2017 saw 200MW of new battery storage projects coming online in Britain. As the market develops, various business models are emerging, however project sponsors face challenges in developing these models against a backdrop of a changing regulatory landscape that did not anticipate the emergence of battery storage on the system.

According to Cornwall Insight the business models for battery storage fall into three categories:

  • standalone (grid connected);
  • co-located (either with renewables or fuelled generators); and
  • behind the meter for a major consumer.

battery storage

Most capacity has been developed on a standalone basis

Standalone batteries tend to focus on providing grid services, particularly frequency control – 201 MW of batteries are providing enhanced frequency response under 4-year agreements, and a further 100 MW is contracted to provide firm frequency response where the longest contracts have 30-month tenors.

National Grid is currently revising its balancing services product portfolio – these changes will impact the business models of storage projects, but should overall be positive as National Grid’s tender process become more transparent.

Both the frequency support revenue streams can be “stacked” with others, which improves the economics. New battery projects can bid for capacity contracts, which offer revenue certainty for 15-years, however, prior to the last auction de-rating factors we reduced from 96% to 36% of capacity, significantly reducing available income.  Embedded benefits can provide further revenue streams, however these have also recently been reduced through the triad review (although this is currently the subject of a legal challenge).

The provision of frequency support is increasingly competitive, and National Grid estimates that its requirement will only be around 2 GW, meaning there could be a large number of providers chasing a limited amount of capacity.

Batteries can also earn income through arbitraging the wholesale markets and participating in the Balancing Mechanism – these are significantly deeper markets then frequency response, and may prove more attractive in the longer term. As the amount of intermittent generation on the system increases, volatility is also likely to increase, so batteries will be able to participate in the increase in balancing actions required by the system operator.

Co-location offers greater investor protection from revenue diversification

Capturing market arbitrage could be more efficient if the battery co-located with a source of renewable generation: the battery can shift output of the generation plant, storing it until market prices are higher, thereby maximising the value of the output into the wholesale market. Alternatively, the battery could provide services to National Grid, as in the standalone option; or it could do a combination of the two strategies although not at the same time.

Co-located batteries could also bid for capacity contracts and seek to capture embedded benefits. In addition, such projects benefit from cost efficiencies both for the grid connection and O&M.

In his review of energy markets, Dieter Helm proposed that intermittent generators should be responsible for the system costs of the intermittency they produce – co-location with a battery would reduce the impact of a plant’s intermittency on the grid and therefore reduce the impact of any such costs (were they to be introduced) on the project.

Ofgem issued draft guidance on the treatment of batteries co-located with renewable generation for the purposes of the Renewables Obligation (“RO”) and Feed-in-Tariff (“FiT”) schemes. Installation of co-located storage represents a change to the generating station or installation that needs to be notified to Ofgem, or, for smaller-scale FiT installations, the relevant FiT licensee. Ofgem outlined four overarching principles that operators of RO generating stations or owners of FIT installations should consider when thinking about co-locating storage with generation accredited under the schemes:

  1. Co-located storage does not change generators’ obligations to comply with the RO and FIT scheme requirements.
  2. Generators can only receive support for eligible renewable electricity generated by an accredited RO generating station or FIT installation.
  3. Installing storage will not alter the Total Installed Capacity of the RO generating station or FIT installation.
  4. The schemes’ eligibility requirements are not changed by the type of storage technology.

The draft guidance highlights that generators will need to apply to amend their accreditation and provide additional evidence and information (such as single line diagrams) to satisfy the regulator that the project is still eligible for support. Each project will be considered on a case-by-case basis, and Ofgem cannot provide any assurances to developers of proposed schemes prior to installation, meaning that developers bear the risk that they will not receive the levels of subsidy they expected.

In general, depending on the configuration, the amount of support received by a project may decrease; and the same generating capacity cannot necessarily receive support under the RO and participate in the Capacity Market, although there may be some configurations in which this is possible.

Final guidance is expected in the next few months.

Behind-the-meter is a growth area

Behind-the-meter storage is gaining traction in the UK, with low 10s of megawatts being commissioned alongside industrial and commercial sites in the past year. The business case centres on reducing electricity costs for major consumers by reducing their reliance on the grid at expensive peak times, particularly 4pm-7pm on winter weekdays where consumption drives a number of other, non-commodity, costs.

These avoided costs include red rates of distribution use of system (“DUoS”) charge, transmission network use of system (“TNUoS”) costs and the Capacity Market supplier charge, all of which have been increasing in recent years.

Although there can be significant benefits to such schemes, the complex, multi-party nature of the projects with consumers, battery owners and aggregators all being part of the schemes leads to a high degree of contractual complexity, generally in an area outside the consumer’s core area of expertise.

Regulatory change creates uncertainties for business models

All of the above models face risks which can affect the revenue and cost profiles. Regulatory change is creating uncertainly, with Ofgem’s Targeted Charging Review examining the determination of system charges, with and proposes further work to consider how behind-the-meter generation (which could include battery storage) should be captured in the charging frameworks. This would make sense, to the extent that sites rely on a grid connection for back-up…this is an option that must be paid for in order to maintain equity among users of the system.

battery storage

A number of other regulatory and market changes may impact the economics of storage projects:

The challenges and risks facing storage projects were recently brought into focus with the poor performance of the sector in the latest T-4 Capacity Action in February, with storage only securing 1.7% of the available capacity – a drop of 80% on previous auctions. This was due to a decision by the Government to reduce the de-rated capacity of shorter-duration systems.

Interest from investors as the technology matures…

Despite these uncertainties, there are signs of growing investor interest in the sector. A report issued by ratings agency Moody’s Investors Service last month concluded that battery storage is increasingly emerging as a project finance opportunity, although the technology “still presents risks and challenges that could affect the development of battery storage on a non-recourse, project-finance basis.”

“While the developing technology presents some unique challenges, we view the financing approach of a battery storage project to be broadly akin to many of the risks associated with financing a conventional power project,”
– Rick Donner, vice president and senior credit officer at Moody’s

As with power projects, battery storage benefitting from contracted revenues would be more creditworthy than merchant projects relying on stacked revenue streams.

The UK’s first energy storage investment fund, Gore Street Energy Storage Fund (“GSF”) has announced that it plans to raise £100 million in a stock market floatation this month, to finance a network of lithium batteries. The closed-end fund believes it can generate multiple, long-term contractual revenues from providing grid services or back-up energy systems for businesses. The company believes it can achieve total annual returns before costs of 10-12%, without the use of debt.

The initial public offering (“IPO”) of shares is aimed at income investors, with the company targeting a 3% quarterly dividend yield in the first year, rising to 7% the following year. This would exceed the current 6% average yield from existing listed renewables funds such as Bluefield, Foresight and Greencoat.

The fund has two Japanese partners: NEC Energy Solutions, a leading battery supplier, and Nippon Koei, an engineer, which have each committed to invest £14 million if a minimum of £75 million is raised from professional and private investors. The management of Gore Street Capital will invest a further £2 million.

An £11 million seed portfolio of three projects in North Yorkshire, Swansea and Essex using batteries from NEC and Tesla has been created, with a further 60 projects in the pipeline should the IPO succeed. The revenues from these projects will not depend on government subsidies, reducing political risk.

GSC will charge an annual management fee of 1% of net assets plus a performance fee of 10% of returns above 7% a year, capped at 0.5% of net assets. It hopes to keep overall ongoing charges below 2% a year and the 100p shares will start with a minimum net asset value of 98p.

A prospectus for the offer is available on the company’s website.

….while companies and municipalities develop new storage projects

French energy company EDF announced recently that it plans to invest US$8 billion in developing its battery storage capabilities over the next 20 years. Its aims to be a leader in the European market, with 10 GW new projects planned by 2035 under its Electricity Storage Plan which will see a doubling of its investments in storage R&D, and building on its existing 5 GW storage portfolio which is primarily hydro-based. EDF also holds an enhanced frequency response (“EFR”) contract with National Grid, with a 49 MW battery at West Burton in the UK.

The company plans to focus on the residential sector in France, and Europe more broadly, with a range of self-consumption services incorporating batteries. Projects will also be explored in Africa, where there are plans for a portfolio of 1.2 million off-grid customers by 2035 through local partnerships. In the near term, EDF intends to roll out its existing solar plus storage offer to customers in Ghana following a successful launch in Ivory Coast where it has 15,000 customers.

At the same time, Swindon Council has received permission from its planning department to develop a 50 MW / 50 MWh battery storage scheme which will be one of the largest in the country to date. Council-owned Public Power Solutions is seeking developers to take on funding and construction of the project, which it claims can achieve grid connection at a nearby substation at “very low cost”.

“Local authorities are in a unique position to benefit from the growing demand for electricity storage, with diverse property portfolios and high energy consumption. We’re making it work at home here in Swindon but this project could be replicated in many other parts of the country, helping generate an income for the cash-strapped public sector,”
– Steve Cains, Public Power Solutions

The project is designed to have a 30-year lifespan, and will provide a long-term land rental income for the Council, should it manage to find a developer. Other municipalities may follow suit with similar schemes.

The battery storage market is beginning to take off, however, a dynamic regulatory landscape presents challenges, and it will be some time before clear and sustainable models emerge. 

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