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Ontario Power Generation announces plans to rebuild century-old Calabogie Generating Station

Plans are under way to rebuild one of Ontario Power Generation’s oldest hydroelectric generating stations, which was damaged by a tornado in 2018. Constructed in 1917, the 5-MW Calabogie Generating Station has produced renewable, low-cost electricity on the Madawaska River for decades.

On Sept. 21, 2018, the station was hit by a tornado, one of six that touched down in the Ottawa-Gatineau region in eastern Ontario, Canada. Wind gusts estimated at 175 km/h damaged more than two dozen homes and buildings in the Calabogie area and ripped off the roof of the Calabogie powerhouse.

Before this event, OPG concluded rebuilding the generating station, which was nearing the end of its operational life, was the best alternative to repairing or refurbishing. The project will involve demolishing the existing powerhouse and building a new powerhouse about 50 m upstream from the existing building. OPG plans to more than double the station’s existing capacity to about 10.8 MW. OPG does not plan to alter the current water levels and flows for the station.

Construction is planned to start in 2020, with the new station expected to go into service in 2022.

An environmental assessment is under way to evaluate the project’s potential effects on the environment during both construction and operation. As part of this process, OPG will consult with local First Nations, including the Algonquins of Pikwakanagan and the Algonquins of Ontario. “Consultation with Indigenous communities and the public is an integral component of this process,” said Mike Martelli, president of renewable generation at OPG.

The Calabogie GS was constructed by the Calabogie Light and Power Company to support local development and the lumber industry.

In 1929, OPG’s predecessor, the Hydro-Electric Power Commission of Ontario, acquired the Calabogie GS.

Long-term financing for solar is possible and critical for supporting continued industry growth

By Jim Spano

Installed solar capacity in the United States exceeded 10 GW for the third year in a row in 2018, and the pace of growth is expected to continue. The first quarter of 2019 was the strongest in the history of the U.S. solar market, according to a recent report from Solar Energy Industries Association (SEIA) and Wood Mackenzie Power & Renewables. Yet inefficient and costly project financing inhibits many solar developers from tapping into the market’s true potential. 

With changes to the investment tax credit (ITC) looming, there is an opportunity to address some of the long-term financing challenges that have confronted the industry for many years. New debt financing vehicles, with terms that match the full operational life of solar projects will support continued industry growth as utilities are increasingly establishing renewable energy targets or supporting similar state goals

Solar financing today 

The solar finance landscape remains a borrower’s market, but most of the loans that are available to developers today have shorter terms that are not in line with the operational life of projects. According to Wood Mackenzie, mini-perm debt structures are the most common financing vehicle today. The number of total lenders and new market entrants is rising, which is increasing competition and has generally outweighed the negative effects of the ITC step down (a bit more on that later). 

Mini-perm debt structures mean the lender offers repayment terms of 4-7 years, after which the project sponsor must refinance. This process repeats multiple times over the course of a 20-30 year contract. In recognizing this mismatch, the industry has been discussing the benefits of shifting towards shorter PPAs, but this transition would still leave small to midsize project developers with the same structure of today, which is akin to financing your mortgage with a car loan. The result is a paradigm of negative project cash flows from day one in which developers must flip their projects to investors in order to have working capital to develop their next projects. 

Wood Mackenzie U.S. Solar Market Insight Q2 2019

Impacts on industry growth

New models of long-term financing like the solar mortgage REIT can help break this cycle and align debt repayment terms to the operational life of the project. This is not a niche problem to address. 90 percent of solar projects in the U.S. are financed – meaning we cannot overlook the impact that financing has on whether or not projects succeed, market growth continues and utilities are able to meet increasing demands for renewable energy. 

Solar PV was by far the largest renewable energy employer worldwide in 2018, meaning there are abundant opportunities for the industry to support job growth. If we can align financing terms with the operational life of solar projects, smaller developers will be able to grow their businesses more sustainably. It is a fundamental shift in how we think about the business of project development. If more developers are able to adopt this approach, they will be more prolific in the number of projects produced and feed utilities’ ever-growing need for solar. 

What is a solar mortgage REIT?

Real estate investment trusts (REITs) are widely deployed and proven in the real estate industry, and with similar attributes for the solar market, solar mortgage REITs can lower the cost of capital for projects, increase the net operating income of an asset and ensure positive cash flows over the lifetime of the PPA. Solar mortgage REITs offer fixed-rate and long-term mortgage loans to solar developers for new installations or long-term refinancing for existing projects. Ultimately, solar mortgage REITs can provide developers with the option to maintain ownership of a project.  

On paper, it may be true that the ITC step down hasn’t negatively impacted installed capacity or job growth, but the changes that come with shifting tax structures are important to recognize. One silver lining to the step down is that tax equity will become a smaller part of the capital stack for solar projects, making more room for debt to fill in that gap – so long as that debt is cost effective and long-term. Again, this ultimately enables ongoing industry growth and meets the needs of utilities looking for more renewable energy resources. 

Project developers are the cornerstone of a successful solar industry, bridging the gap between technology and deployments. But even with the market success of solar as a reliable investment, developers continue to be hindered by suboptimal financing solutions. As we enter the ITC sunset, bringing proven investment vehicles for long-term financing will help to ensure solar’s growth is sustainable through changing incentives and for many years to come.

Jim Spano is the Co-Founder and Head of Originations at RadiantREIT, and Managing Partner of Spano Partners Holdings, LLC.

GE steps up offshore wind operations in China

GE Renewable Energy has taken a major step to cement its offshore wind operations in China.

The company has announced that it will open a new offshore wind factory in the Chinese province of Guangdong and also establish a new operation and development centre in the city of Guangzhou.

GE Renewable Energy’s offshore wind chief executive John Lavelle said that China “is poised to become one of the largest offshore wind markets in the world” and added that the new factory and operation centre “will put us in a better position to meet our customer’s demands in this fast-growing industry, while contributing to meet China’s growing offshore wind ambitions”.

Construction on the factory is due to start at the end of this year, with completion targeted for early 2021 and offshore wind turbine assembly production kicking off later that year when it will make GE’s Haliade-X 12 MW turbine.

The factory will be part of an established offshore wind industrial park in Jieyang which has been step up to develop an windpower business cluster.

Lavelle said that according to Guangdong’s Offshore Development Master Plan, “66 GW will come from the Guangdong region alone towards 2030”.

And Rachel Duan, president of GE’s Global Growth Markets division, said: “As one of China’s strategic offshore wind development centers and a key growth region for GE in China, Guangdong is an ideal place to develop our offshore wind business.

She said that GE’s investments in Guangdong “will bring together advanced manufacturing, operations and development, services and digital applications, together with relevant suppliers, to form an offshore wind business ecosystem that closely and effectively serves the needs of customers in China and the rest of Asia, while pushing forward China’s clean energy ambitions”.

Meanwhile, the new Operation and Development Centre in Guangzhou will carry out R&D work and will also be the regional sales and project management base for GE Renewable Energy’s offshore wind business.

GE Renewable Energy wins order for 138 MW windfarm in Turkey

A 138 MW windfarm in Turkey is to be powered by 27 turbines from GE Renewable Energy.

The Saros windfarm will be operated by Turkish energy company Borusan EnBW Enerji which is investing $190m in the project.

Borusan EnBW Enerji general manager Mehmet Acarla said: “We are determined to realize our vision of harnessing the renewable energy resources of our country and becoming the industry leader in wind energy.”

Borusan EnBW Enerji was founded in 2009 to focus on the Turkish market in partnership with German energy company EnBW Energie Baden Württemberg. It has 495 MW of installed power across 11 renewable power plants in cities throughout Turkey.

The 27 turbines will be GE’s largest model for the onshore market, the Cypress, and its blades will be manufactured in Turkey by GE Renewable Energy subsidiary LM Wind Power.

Manar Al-Moneef of GE Renewable Energy said: “Borusan EnBW Enerji is one of the biggest investors in wind energy in Turkey, and we are thrilled to be working together. GE is very proud to bring additional wind energy and to invest in localization and job creation to contribute to the development of renewable industry in Turkey.”

Voith to provide equipment for new Ritom pumped storage powerhouse

Voith has received an order for the Ritom pumped storage power plant in Switzerland, which began operating in 1920 and will be replaced with a new facility.

Voith will be responsible for design, fabrication, installation and commissioning of the new generating units. The four Pelton turbines with a total capacity of 44 MW that are used in the Ritom pumped storage power plant will be replaced by two 60-MW Pelton turbines and a 60-MW storage pump.

The electricity produced by Ritom is of crucial importance for the operation of the rail network by Swiss Rail (SBB) and for supplying power to the Ticino region, Voith says. The total investment volume for the construction project is about CHF250 million (US$251.7 million). The new plant is scheduled to go into operation in mid-2023.

Ritom SA, a joint venture between SBB and the canton of Ticino, is the plant owner. As the Swiss Federal Office of Energy, the canton of Ticino and Ritom SA want to increase the proportion of hydropower in electricity generation in the next few years, the expansion of the power plant at this location is especially important, Voith says.

The different designs and purposes of the generating units mean that Voith’s engineers have exacting requirements to meet. The first machine unit will supply power for the 16.7 Hz Swiss Rail network and the operation of its trains. The second will feed the electricity it generates into the 50 Hz public grid.

The third unit, with a delivery head of more than 700 m, will pump the water for reservoir management and to provide balancing power (operating reserve) from the Airolo basin to Lake Ritom. In combination with the turbine, the pump can provide the operating reserve for fast grid regulation and stabilization with maximum flexibility. This means the new power plant will provide a feed-in reserve/intake balance of 60 MW for the 50 Hz Swiss grid.

The Voith Group is a global technology company, with a broad portfolio of systems, products, services and digital applications. Voith Hydro is part of the Voith Group and a full-line supplier and trusted partner for equipping hydropower plants.

Hanergy to deliver 400 MW of solar to Democratic Republic of Congo

Chinese solar company Hanergy Thin Film Power Group has won a deal to build the first solar PV plants in the Democratic Republic of Congo.

Hanergy will deliver 400 MW of solar power from several projects under an agreement with the DRC’s Ministry of Energy and Hydraulic Resources of Democratic Republic of Congo.

Under the pact, Hanergy will help the ministry to develop projects covering electricity, water, renewable energy and fuel.

The cooperation is intended to gradually reduce the energy scarcity faced by the mining industry in the provinces of Katanga, Lualaba, Kasaï-Oriental, Kasaï-Central, Kivu and Sankuru by building the solar PV plants.

José Maboya Nzalingo, general secretary of the Ministry of Energy and Hydraulic Resources, said the Hanergy deal “is a step ahead towards meeting DRC’s original target of 65 per cent electrification by 2025, plus new sustainable development goals of universal electricity access by 2030”.

“We’re confident of providing sustainable and stable energy supply in the Democratic Republic of Congo.”

The 400 MW-worth of power stations are expected to solve the problem of energy inadequacy in the DRC and also create around 10,000 jobs, plus provide education to create 100 technology specialists.

Guo Bin, chief executive of Hanergy Uganda, said: “We recognise the potential of renewable energy in Congolese market and have set out a roadmap to accelerate our expansion plan in the country while supporting the need for sustainable and stable energy supply.

He said the 400 MW power plants were “primarily aimed at meeting the on-peak demand of nearby mining companies and reduce local diesel consumption, while reducing carbon emissions substantially”.

Even though the DRC has extensive mineral resources, its national electrification access rate is low – most recent figures put it at just 9 per cent.


Massachusetts incentivizes energy storage systems for commercial property owners

By Matthew S. Cote, Sherin and Lodgen LLP

Commercial property owners with existing energy storage systems, or owners considering implementing an energy storage system, may be able to benefit from a recent order by the Massachusetts Department of Public Utilities (DPU) allowing utility companies to pay customers who agree to rely upon their energy storage systems and dispatch the energy during peak events.

This order makes Massachusetts the first in the nation to incentivize behind-the-meter battery storage by providing new tools and resources for Mass Save (a collaborative of Massachusetts’ natural gas and electric utilities and energy efficiency service providers) to offer pay-for-performance programs to customers of Massachusetts utilities, including Eversource, National Grid, Berkshire Gas, Blackstone Gas Company, Cape Light Compact, Columbia Gas of Massachusetts, Liberty Utilities, and Unitil.

The Basics

While each utility has its own set of standards and criteria, the order allows the utilities to make year-end payments to customers who agree, upon request of the utility, to reduce their use of electricity during peak events (when demand from the electrical grid is forecasted to be high) by drawing energy from their energy storage systems instead of the local electrical grid. While it may vary by utility, in general, utilities will only request that customers dispatch from their energy storage systems on weekdays between the hours of 2-7 p.m. and for no more than three hours at a time. Customers will be notified the day prior to an event and there will be no events scheduled on holidays or when a significant storm is forecasted so that customers who use their energy storage systems to protect against power outages will not be negatively impacted by participating in the program. Mass Save estimates a total of thirty to sixty (30-60) events per summer.

For commercial properties and industrial properties in Massachusetts, this new incentive is primarily offered through the Daily Dispatch program – designed for energy storage systems that can frequently decrease the load on the grid and which have lower costs of controls and special metering, such as battery storage systems or thermal storage systems. The program is technology and vendor agnostic, extending the benefit to those owners with existing storage systems or those who do not want their options limited when implementing a system.

The Incentives

As an example of the available incentives, National Grid and Eversource are currently offering commercial and industrial customers who participate in the Daily Dispatch Program up to $200/kW per event in the summer. At these rates, the incentive would be $20,000 per year for a customer dispatching an average of 100 kW over the summer. Some utilities offer programs during other times of the year, such as National Grid’s Winter Dispatch Program, offering incentives of up to $25/kW per event in the winter. The incentives are paid on performance, with some of the rates locked in for the first five years of the program.

Combining Energy Storage with Solar Energy Systems

Property owners who combine an energy storage system with a solar energy system (sharing a point of common coupling) may also be eligible for the Solar Massachusetts Renewable Target (SMART) energy storage adder, increasing the incentives received from the SMART program. The Department of Energy Resources (DOER) provides a list of energy storage system eligibility requirements (including nominal rated power, nominal useful energy, minimum efficiency, data provision, and operational requirements) and a calculator and table, which can be used to determine the potential value of an energy storage system and which illustrates possible adder values for different system sizes.

The SMART Program is a 1600 MW declining block incentive program for eligible projects interconnected with Eversource, National Grid or Unitil. Those interested can learn more about the SMART Program online here. 

Matthew S. Cote is an associate in Sherin and Lodgen’s Real Estate Department. He represents owners, developers, lenders, investors, and businesses in all aspects of commercial real estate transactions including acquisitions, dispositions, financing and development. Matt can be reached at mscote@sherin.com.

New solar permit software could reduce costs and expand residential markets

Solar Foundation and the Solar Energy Industries Association (SEIA) are joining the National Renewable Energy Laboratory (NREL), several national residential solar companies, and other nonprofit organizations to develop new automated permit software for distributed solar and storage, reducing the cost of solar installations and saving resources for local governments and taxpayers.

NREL was awarded $695,000 in new funding from the U.S. Department of Energy’s Office of Technology Transitions, Technology Commercialization Fund to develop and deploy the Solar Automated Permit Processing (SolarAPP) software platform. The intent is to dramatically reduce the time and cost of the permitting application review and approval process, which in turn will decrease customer cancellation rates and expand solar energy development and solar job growth nationwide.

The partners working with NREL on the SolarAPP software include the California Solar + Storage Association, Institute for Building Technology and Safety (IBTS), Solar Energy Industries Association (SEIA), The Solar Foundation, SunPower, Sunrun, Tesla, and Vivint Solar.

These groups are active participants in the SolarAPP Campaign, a national initiative of The Solar Foundation and SEIA which seeks a fundamental reshaping of solar permitting at the federal, state, and local levels. The goal is to allow most routine rooftop solar projects to receive instantaneous approval and efficient inspections, while enhancing safety and reliability.

“Over the past decade, NREL research has shown that while the cost of PV modules and other hardware has declined, non-hardware ‘soft’ costs remain relatively constant. The SolarAPP software will help address key soft cost challenges by providing both AHJs and installers a standardized online portal to complete and manage permitting and inspection processes,” said Kristen Ardani, Solar Analysis Sub-program Lead at NREL.

“Inefficient permitting can cause frustration and added costs for Americans who just want to go solar,” said Abigail Ross Hopper, President and CEO of the Solar Energy Industries Association. “A streamlined, easy-to-use solution such as SolarAPP can cut down on burdensome applications and connect solar projects to the grid faster. A more reliable permitting experience will help both inspectors and solar customers save time and money without sacrificing safety or quality.”

While the cost of residential solar installations has decreased more than 70% over the last ten years, costs are still much higher in the United States than in other mature markets, largely due to non-hardware “soft costs.” The direct and indirect costs of permitting, inspection, and interconnection, including efforts spent acquiring customers who cancel before a permit is issued, can add about $1 per Watt, or $7,000, to the cost of a typical residential system.

Nationwide, there are over 20,000 authorities having jurisdiction (AHJs) with distinct permitting and inspection requirements, application costs, and approval times. The SolarAPP platform will provide a streamlined process that will increase efficiency and reduce the time and cost of a solar permit, leading in turn to lower cancellation rates.

The platform could also benefit local governments, which face budget constraints and growing workloads to keep up with the accelerated pace of solar energy development. Automated permitting will reduce time spent and increase permit revenues, allowing AHJs to focus their resources on post-installation and inspections.

The SolarAPP platform will build on existing software capabilities at NREL to do the following:

  • Provide a flexible, web-based solar permitting tool for residential systems.
  • Encourage the standardization of permitting processes, while allowing for some flexibility to produce applications that meet the specific requirements of AHJs.
  • Evaluate applications and design plans for safety certification and code compliance.
  • Offer opportunities to incorporate energy storage and expand to other market segments, such as solar thermal and commercial systems.

The SolarAPP initiative builds on previous and existing programs to reduce soft costs, including the SolSmart program that provides designation and no-cost technical assistance for local governments to open up solar markets.

San Diego Airport installs 2 MW/4 MWh storage system to complement existing PV array

Yesterday, ENGIE Storage announced that San Diego International Airport (SAN) installed a 2 MW/4 MWh GridSynergy energy storage system. Paired with the airport’s existing 5.5 MW of solar capacity, the new energy storage system will reduce energy charges during peak demand, which according to ENGIE equate to approximately 40 percent of the airport’s monthly electricity costs. The system is expected to begin operation in early 2020.

The airport will be using GridSynergy’s cloud-based software, which will draw on past and present energy generation and usage data at the airport to calculate optimal charge and discharge cycles for the lithium-ion batteries. GridSynergy will continually learn and adapt to the airport’s energy needs over the next ten years, said ENGIE.

“We are continuously exploring ways to operate more efficiently and reduce the airport’s carbon footprint as energy cost and demand rise,” said Kimberly Becker, SAN’s President/CEO. “This system becomes an important tool in that effort by helping to harness our onsite renewable energy opportunities and maximize their benefits well into the future.”

Solar generation is one of many initiatives included in the airport’s comprehensive strategic energy plan.   Other initiatives include LED lighting retrofits, HVAC efficiency improvements, additional solar and battery storage, and industry leading energy efficient design of new facilities to include the proposed replacement of Terminal 1.

Ontario Power Generation to buy U.S.-based Cube Hydro

Ontario Power Generation (OPG) has entered into an agreement to acquire Cube Hydro, an operator of small and medium-sized hydropower facilities in the northeast and southeast U.S.

OPG says the acquisition provides additional scale to its existing U.S. hydro platform and should generate meaningful operational synergies between the two platforms, including enhanced opportunities for further capital deployment.

“OPG has significant hydroelectric expertise in Ontario and in the U.S., so acquiring this portfolio of diversified, high-quality, long-life assets represents a natural fit for us,” said OPG’s Ken Hartwick, president and chief executive officer. “This is also an opportunity to grow our revenue base over the long term and provide increased returns to our Shareholder, the Province of Ontario.”

This investment will be financed primarily through OPG’s corporate public debt program or other available credit facilities. Goldman Sachs & Co. LLC acted as a financial advisor to OPG on the acquisition. The transaction is subject to standard regulatory approvals. Once the acquisition is finalized, Cube Hydro will operate as part of OPG’s U.S. hydroelectric platform. OPG expanded to the U.S. through its acquisition of Eagle Creek Renewable Energy in November 2018.

Cube Hydro was established in 2014 and operates 19 hydropower facilities, providing 385 MW of in-service capacity at facilities in New York, Pennsylvania, Virginia, West Virginia and North Carolina. Its enterprise value is US$1,123 million, subject to customary working capital and other adjustments on closing.

OPG produces about half of the electricity Ontarians rely on every day, and its clean, safe power costs an average of 40% less than other generators in the province, according to a press release.