Duke Energy’s advancement of battery energy storage technologies in the Carolinas includes $500 million of projects in the company’s 15-year forecast – continuing the company’s industry-leading deployment of the technology.

“Duke Energy is at the forefront of battery energy storage, and our investment could increase as we identify projects that deliver benefits to our customers,” said Rob Caldwell, president, Duke Energy Renewables and Distributed Energy Technology. “Utility-owned and operated projects in North Carolina and South Carolina will include a variety of system benefits that will help improve reliability for our customers and provide significant energy grid support for the region.”

In the company’s recent Integrated Resource Plan (IRP), Duke Energy outlined plans to deploy $500 million in battery storage projects in the Carolinas over the next 15 years – equal to about 300 MW of capacity. Combining battery storage from all utilities, North Carolina has only about 15 MW of battery storage capacity in operation, and far less in South Carolina.

As the grid operator, Duke Energy can maximize the versatility of storage beyond storing and dispatching of energy to include other customer and system benefits such as system balancing and deferral of traditional grid upgrades.

This week, the company filed for a Certificate of Public Convenience and Necessity with the North Carolina Utilities Commission for a solar facility in the Hot Springs community of Madison County as part of a microgrid project.

The Hot Springs Microgrid project will consist of a 2-MWac solar facility and a 4-MW lithium-based battery storage facility. The microgrid will provide a safe, cost-effective and reliable grid solution for serving the Hot Springs area, and provide energy and grid support to all customers. The project will defer ongoing maintenance of an existing distribution power line that serves the remote town.

As renewable penetration grows, the need for energy storage grows as well. However, existing storage technologies may not be able to meet that need.

A Department of Energy (DOE) grant program aims to address that problem by trading efficiency for low cost.

Existing storage technologies fall short in terms of duration. Lithium-ion batteries, which have captured about 90% of the energy storage market, can economically run for about four hours. Pumped hydro storage, which accounts for the most energy storage today in terms of capacity, can generate power by releasing water from storage reservoirs for up to 20 hours under certain conditions.

But as renewable energy penetration reaches and surpasses 50%, the need for even longer durations will grow.

The sunny forecast for storage demand

The need for longer durations is particularly applicable to areas where solar power dominates the resource mix.

In a future where 70% of power is generated by solar panels, it is easy to imagine a scenario where a couple of cloudy days in a row could create a gap in meeting customer demand, Michael Jacobs, senior energy analyst at the Union of Concerned Scientists, told Utility Dive.

Filling that gap is the aim of a program at the DOE that is providing funding for technologies that can extend energy storage durations to up to 100 hours.

Last month, the DOE’s Advanced Research Projects Agency-Energy (ARPA-E) awarded just over $28 million to 10 projects that aim to push the limits of energy storage duration. ARPA-E’s Duration Addition to electricitY Storage (DAYS) program aims to push the duration of energy storage systems out to 100 hours.

One hundred hours, just a little more than four days, is an exponential leap from current durations but the role of ARPA-E is to focus on early stage technologies that are not yet commercial or quite ready for the private sector.

CPS Energy recently broke ground on their first solar energy and battery storage project in Texas.

The greater San Antonio’s natural gas and electric provider says the project is a culmination of three years of work, which included a partnership with Southwest Research Institute (SwRI). For theirpart, SwRI is providing nearly 50 acres of land on which the solar facility and battery storage system will be constructed. SwRI aims to gain insight into the efficiencies of both solar production and battery energy storage. Sharing that information with CPS Energy will provide the utility with vital information that someday may lead to similar projects on a larger scale as they continue to execute their “Flexible Path,” San Antonio’s new energy resources plan.

The $16.3 million project, which will be constructed by RES Americas,was approved earlier this year by CPS Energy’s Board of Trustees. The site will consist of a 5 megawatt (MW) solar power facility and a 10 MW battery storage system located at 9800 W. Commerce in San Antonio.

In 2016, CPS Energy applied for and was awarded a New TechnologyImplementation Grant (NTIG) for $3 million from the Texas Commission on Environmental Quality (TCEQ) to fund part of the project cost. The primary objective of the NTIG program is to offset the cost of the implementation of existing technologies that reduce the emission of pollutants from facilities and other stationary sources which may include electricity storage projects in Texas.

The goals of the NTIG are to:

• Improve the quality of air in Texas in order to meet federal standards established under the Federal Clean Air Act (42 U.S.C. Section 7407).
• Facilitate the implementation of new technologies to reduce emissions from facilities and other stationary sources in the state.
• Adequately fund the implementation of new technologies that will make the state a leader in new technologies that can solve the state’s environmental challenges while creating new business and industry in the state.

CPS Energy says the project will allow for solar shifting. This means energy is captured when solar production is at its peak, generally between noon and 2 p.m., can be stored in onsite batteries and dispatched when energy demand is at its peak in San Antonio, between 3 and 7 p.m.

CPS Energy received and evaluated 22 proposals for an engineering, procurement and construction contractor for this project.

Additionally, there are plans to utilize an existing building on the site to develop an educational facility for students and the general public to tour and learn about innovative technologies being used by the utility.

The site is expected to be online in the summer of 2019.

We know energy storage is coming. The question is: How much and how fast? Tesla showed us that they’d rather build cars versus energy storage installations, and that makes sense since more than 90% of their revenue is from cars. And Bloomberg recently reminded us that the whole of the industry is in a situation of greater demand than supply. Nonetheless, the potential is there and the manufacturing capacity is growing immensely.

In a report commissioned by the Public Utilities Commission of Nevada and Nevada Governor’s Office of Energy, the Brattle Group found that over the next year and a half 175 MW / 700 megawatt-hours (MWh) of energy storage could be deployed while saving money for ratepayers. The Economic Potential for Energy Storage in Nevada (92 page PDF), also found that by 2030 – depending on how pricing moves – 700 to 1,000 MW of energy storage can be effectively deployed. Additionally volume could be found behind-the-meter, as deployments could range from 30 to 40 MW / 120 to 160 MWh by 2030.

These numbers are particularly interesting in light of Warren Buffet’s NV Energy recently signing contracts including 100 MW / 400 MWh of energy storage.

The report made its judgments on value of the energy storage based on power grid benefits (noted on the right of the chart above). What was not included in the chart below were the societal emissions-related impacts of up to $10.6 million per year in 2020, and $27 million a year in 2030, as these items aren’t reflected in electricity bills.

The report suggests there is also a chance to expand the volumes deployed by large amounts with ever so slight adjustments in how we recognize the value provided by energy storage or through declines in the cost of deploying energy storage. The report also notes that if a regional market develops, beyond 1,000 MW is a possibility.

A Montana utility case pending before federal regulators could set a precedent for how energy storage facilities paired with renewable generation will be treated under the Public Utility Regulatory Policies Act (PURPA), a 1978 law intended to increase competition in power generation.

This summer, Northwestern Energy asked the Federal Energy Regulatory Commission (FERC) to revoke qualifying facility (QF) status under PURPA for four wind-plus-battery facilities a developer is trying to site in its Montana service area. The federal law compels utilities to purchase power from QFs.

Developer Caithness Beaver Creek has QF status for four planned 80 MW wind facilities paired with battery storage. Northwestern argues their status should be revoked because the addition of batteries violates generation sizing requirements under PURPA.

The case comes in the middle of FERC’s ongoing review of its implementation of PURPA and would be the first ruling directly addressing paired storage facilities under the law. Utility trade group Edison Electric Institute asked FERC to put the case on hold until the commission completes that review, but one federal regulator said it is still in its early stages.

Northwestern v. Caithness

FERC today has little experience relating energy storage to PURPA. In the 1990 case Luz Development and Finance Corp., FERC found that a standalone storage project could receive QF status if it is charged with renewable energy, but the agency has not yet considered how to treat paired storage projects, like the Beaver Creek facilities.

Northwestern filed with FERC in late August, arguing the Beaver Creek batteries should be considered separate facilities from the wind turbines. If not, the utility said the combined facilities would violate PURPA’s 80 MW capacity limit.

“Integrating battery storage facilities with a wind farm in these circumstances is simply a combination of power production facilities,” the utility wrote. “There is no precedent for the proposition that a battery storage facility’s capacity can be deemed to be zero simply because the battery may receive charging energy from another QF or because the battery storage facility is to be ‘integrated’ with an existing QF.”

Global energy technology giant Siemens plans to acquire Massachusetts-based Russelectric, a move likely to strengthen Siemens position in state’s increasingly fertile microgrid market.

Russelectric manufactures power control systems and made a splash in the microgrid arena last year with the opening of a sophisticated microgrid demonstration at its Hingham, Massachusetts headquarters.

The Russelectric microgrid not only powers the facility, but also serves as a learning ground for potential customers who want to see a microgrid in action. Such projects are viewed as valuable within an industry that is still young and needs to prove itself to customers

The acquisition of Russelectric by Siemens means that two of the major players in microgrids — Siemens and Schneider Electric — will have corporate demonstration projects in Massachusetts.  Schneider Electric, a prime competitor to Siemens, operates  a demonstration microgrid at its Andover, Massachusetts headquarters.

Like most of the Northeast, Massachusetts is viewed as a prime market and a launching ground for the North American industry because of severe hurricanes and winter storms that cause power outages. (The other launching ground for microgrids is California, where the market has been driven by environmental goals and grid vulnerability to earthquakes and wildfires.)

State policy swings in favor of microgrids in Massachusetts with state grant programs through the Massachusetts Clean Energy Center and strong energy storage, renewable energy and climate goals. The city of Boston also has laid out microgrid plans, with a much-watched project at the Raymond L. Flynn Marine Park Project.

We know energy storage is coming. The question is: How much and how fast? Tesla showed us that they’d rather build cars versus energy storage installations, and that makes sense since more than 90% of their revenue is from cars. And Bloomberg recently reminded us that the whole of the industry is in a situation of greater demand than supply. Nonetheless, the potential is there and the manufacturing capacity is growing immensely.

In a report commissioned by the Public Utilities Commission of Nevada and Nevada Governor’s Office of Energy, the Brattle Group found that over the next year and a half 175 MW / 700 megawatt-hours (MWh) of energy storage could be deployed while saving money for ratepayers. The Economic Potential for Energy Storage in Nevada (92 page PDF), also found that by 2030 – depending on how pricing moves – 700 to 1,000 MW of energy storage can be effectively deployed. As part of this, behind-the-meter deployments could range from 30 to 40 MW / 120 to 160 MWh by 2030.

These numbers are particularly interesting in light of Warren Buffet’s NV Energy recently signing contracts including 100 MW / 400 MWh of energy storage.

The report made its judgments on value of the energy storage based on power grid benefits (noted on the right of the chart above). What was not included in the chart below were the societal emissions-related impacts of up to $10.6 million per year in 2020, and $27 million a year in 2030, as these items aren’t reflected in electricity bills.

The report suggests there is also a chance to expand the volumes deployed by large amounts with ever so slight adjustments in how we recognize the value provided by energy storage or through declines in the cost of deploying energy storage. The report also notes that if a regional market develops, beyond 1,000 MW is a possibility.

Renewables developers eyeing Saudi Arabia remain wary of the market following the news that the world’s biggest solar project has been canceled.

The $200 billion, 200-gigawatt solar plant planned by SoftBank and the Saudi Public Investment Fund had raised skepticism among developers when it was announced in March, partly because of technical concerns over how it might be integrated into the grid.

The main worry, though, was that the megaproject appeared to have been approved independently of plans for an orderly ramp-up of solar through a tender program managed by the Saudi Renewable Energy Project Development Office (REPDO).

Soon after the SoftBank agreement was unveiled, it emerged that top officials in the kingdom had been excluded from negotiations, adding further uncertainty.

Given the haphazard way in which the deal was brokered — and the fact that the Saudi state and SoftBank had both previously announced plans for massive solar investments that had been canceled — last week’s news came as no surprise.

“Precedent would suggest that grand solar plans from SoftBank or the Saudi state come with a gap between promises and reality,” said Benjamin Attia, global solar analyst with Wood Mackenzie Power & Renewables. “This is no exception.”

He said the project never got beyond an initial feasibility study.

According to The Wall Street Journal, the announcement of the freeze was greeted with relief by Saudi energy officials. “Everyone is just hoping this whole idea would just die,” one said.

Although the SoftBank project was widely viewed as being doomed from the start, the cancellation is a further blow to the Saudi solar market.

Investment management firm Gresham House is to float an energy storage fund on the London Stock Exchange next month, with an aim to raise £200 million (US$260 million) to fund 262MW of energy storage projects over the next year.

Gresham House Energy Storage Fund has already secured a seed portfolio of 70MW across five projects it has developed alongside its partner Noriker, ranging from 7MW up to 20MW. Gresham House also took over Hazel Capital in 2017, a renewables investment fund company which delivered the 15MW Lockleaze battery project, at the time one of Britain’s biggest projects of that type.

Gresham House New Energy, which will manage the fund, says it also has exclusivity over 132MW of shovel-ready sites across the UK, with a further 80MW in the advanced stages of negotiations.

Finally, more than 50MW of storage projects are also within sight of the management team, which has already invested more than £30 million alongside institutional investors, all of which is expected to be acted on over the next year.

Gresham House hopes to have completed the initial public offering (IPO) and admission to the LSE early next month, with the fund offering yields of 7% to investors.

Rupert Robinson, managing director of Gresham House Asset Management, said: “We are excited to bring this opportunity to invest in energy storage systems to institutional and high net worth investors.

“What will set the Fund apart is the proven expertise of the management team in this highly specialist sector and the cornerstone investment of more than £30 million, from the management team and institutional investors.

“We are confident that we can deploy up to £200 million in a tangible pipeline within 12 months of IPO.”

​It will be the second listed fund dedicated to energy storage after Gore Street Energy Storage Fund was announced in March, targeting £100 million and also promising 7% returns.

However the fund underwhelmed in May having only raised £30 million, with half of this coming from external investors.