he sees it, the “village” of those with vested interests are essentially “sacrificing a number of foreigners to the volcano every year to keep their way of life going.”

What should policymakers do?

“I would be telling them to adapt,” said co-author Amanda Myers. The report recommends that regulators, policymakers and others “critically examine each and every coal plant in their jurisdiction given the overwhelming amount of existing coal and the rapidly changing economics of possible alternatives.” The report also suggests that energy efficiency, demand response and storage could support reliability so that roughly a quarter of U.S. coal capacity left in 2025 may not need replacement.

“If you hide your head in the sand and pretend it’s not happening, probably some of these things will happen faster and with more disruption,” Gimon added.

How do the report’s findings fit with what environmental advocates have been seeing in Ohio?

“This is a trend. This is not a surprise,” said Neil Waggoner, Ohio representative for the Sierra Club’s Beyond Coal campaign. “The costs of renewables just keep decreasing. Meanwhile, the coal plants out there are getting older. … None of these plants are spring chickens.”

Since late 2013, utilities had sought bailouts for uneconomic coal plants, Waggoner noted. Two Ohio Valley Electric Corporation plants continue to get subsidies of nearly $233,000 per day under House Bill 6, the 2019 law at the heart of an alleged $60 million conspiracy involving former Ohio House Speaker Larry Householder.

Bills to either repeal just those subsidies or to repeal all of HB 6 remain pending. Meanwhile, other bills could drastically limit further wind and solar energy in the state.

“The legislature is trying to find ways to put up barriers for renewables,” Waggoner said, “while also ignoring the reality of coal in an absolute decline.”

This article first appeared on Energy News Network and is republished here under a Creative Commons license.

EU approves €400 million aid scheme to develop renewables in Denmark

Fri, 05/07/2021 - 14:22

The European Commission has approved, under EU State aid rules, a Danish aid scheme to support electricity production from renewable sources: onshore and offshore wind, wave power plants, hydroelectric power plants and solar PV.

The measure will help Denmark reach its renewable energy targets without unduly distorting competition and will contribute to the European objective of achieving climate neutrality by 2050.

“This Danish scheme will contribute to substantial reductions in greenhouse emissions, supporting the objectives of the Green Deal. It will provide important support to a wide range of technologies generating renewable electricity, in line with EU rules,” said Executive Vice-President Margrethe Vestager, in charge of competition policy. “The wide eligibility criteria and the selection of the beneficiaries through a competitive bidding process will ensure the best value for taxpayers’ money and will minimize possible distortions of competition.”

The measure follows a previous Danish aid scheme for electricity from renewable energy approved by the EC in August 2018, which expired on Dec. 31, 2019. The scheme has a total maximum budget of about €400 million ($482 million) and is open until 2024.

The aid will be awarded through a competitive tendering procedure to begin this year and will take the form of a two-way contract-for-difference premium. This model guarantees renewable energy producers long-term price stability, helping them to make the necessary investments while limiting the cost for the state.

The Commission sees the aid as vital to meet Denmark’s environmental goals. It also has an incentive effect, as electricity prices do not fully cover the costs of generating electricity from renewable energy sources.

According to the International Energy Agency (IEA), Denmark is considered a leading nation in the global energy transition. The country aims to cut emissions by 70% from 1990 levels by 2030 and for renewables to cover at least half of the country’s total energy consumption by 2030.

The Nordic country has significant offshore wind potential and is home to some of the largest wind turbine producers, such as Vestas and Orsted.

Developer eyes economically distressed communities in rural Indiana for up to 1.6 GW of solar capacity

Fri, 05/07/2021 - 14:00

Hoosier Solar Holdings said last week that it is developing solar power facilities in economically distressed, rural communities across Indiana that have been designated as Qualified Opportunity Zones. 

Several solar and battery storage projects that collectively have a potential capcity of more than 1,600 megawatts (1.6 GW) are currently in active development, said the company. Many of these projects are expected to be operational by 2023.

Indiana’s 156 Opportunity Zones, in 58 counties across the state, provide federal capital gains tax advantages to attract investments in economically distressed urban and rural communities.

“Indiana has a unique opportunity to take advantage of solar power and battery storage technology to deliver reliable, low-cost power to serve the needs of residential and industrial customers,” said Paul Mitchell, Chief Executive Officer of Energy Systems Network, an Indianapolis-based partner of Hoosier Solar. “Importantly, we can attract investment capital to support development in economically distressed rural communities that have been designated as Opportunity Zones by Governor Eric Holcomb.”

Hoosier Solar selected South Bend, Indiana-based Inovateus Solar as the provider of engineering, procurement, and construction services, and Inovateus is leading Hoosier Solar’s engagement with landowners across Indiana.

“As multi-generational Hoosiers, we are thrilled to bring our deep experience in Indiana to this exciting initiative,” said T.J. Kanczuzewski, Chief Executive Officer of Inovateus Solar. “Hoosiers have deep ties to the land and we look forward to working with community leaders to encourage rural economic development while delivering competitively priced, reliable power.”

Hoosier Solar intends to use an Indiana-based workforce comprised of Hoosier businesses, utilizing Indiana’s strong manufacturing sector by purchasing finished equipment and raw materials from Indiana-based suppliers. Hoosier Solar also plans to involve local school groups and universities to provide job training and research opportunities for Indiana students.

 Hoosier Solar is a solar development company whose partners have decades of experience in energy development, financing, and economic development. Hoosier Solar will help meet the increasing demand for renewable energy by Indiana’s municipal and regulated utilities, as well as Indiana’s unique access to wholesale energy buyers across Midcontinent Independent System Operator (MISO) as well as the Mid-Atlantic region through the PJM regional interconnection organization.

“Indiana has remarkable resources for solar power,” said Carl Weatherley-White, Chief Executive Officer of Hoosier Solar, and Managing Director of Advantage Capital. “With deep agricultural roots, Hoosiers want to preserve productive land for multiple generations, and solar projects provide farmers with long-term, steady income that is neither seasonal nor dependent on weather or crop pricing. During the period that the land is not actively farmed, it can regenerate for future generations.”

IRENA members commit to advance the global hydropower fleet

Thu, 05/06/2021 - 18:12

Members of the International Renewable Energy Agency and private sector representatives are joining forces to modernize and refurbish the existing hydropower fleet around the globe. This is one of the results of the third meeting of the Collaborative Framework on Hydropower organized by IRENA, which aims to expand collaboration and action between the agency’s global membership on the continued deployment of hydropower technologies.

Over 100 participants from 50 countries attended the gathering virtually.

“Hydropower will be a critical element for decarbonising energy systems,” said IRENA’s Director-General Francesco La Camera, highlighting the role of hydropower as clean electricity as well as flexibility provider for the integration of high shares of variable renewables. While hydropower has been a source of baseload generation traditionally, it is increasingly used as peaking capacity and source for flexible generation and energy services, water management and socioeconomic benefits.

With 43%, hydropower accounts for the largest share of installed renewable capacity, according to IRENA’s latest data. Although a large number of hydropower projects are in the pipeline, the global hydropower fleet is aging and a considerable amount of capacity is due for retirement or in need of refurbishment. About 50% of hydro installed capacity is older than 30 years. IRENA’s World Energy Transitions Outlook suggests that global hydropower capacity will need to more than double by 2050 if the climate goal of 1.5° C under the Paris Agreement is to be achieved.

“There is no excuse in 2021 anymore for no good environmental practices in the hydropower sector,” said Eddie Rich, chief executive officer of the International Hydropower Association (IHA). To drive the global hydropower agenda, IHA has initiated the San José Declaration on Sustainable Hydropower, to be endorsed by the World Hydropower Congress in September and presented to COP26 in Glasgow in November. “The Declaration will seek to place sustainable hydropower as an essential element in tackling climate change, being clear that good sustainability practice should be a minimum expectation for the future,” Rich added.

The need to urgently add hydropower capacity brings challenges such as unlocking the necessary investments, financial viability through fair markets and remuneration, the need to ensure sustainability, the need for innovations in technology, markets and business models, efficiency improvements, as well as more integrated planning. To close the gaps in global hydropower, the Collaborative Framework on Hydropower will identify “champion” countries taking the lead on key hydropower-related topics and help prepare the World Hydropower Congress.

China, Indonesia, Turkey, the U.S. and Uruguay shared their experiences and recommendations on the topics mentioned above during the Collaborative Framework. “Champion” countries will now take the thematic workplans forward. The next Collaborative Framework is scheduled as a high-level meeting at the World Hydropower Congress.

US DOE announces $12 Million for enhanced geothermal technology improvement

Thu, 05/06/2021 - 14:51

The U.S. Department of Energy (DOE) last week announced up to $12 million for technologies that can make geothermal systems more efficient for clean, renewable energy production. The funding is designed to help scientists and engineers unlock the full potential of enhanced geothermal power to help tackle the climate crisis and achieve the Biden Administration’s goal of net-zero carbon emissions by 2050.

Enhanced Geothermal Systems (EGS) are man-made reservoirs created by injecting fluid into “hot rock,” which is heated by the natural warmth of the Earth’s core. The fluid re-opens pre-existing fractures, allowing it to circulate through the hot rock, and bring the heated water to the surface. That hot water becomes steam that spins a turbine, creating clean, renewable energy.

The “Innovative Methods to Control Hydraulic Properties of Enhanced Geothermal Systems” funding opportunity will support the research, development, demonstration, and deployment of technologies and techniques to control the fluid flow in EGS reservoirs, enhancing the connectivity of pre-existing fracture networks and optimizing them for heat mining. This ability to customize reservoirs has the potential to increase their efficiency and longevity—driving down EGS costs, reducing the risk of development, and accelerating the path towards widespread commercialization.

A  2019 study by DOE’s Geothermal Technologies Office (GTO) concluded that with technology improvement geothermal power generation could increase 26-fold, deploying 60 gigawatts-electric (GWe) of clean energy by 2050. Despite that vast potential, there are only 3.7 GWe of geothermal energy currently installed in the United States.

GTO is using its research and development portfolio to advance technologies and projects that can rapidly increase that number, while supporting thousands of good-paying jobs for American workers—including those in the oil and gas industries that already have matching skills and expertise.

“Enhanced geothermal systems harness the clean, renewable energy that lives right beneath our feet—available at any time, in any weather, in any part of the country,” said Secretary of Energy Jennifer M. Granholm. “This new funding will help us tap into its enormous potential to power millions of homes and businesses, reduce carbon emissions, and put thousands to work in greener, good-paying jobs.”

GTO is looking for applications that address the funding opportunity review criteria in full. Applications are due by 5:00 p.m. ET on June 15, 2021.

More information about the funding opportunity HERE.

Solar industry employment dropped 6.7% in 2020, new report shows

Thu, 05/06/2021 - 13:59

The U.S. solar industry employed 231,474 workers in 2020, a 6.7% drop from 2019 due to pandemic restrictions and increased labor productivity, according to the National Solar Jobs Census 2020 released today by the Solar Energy Industries Association (SEIA), The Solar Foundation, the Interstate Renewable Energy Council (IREC), and BW Research. On the flip side, total solar installed capacity increased in 2020, mostly due to utility-scale solar additions, which require less workers.

Indeed, labor productivity did increase in all three market segments, up 19% in the residential sector, 2% in the non-residential sector and 32% in the utility-scale sector. The pandemic took a toll on residential jobs in the summer, and those jobs did not fully recover by the end of the year. 

Breakdown of Solar Job Types

Installation and construction-related employment continued to be the largest segment in the industry, representing 67% of all jobs​. Of all installation jobs:​ 55% were residential​; 18% were commercial​; 8% community solar​ and 19% were utility-scale​. Importantly, workers in manufacturing jobs represented 14% of all American industry employment, while sales and distribution and operations and maintenance represented 11% and 4% of all jobs, respectively​. The ‘other’ category, comprised of workers in fields like finance, legal, research, advocacy and communications, makes up 4% of all U.S. solar workers​.

The new figures come as lawmakers debate infrastructure spending that could boost the solar workforce with hundreds of thousands of jobs over the next decade. SEIA analysis shows that the solar industry will need to reach more than 900,000 workers to reach President Biden’s 2035 clean energy target. SEIA is advocating for policies that will grow clean energy deployment and lay the groundwork to hire and train those workers.

Read more: Energy jobs are key to economic recovery from the pandemic

“The solar industry continues to support hundreds of thousands of jobs across all 50 states, and even during a pandemic, our companies largely were able to keep workers on the job,” said Abigail Ross Hopper, president and CEO of SEIA. “We now have an opportunity to quadruple our workforce, adding diversity and supporting underserved communities by taking policy steps that incentivize solar and storage deployment and provide long-term certainty for solar businesses.”

“Even as the pandemic brought unprecedented challenges, the 11th annual Solar Jobs Census shows the solar industry continues to create hundreds of thousands of high-quality jobs for men and women of all education levels and backgrounds,” said Larry Sherwood, Administrator of The Solar Foundation and President and CEO of IREC. “Since 2010, The Solar Foundation has tracked the rapid expansion of the solar industry and workforce, and we look forward to supporting even more dramatic growth over the next decade.”

Subscribe to Renewable Energy World’s free, weekly newsletter for more stories like this

Notably, the report shows that the U.S. solar industry has a unionization rate of 10.3%, which is substantially more than previously estimated and comparable to the economy-wide rate.

Solar Doing Better with D&I

The report also shows an increase in solar workforce diversity across nearly every demographic category, including female workers, which now represent 30% of the solar workforce. Representation among women and minority demographic groups has improved significantly since 2015, including a 39% increase for women, 92% increase for Hispanic or Latino workers, 18% increase for Asian American and Pacific Islander workers, and a 73% increase for Black or African American workers. 

The solar industry also continues to outpace the rest of the economy in its employment of veterans, which represent 8.7% of the solar workforce, compared to 5.7% in the overall economy.

Solar occupations earn wages comparable to or better than those same occupation types in other industries. For example, wages for solar workers continue to beat other industry averages, when comparing pay for positions such as construction managers, electricians and installers. 

The Solar Jobs Census counts those workers who spend a majority of their time on solar-related work. Download the full report here.

Read More: There are 30 times more jobs created from rooftop solar vs utility-scale solar, utility filing says

Enel’s portfolio of renewable projects under construction tops 2 GW

Wed, 05/05/2021 - 18:44

Today, global energy company Enel said that its US renewable subsidiary Enel Green Power North America, has started construction on five new renewable energy projects in the US with a total combined capacity of 1.5 GW. The projects are:

  • Roseland solar + storage,
  • Blue Jay solar + storage,
  • Ranchland wind + storage,
  • Alta Farms wind project, and
  • Rockhaven wind project.

In addition, Enel said it’s adding 57-MW battery storage systems to the High Lonesome wind farm and the Roadrunner solar farm both located in Texas. The new wind, solar and hybrid projects announced today represent over 1.5 GW of new capacity and 319 MW of battery storage capacity.

Projects in Texas

Enel has now started construction of the 639.6-MW Roseland solar will be paired with a 59 MW battery storage system + storage. The project, which is expected to be online in mid-2022, will be Enel’s largest in North America.

In Grimes County, Texas, the Blue Jay solar + storage project will pair a 270-MW solar plant with a 59-MW battery storage system. The project is expected to begin operations by the end of 2021. The Ranchland wind + storage project will be a 263-MW wind farm paired with an 87-MW battery system. Located in Callahan and Eastland counties, operations of the project are expected to begin in the first quarter of 2022.

Enel previously announced construction, which is currently underway, on three other renewables + storage hybrids in Texas including the Lily solar + storage, Azure Sky solar + storage and Azure Sky wind + storage projects. Additionally, the company plans to retrofit its 500 MW High Lonesome wind farm and 497 MW Roadrunner solar farm in West Texas with a 57 MW battery storage system at each plant, with construction expected to begin this summer. In total, Enel Green Power has six projects under construction in Texas representing 2 GW of new generating capacity and around 600 MW of battery storage. 

Projects in Illinois and Oklahoma

Enel is growing its portfolio in Illinois with the construction of the Alta Farms wind project in DeWitt County. The 200-MW plant is expected to begin operations in the second half of 2022. In Oklahoma, Enel has started construction on the 140-MW Rockhaven wind project in Garvin and Carter counties, adjacent to the Origin wind farm which the company has operated since 2015. The project is expected to achieve commercial operation by the end of 2021.

Subscribe to Renewable Energy World’s free, weekly newsletter for more stories like this

“The American transition to clean energy is unstoppable,” said Salvatore Bernabei, CEO of Enel Green Power and Head of Enel’s Global Power Generation business line. “With more than 2 GW now under construction in the United States, more than ever before, we are creating value with communities, partners, and our entire value chain, helping meet the ambitious clean energy targets of policymakers and businesses alike.”

Over their lifetime, the five new projects are expected to generate around 450 million US dollars in tax revenue for local communities and new income for project landowners. Construction of the projects will be responsible for over 1,500 construction jobs. With these projects, Enel Green Power North America currently has over 2.3 GW of renewable generation under construction and by mid-year will have 606 MW of battery storage capacity under construction.

Energy Storage technology is an important educational topic at POWERGEN International and our call for speakers is open! See our list of tracks and learn how to submit your speaking idea here. Submit your speaking idea today.

New tool empowers utilities to reduce emissions in investment planning

Wed, 05/05/2021 - 14:51

By Erin Murphy and Christie Hicks, EDF

As the United States moves toward decarbonization, cities and states must use all means available to reduce climate pollution, and natural gas utilities should be at the forefront of this rapid energy transition. Gas utilities are the subject of increasing scrutiny because plans to expand and fortify their infrastructure could lock in greenhouse gas emissions and costs for decades. As the industry reckons with its role in a decarbonized future, advocates, utilities and regulators alike are calling for a carefully-managed transition that avoids costly long-term investments. New York has been at the forefront of this effort, seeking to balance ambitious climate goals with outdated natural gas investment planning processes.

To help utility planners align business decisions with environmental targets, EDF engaged MJ Bradley and Associates to develop the Gas Company Climate Planning Tool, an innovative new framework for New York and other states.

This first-of-its-kind tool has the power to transform natural gas utility investment decisions. It is pre-populated with publicly reported data on the life cycle greenhouse gas emissions associated with natural gas investments, including customizable options that reflect the myriad of options utilities have to expand service. It is free and available to the public, enabling utilities, regulators and stakeholders to compare emissions associated with numerous demand- and supply-side options to meet energy needs. For example, utilities can compare the impact of traditional pipeline capacity, using energy efficiency to reduce demand, or incorporating alternative fuels like biogas and hydrogen in their fuel mix. An accompanying report further assists state regulators in developing a framework for assessing life cycle greenhouse gas emissions of investment options.

There is more urgency than ever to chart a new path forward for natural gas investments

In addition to carbon dioxide emitted from combustion of natural gas, its production, transmission and distribution results in significant emissions from methane — a greenhouse gas 84 times more potent than carbon dioxide during the first 20 years after its release. Attention to this issue is more important than ever, since reducing methane emissions could result in more immediate benefits in the battle against global warming.

Most natural gas planning happens through piecemeal processes and often behind closed doors. It has been difficult, if not impossible, for utilities, regulators and the public to easily and accurately compare the climate impact of supply and demand management options. To address this need, the Gas Company Climate Planning Tool provides an independent, data-driven way to assess the long-term greenhouse gas emissions of various planning scenarios in a way that reduces both climate pollution and costs for the utility and the customer.

This tool could not come at a better time, as more states are adopting bold climate goals but gas utilities continue to operate under a business-as-usual paradigm — planning for year-over-year growth and expansion of the natural gas system.

The New York Public Service Commission, for example, acknowledged this tension and found that current gas utility planning in the state is not keeping pace with the energy system transformation. New York enacted the Climate Leadership and Community Protection Act in 2019 — requiring an 85% reduction in statewide greenhouse gas emissions by 2050. In 2020, the commission launched a proceeding to modernize the natural gas planning process. Recognizing that comprehensive, transparent, equitable long-term planning must be at the core of reforms, the PSC recommended that utilities calculate and report the greenhouse gas emissions associated with all supply and demand solutions. It also proposed that, rather than usual infrastructure investments, gas utilities consider retirement of leak-prone pipe and use of non-pipeline alternatives to meet customer needs. To help with these tasks, EDF submitted the Gas Company Climate Planning Tool, along with detailed recommendations to the PSC.

Aligning long-term gas planning with climate goals requires more than a quantitative tool

Transparent, unbiased and publicly available data will improve gas supply decision-making to align gas planning with the imperative to decarbonize. The Gas Company Climate Planning Tool not only meets the information needs of the commission, but also those of other regulators across the country facing similar issues who are grappling with how to improve their state’s long-term gas planning processes to align utility investments with climate goals.

There is more work to be done. The tool is purely quantitative, and other factors should be considered. Qualitative factors can be equally important in investment decisions, especially when considering disproportionately impacted and low-income communities. Equity must be at the core of policies and reform processes. The Gas Company Planning Tool is the first step for a more equitable, inclusive long-term gas planning process.

Utilities, regulators and stakeholders in New York and across the country can begin using this tool today. Every dollar spent by gas utilities either gets us closer to or further from our climate targets.

About the Authors

Erin Murphy is Senior Attorney, Energy Markets & Utility Regulation at the Environmental Defense Fund. Erin represents EDF in regulatory proceedings involving the design of wholesale and retail natural gas markets, seeking to facilitate the clean energy transformation. She advocates before state public utility commissions for gas supply planning mechanisms to prevent unneeded long-term investments in gas infrastructure, and for utility adoption of programs to reduce methane emissions from gas distribution networks. Erin also advocates before the Federal Energy Regulatory Commission for new and better ways to facilitate renewable energy integration and harmonize the wholesale natural gas and electricity markets.

Christie Hicks is Lead Counsel, Energy Markets & Utility Regulation at EDF. Christie’s work focuses on reducing our reliance on natural gas, fostering markets and regulatory structures that will allow clean energy resources to compete and flourish, avoiding over investment in long-lived natural gas infrastructure and reducing emissions from gas transmission and distribution systems by developing, advocating and defending EDF’s interests before FERC, RTOs, and PUCs.

Jolette Westbrook also contributed to this blog.

AES pooling clean energy resources to power Google data centers

Wed, 05/05/2021 - 14:36

Virginia-based AES Corp. will supply nearly carbon-free electricity to power Google’s data centers in the state.

The power generator announced it will become sole supplier of the tech giant’s data-center needs for clean energy. Under the agreement AES will start supply later this year.

See our interview with AES Chief Operating Officer Bernerd Da Santos

AES will source the energy needed from a portfolio of wind, solar, hydro and battery storage which will be developed or contracted by the utility. The utility will ensure the energy powering those data centers will be 90% carbon-free when measured on an hourly basis

“Last year, Google set an ambitious sustainability goal of committing to 100% 24/7 carbon-free energy by 2030. Today, we are proud that through our collaboration with Google, we are making 24/7 carbon-free energy a reality for their data centers in Virginia,” said Andrés Gluski, AES President and CEO. “This first-of-its-kind solution, which we co-created with Google, will set a new sustainability standard for companies and organizations seeking to eliminate carbon from their energy supply.”
AES assembled the 500 MW portfolio from a combination of AES’ own renewable energy projects and those of third-party developers, which were selected, sized and contracted to meet Google’s energy needs across a number of considerations, including cost efficiency, additionality and carbon-free energy profile. The portfolio assembled by AES is expected to require approximately $600 million of investment and generate 1,200 jobs, both permanent and construction, in the host communities.

Subscribe to Renewable Energy World’s free, weekly newsletter for more stories like this

This supply agreement follows on the strategic alliance AES and Google formed in November 2019 to leverage Google Cloud technology to accelerate innovation in energy distribution and management and advance the adoption of clean energy.

“Not only is this partnership with AES an important step towards achieving Google’s 24/7 carbon-free energy goal, it also lays a blueprint for other companies looking to decarbonize their own operations,” says Michael Terrell, Director of Energy at Google. “Our hope is that this model can be replicated to accelerate the clean energy transition, both for companies and, eventually, for power grids.” 

AES has worked or is developing numerous carbon-free energy projects globally, including a partnership with Kaua’I Island Utility in Hawaii and energy storage sites in California, Arizona and elsewhere.

— — — — —

Renewables, energy storage and on-site power are all key parts of POWERGEN International, happening Jan. 26-28 in Dallas, Texas. The POWERGEN Call for Speakers is now open and seeking content for tracks such as Decarbonization, Digitalization, Energy Storage Breakthroughs, the Future of Electricity, Hydrogen: What’s New, Optimizing Plant Performance, the New Energy Mix (on-site power) and Trends in Conventional Power. Click here to see more and submit a session idea.

We need more grid engineers to implement Biden’s plan (Part 2 of 2)

Tue, 05/04/2021 - 18:03

Hiring engineers via the H1B immigration process would make implementing Biden’s infrastructure plan more efficient. In part 1, we focused on the need for transmission planning engineers. In part 2, the focus is on the need for additional market systems and distribution planning engineers.

Engineers should have the flexibility to move within an organization

Engineers who are starting in their jobs need a clear career trajectory. For example, if hired first in interconnection planning, an electrical engineer can spend three years in that position. Later they can join the transmission planning department to put the skills they have gained by modeling interconnection requests because the skills to study steady-state and dynamic stability models in planning are relatable to interconnection planning.

At electric utility companies with both transmission planning and distribution planning, engineers can move from one department to another without needing a new H1B process. An H1B process hooks the engineer to the specific employer and at a specific location and a specific job.

Remove that specific job requirement if we want more engineers hired within the same company at the same location. If a utility company is spending more than $10,000 to hire an engineer on an H1B process, it makes sense from a business case perspective to show a career path for more than three years.

Another need – Market systems engineers

Engineers are also needed to implement market systems in the organized wholesale energy markets administered by RTOs. Very few engineers can code and understand the complex algorithms inside the market engine that solves every four seconds in the control room.

As we integrate more distributed energy resources on the grid, RTOs like MISO are making a case that market systems engines might slow down (take more than 4 seconds to solve) if we connect more distributed resources to the transmission grid. However, very few market systems engineers can get under the market engine hood to understand the issue. This situation happened when MISO asked FERC to extend the implementation deadline for FERC order 841 on electric storage resources. There are very few market system engineers who can challenge MISO on their extension request at FERC. However, without this expertise, energy storage developers find it hard to challenge MISO.

Focusing on regulatory policy alone would not get the job done

Today there is much focus on regulatory policy. While there is nothing wrong with so many engineers and policy professionals focusing on what we need in the future, the regulators also need to understand that we need engineers to execute or implement these renewable projects to meet carbon-free goals.

Policy professionals are more tuned towards communication and messaging. They can write in simple terms a one-pager that become policy briefs for state and federal regulators. We need these policy professionals to demystify the complex topics associated with wholesale energy markets.

Distribution planning concepts are even more complicated than wholesale energy market concepts. Public utility commissions are already seeing the need for more engineers. It is not good for the electric utility industry if a PUC trains an engineer and they leave for a higher salary at a utility company or a renewable project developer.

We need these engineers to stay within a company for at least three years to understand all the complexities of a certain job. That three-year duration can only come if the PUC hires international professionals via the H1B legal immigration process. And for that to happen, the PUC should not be responsible for higher immigration fees.

Charge immigration fees for hiring engineering professionals according to the revenue of the hiring company. For example, Google can afford $12,000 to $20,000 for a green card. However, don’t ask a PUC to pay those high immigration fees to hire an engineer.

This engineer shortage is not a renewable project developer problem alone

It would be a mistake to think renewable project developers alone should find more grid injection engineers. Renewable project developers, transmission owners, regional transmission organizations, electric utility companies all share the need for additional grid injection engineers in the next three to five years.

The reality is that grid injection engineers at the RTOs are in high demand. Major renewable project developers seek them because these engineers understand the interconnection queue rules. Even though transmission owners at PJM have approved contractors list, those approved contractors may not have enough engineers to keep up with the volume of PJM interconnection queue projects. Hence this problem is not unique to renewable project developers. It takes a village to hire these grid injection engineers and retain them at least for a couple of years at each organization.

The industry is not served well if fresh graduates move from company to company every year. We need these engineers to stay at a company for at least three years because it takes that much time to model a transmission or distribution system.

We have barely scratched the surface of integrated distribution planning

The electric utility industry might see more distributed energy resources interconnect to the transmission grid. Once that happens, there would be a long line in the interconnection queue for distributed resources at the RTOs. We need distribution planning engineers to interconnect distributed resources to the transmission grid, not transmission planning engineers.

Distribution planning models are different than transmission planning models. Very few distribution planning engineers are well versed in transmission planning. Similarly, few transmission planning engineers can successfully model distribution planning.

Traditionally transmission planning and distribution planning has been done in silos. However, with more distributed energy resource interest, especially with FERC order 2222, we can expect more distributed energy resources to connect to the transmission grid. Hence we need more engineers to integrate distribution planning and transmission planning.

Mitsubishi, Powin to provide battery storage retrofits to California solar projects

Tue, 05/04/2021 - 15:41

Southern Power has awarded a combined 640-MWh energy storage project to Mitsubishi Power Americas and Powin LLC.

The two-site utility-scale battery project is designed to enhance California’s grid reliability with additional and flexible resource capacity paired with renewable energies. Southern Power is the wholesale energy wing of Atlanta-based utility owner Southern Co.

The battery energy storage systems (BESS) represent some of the largest retrofits of solar and storage in North America, the companies said. Southern Power’s 205-MW Garland Solar Facility in Kern County (pictured) will add 88 MW/352-MWh of energy storage, while the 204-MW Tranquility Solar Facility in Fresno County will add 72 MW/288 MWh of BESS capacity.

Both projects are scheduled to come online in 2021.

Mitsubishi Power is excited to leverage our network of capabilities in the Americas and globally to bring low carbon solutions to Southern Power,” Tom Cornell, senior vice president of Mitsubishi Power’s NEXT, said. “These battery energy storage projects, which will use lithium iron phosphate technology, fit within our vision to provide short- and long-term energy storage solutions that include lithium ion, hydrogen, and other emerging storage technologies.

Subscribe to Renewable Energy World’s free, weekly newsletter for more stories like this

The energy storage projects will be owned in partnership with AIP Management and Global Atlantic Financial Group, both of which have existing ownership interests in the Garland and Tranquillity solar facilities that went into commercial operation in 2016. Southern Power operates the solar projects and will be responsible for operating the energy storage projects upon completion.

“This award highlights the fact that large-scale solar PV paired with energy storage is cost competitive,” Geoff Brown, CEO of Powin, said. “We applaud Southern Power for taking this step toward helping California meet its clean energy goals with energy storage.”

Headquartered in Tualatin, Oregon, Powin has built over 600 MWh of systems, supporting 54 projects in 10 states and 8 countries. Powin has a contracted pipeline to supply over 4,000 MWh of energy storage systems globally over the next five years.

Massive solar + storage project receives federal approval to be built on US public lands

Tue, 05/04/2021 - 14:29

Yesterday, the U.S. Interior Department (DOI) announced that the Bureau of Land Management (BLM) has given final approval to a new solar energy project on public lands in California. The approval gives developer Sonoran West a green light to go forward with the construction of the Crimson Solar Project, a 350-megawatt (MW) solar photovoltaic facility with a 350-MW energy storage system, and the necessary ancillary support facilities to generate and deliver power through the Southern California Edison Colorado River Substation.

The Crimson Solar Project represents an investment of roughly $550 million and will provide an estimated 650 temporary construction jobs, 10 permanent jobs and 40 temporary jobs in operations and maintenance over the 30-year life of the project, said DOI.

Sonoran West Solar Holdings, LLC, a wholly-owned subsidiary of Recurrent Energy, LLC will own the project, which will occupy up to approximately 2,000 acres of BLM-administered lands approximately 13 miles west of Blythe, in Riverside County, California. (see map)

Although the project application pre-dates the Desert Renewable Energy Conservation Plan (DRECP), the Crimson Solar Project is located within one of the areas designated for development, known as Development Focus Areas, by the DRECP. Through the DRECP process, the BLM, State of California and U.S. Fish and Wildlife Service worked with renewable energy developers, the conservation community, Tribes, local government, and others over several years to identify areas appropriate for renewable energy development and areas that should be conserved.

“The time for a clean energy future is now. We must make bold investments that will tackle climate change and create good-paying American jobs,” said Secretary Deb Haaland. “Projects like this can help to make America a global leader in the clean energy economy through the acceleration of responsible renewable energy development on public lands.”

“America’s public lands provide a tremendous opportunity to realize the potential of renewable energy. BLM is committed to engaging in an inclusive and equitable process in pursuit of a clean energy economy,” said Principal Deputy Assistant Secretary of Land and Minerals Laura Daniel-Davis.

“The BLM California is proud to support responsible development of renewable energy projects as part of our mission to sustainably manage public lands,” said State Director of the BLM California Karen Mouritsen. “The Crimson Solar project showcases the agency’s commitment to meeting California’s energy and economic needs with 21st Century technology.”

Repowered 160-kW Valatie Falls Hydro plant now operating

Tue, 05/04/2021 - 14:24

On April 26, the 160-kW Valatie Falls Hydro plant in New York began generating power for the first time since June 2018.

Valatie Falls will provide direct energy to the Village of Valatie, as well as charge the electric vehicles of local business PlugIn Stations Online.

Built along the shores of Kinderhook Creek in Valatie, Valatie Falls Hydro first produced power in the early 1990s. The site was the filming location for the final scene of the last movie Harry Houdini ever made, “Haldane of the Secret Service.”

VF Hydro and PlugIn Stations Online purchased the plant in April 2020 and spent the past year rebuilding the plant and refurbishing the offices on the upper level. With the help of former owners Fred and Bob Munch, as well as Jim Clevenstine from Clevenstine Engineering, this Federal Energy Regulatory Commission-licensed project was able to get back online, according to a press release.