Financing battery storage+renewable energy

This article was original published in Project Finance International in December 2017.

Renewable energy has moved to the mainstream. The tumbling costs of renewables, from solar photovoltaic (PV) to offshore wind, has grabbed headlines globally in the last two years. Increased penetrations of renewable power are expected in the coming decades; a recent report¹ by the International Renewable Energy Agency (IRENA) found that over 80% of  the world’s electricity could derive from renewable sources by 2050, with solar PV and wind power accounting for 52% of total electricity generation. However, at higher penetrations, these variable renewable power sources make balancing the system more complex and so will require a transformation in our power systems.  Electricity system operators are increasingly considering how procure flexible capacity to integrate high penetration of intermittent, often distributed, renewable energy sources.

Storage is an essential element in this energy transition. Recent cost reductions in storage technologies have meant that storage is on the cusp becoming of competitive. IRENA predicts further cost reductions of 48% to 64% between 2016 and 2030, with total electricity storage predicted to grow from approximately 4.67 TWh in 2017 to between 6.62 TWh and 7.82 TWh by 2030; an increase of 42-68% from 2017. Batteries in particular are gaining market-share. In 2016, lithium-ion batteries made up almost half of all new battery deployments, whilst advanced lead-acid and sodium-sulphur batteries also held large market shares.

Battery storage is readily scalable and can respond in milliseconds. It can be located either ‘behind the meter’, as part of a hybrid site smoothing generation output or providing back-up power, or ‘in front of the meter’, providing electricity grid services.

Behind the meter, batteries may be combined with renewables or fossil fuelled plants in order to reduce potential grid integration challenges, reduce grid connection capacity requirements, and, for variable generation, reduce balancing costs and allow access to revenue from the provision of grid services. Storage may facilitate an energy intensive industrial user’s participation in the demand-side reduction market or provide important back-up power for critical processes. Off-grid industrial users may also find battery storage an interesting proposition, lowering power costs and reducing reliance on diesel supplies. For example, the DeGrussa Copper-Gold mine project in Western Australia is powered by a 10.6 MW solar PV farm and is coupled with a 6 MW battery facility to power the off-grid mine². The solar+storage system has been combined with a 19 MW diesel generator, supplying the whole mine and its processing operation with power during daylight hours³. The DeGrussa system is expected to reduce the site’s reliance on diesel by approximately 20%.

In front of the meter, stand-alone battery storage systems connected to large power grids provide an array of grid services including frequency response and firm capacity in times of system stress. For example, Renewable Energy Systems has 90 MW of standalone batteries in operation and more than 55 MW under construction, including two 55 MW projects in the UK that provide enhanced frequency response to the utility grid.  AES Energy Storage is also a market leader for commercial energy storage solutions, operating across four continents. To date, AES has a total of 476 MW of interconnected energy storage, which is equivalent to 952 MW of flexible resource, in operation, construction or late stage development.

Battery systems may also be combined with fossil fuelled or renewable generation in non-interconnected grids or island grids. These mini-grids have historically been developed by the public sector (governments, state-owned utilities, NGOs or community groups), however, the scale of the challenge to electrify remote communities means that private sector funding will increasingly be required. Some of the Hawaiian islands, for example, require renewable generators to couple any new generating facilities with batteries to help manage the local grid. In emerging markets, small, renewable, off-grid solutions with battery storage are a sustainable alternative to the traditional centralised generation model. With the support of export credit agencies and development banks, investment is increasing They are also comparatively easier to finance  given lower capital costs, shorter construction periods and fewer risks and complications involved.

As energy storage gains importance in the global electricity mix, so the question of how to finance energy storage installations increases in importance.

At any scale, financing storage assets will require getting comfortable with technology risk. Mitigants include creditworthy suppliers standing behind extended contractual warranties; in the USA a two- to three-year warranty is considered standard, but developers can pay for a 10-year warranty, which is considered an extended warranty. It is rapidly becoming the market standard. A robust operation and maintenance agreement from a reputable provider will also be important, and we are seeing firms such as AES Energy Storage, Stem,  Renewable Energy Systems (RES), Advanced Microgrid Solutions (AMS)  beginning to specialise in storage asset management despite the nascent nature of the industry. Robust technical advice will of course be important to the lending decision, including in relation to operating conditions which can have a significant impact on performance and the battery’s depth of charge (DoD), which refers to the total capacity of the battery and relates to the speed of degradation of the battery.

The revenue streams for the storage project will depend on the relevant electricity market, technology, project size and whether the project is applied ‘behind’ the meter or connected to the public grid. Storage may be able to capture value in a number of different ways such as the provision of grid services (frequency response, capacity market revenues, demand-side response), market price arbitrage, or the smoothing of generation output and avoidance of imbalance costs. Investors will want the flexibility to stack revenues, perhaps relying on different income sources at different times of day or year, whilst financiers will wish to see a longer-term base contracted revenue-stream to under-pin the debt repayment.

In general, regulation is still playing catch-up when it comes to integration of storage into the existing regulatory framework. Regulations and (the lack of) market rules create uncertainty, which places additional burden on early projects. For example, in the UK the regulator is taking steps to change rules which result in taxes being levied on power inputs to charge a battery and also charged on the power supplied by the battery to the end consumer, increasing the costs of power from the storage unit. The US Federal Energy Regulatory Commission has been wrestling with whether to classify storage as a generating asset, transmission asset or a hybrid of the two. The cost of transmission assets can be recovered from all transmission customers in the rates they are charged by the grid.

Utility-scale storage may be financed alone or, as part of a portfolio that includes other assets. The latter approach allows lenders to diversify risk across the portfolio of projects, with revenues from more established technologies cross-collateralising the obligations of the storage provider. Norton Rose Fulbright recently acted on the Southland repowering project consisting of 1,284 MW of efficient combined cycle natural gas generation and 110 MW of advanced battery-based energy storage. The gas-fired capacity is expected to enter commercial operation in 2020 and the energy storage capacity in 2021. This capacity will replace AES' 3.9 GW of existing gas-fired capacity currently slated to be retired at the end of 2020. Interestingly, the project used a tolling structure: under 20-year power purchase agreements auctioned off Southern California Edison (SCE), one hundred percent of the 1,384 MW capacity is to be sold to SCE in exchange for a fixed monthly capacity fee that covers fixed operating cost, debt service and return on capital. In addition, SCE will reimburse variable costs and provide the natural gas and charging electricity.

Increasingly, batteries are being combined ‘behind the meter’ with generation plant such as solar PV, onshore wind and offshore wind. For intermittent renewable generation, the addition of storage may allow variable output to be smoothed, imbalance costs to be reduced and new revenue sources to be accessed. Whilst we focus on renewable applications below, batteries may be combined on the same site as other types of generation such as gas or smaller diesel-fired plant and many of the same considerations apply.

Ownership structures need to be determined upfront. The battery array may be owned by the same special purpose vehicle as the generation project, or may be established under its own vehicle with separate contractual arrangements and its own independent revenue sources (albeit purchasing power from the renewable generator). However, even a discrete storage project on the same site will necessarily be co-dependent and may share land rights, permits, grid connection arrangements and meters with the generation project. If grid export rights are limited, the renewable project and storage unit may be unable to export simultaneously and would need to agree upfront how any export conflict is resolved. Cooperation on operation and maintenance will also be required, including the careful scheduling of outages (both in terms of timing and duration).

Norton Rose Fulbright recently advised on the Lakeland solar PV and storage project which is an example of this hybrid approach. The Lakeland project is located at the fringe of Ergon’s grid in Northern Queensland. It will have an installed capacity of 10.8MW combined with a 5.3MWh battery storage system.  The project will receive both a funding grant from the Australian Renewable Energy Agency and debt financing from NordLB. The solar and battery assets are owned by the same vehicle, which reduced the number of interfaces and ensured the debt financing process went smoothly. One of the features of the project is a Knowledge Sharing Plan (KSP) which involves all the key stakeholders. The outputs of the KSP will be made public with the intention of sharing lessons learned and heling the market develop new business models for solar+storage projects.

Ultimately the revenue proposition will be a key consideration and the interface of the storage revenues with those of the renewable generating asset will need to be considered early-on. A key question is how the power will be marketed. Will the storage system sell its power together with the renewable generating unit or will the storage unit buy power at arm’s length from the renewable generator and the grid, and sell power on its own account?

Depending on the structure of any applicable renewable support regime, regulators will need to determine, for the purposes of measuring renewable power generated, whether to meter electricity generated before charging the storage unit or whether to measure net output at the site boundary (netting off any imports required to charge the battery when the renewable plant is not generating). The latter approach means that the generation project may lose entitlement to any green benefits in respect of power losses in charging and discharging the battery. In Britain for example, the regulator Ofgem has nevertheless confirmed that renewables obligation certificates (green certificates awarded to some renewable power projects) may be claimed on all the renewable electricity generated, including any that is used to charge the storage devices.

The co-location of storage is also an interesting proposition for owners of existing, operational renewable generation assets who may be considering retrofitting storage to an existing site. Where financing is already in place, a review of the terms of the existing finance documentation and due diligence will be needed. Existing lenders will wish to confirm that any change to the existing project and/or its contractual arrangements would not have a negative impact on the project or its revenues. As a result, the impact on important aspects of the project such as its power purchase arrangements, entitlement under any renewable energy support regime, grid connection agreements or existing environmental permits will need early consideration.

The co-location of storage + generation is still in its infancy, with business models under development and financing terms yet to crystalise into standard market practices. However, as the costs of renewables and batteries fall and the costs of balancing rise, so the opportunities for hybrid sites will grow.