Energy and Climate ChangeSupplementary written evidence submitted by Community Energy Scotland

Q1 Chair: As I am sure everybody is aware, we are looking at essentially medium-sized energy projects, but I think we all agree that that covers a large number of different projects. Could you perhaps tease out a little the distinction that you see between general medium-sized energy projects, community-owned projects, local energy projects, distributed energy projects? What do you see as the main differences between those particular categories and in the overall heading of smaller projects?

The oral and written evidence submitted to the committee outlined a wide range of interpretations of “local energy”, from projects substantially owned by local community organisations, to projects owned by local SME’s and rural businesses.

DECC has produced a definition of “community organisation” for the purposes of the benefits being targeted at community energy projects under the Feed in Tariff regime. The definition is contained in article 11 of the FiT Order 2012 and essentially limits eligibility to cooperatives, community benefit societies (“bencoms”), and community interest companies (CIC’s).

If, as seems likely, the 5MW ceiling on FiT projects is increased to provide community energy schemes an alternative to CfD’s, this is the definition that will be used.

There are a number of difficulties with this definition:

(i)As of January 2013 over 80% of the community energy projects under development in Wales, and over 90% of the projects in Scotland, would be excluded by this definition.

This is because they are being developed using the “charity and trading subsidiary” model, whereby the parent community organisation is a charity, and the project vehicle is a wholly owned trading subsidiary.

This model has evolved to serve the needs of non-profit distributing, wholly locally owned projects in particular, and has been used by 100% of the large scale community energy projects developed in Scotland to date (over 25MW).

Under the DECC definition, neither charities nor trading subsidiaries which are ordinary companies are eligible. In its response to the FiT’s review consultation (phase 2b), DECC assumed that any community organisation would be able to convert or set up a project vehicle that would use one of the eligible forms.

However there are a number of commercial, legal and regulatory barriers that will make this very difficult in practice and create an additional and entirely unnecessary hurdle for much of the sector. We have raised these issues a number of times with DECC and requested that an amendment is made to the FiT Order but to date DECC has refused to make the necessary changes.

We have commissioned a legal opinion on the consistency of the FiT Order definition, and also gathered evidence on the potential impact on the sector which we would be happy to share with the committee.

(ii)We are also concerned that the FiT Order definition depends entirely on the legal form of the organisation, and not its activities or membership.

While there are statutory regulators for these bodies (FCA, Companies House, CIC Regulator), their priorities are not necessarily the same as the government’s reasons for promoting community ownership of renewable energy.

Specifically there is no requirement for a minimum level of local ownership, or for the organisation to be open membership within the local area.

This means that it is entirely possible to establish a FiT eligible community energy project that is not open to local people and delivers no additional financial benefit to the local community compared to a conventional, privately owned development.

There is a risk that should such projects go ahead, they will damage the public perception of community energy, and undermine the drive to involve local people directly in the benefits arising from renewable energy projects.

It is clearly possible to create additional safeguards through more detailed legislation, as the Scottish Government has done through the Land Reform (Scotland) Act 2003, which gave certain forms of community organisation specific powers for the purchase of land.

Our view is that DECC should consult further on how “local” and “open membership” should be defined and consider further amendments to the community organisation definition contained in the FiT Order.

In the meantime they should also closely examine the rules and articles of association of successful community FiT applicants, to build up an evidence base of whether the projects will indeed increase benefits to local communities.

Q41 Sir Robert Smith: The other big challenge is a lot of our renewable resource is in parts of the country that have not traditionally had great connections to the grid. Are there any imaginative solutions?

The committee noted the importance of timely and affordable grid connections to enable local energy projects to come forward. However from the point of view of Scotland and the South West of England, DECC are demonstrating a lack of urgency in tackling the issues local developers are currently facing.

As a result of transmission level constraints, the majority of the north and west of Scotland, and large areas of the south, are currently closed for development until in some cases 2020. Distribution level constraints are also widely spread and unfortunately penetrate areas not subject to transmission constraints, compounding the problem.

This represents 100’s of MW of renewable energy capacity under development which won’t be able to connect for over 5 years. In the short term the only solution is innovation in network management and commercial arrangements to squeeze some additional capacity; however the reality is that the existing infrastructure was not designed to maximise the capture of renewable energy from highly productive but relatively remote sites.

In order to ensure that the capacity is available for the next wave of renewable energy development, the investment has to take place now. The example of the Beauly Denny upgrade amply demonstrates the long lead times of major infrastructure upgrades, which has led to the existing grid capacity shortfall.

We are concerned that at a fundamental level, DECC and Ofgem do not recognise the need for strategic grid investment as a pre-condition for ensuring that timely and affordable grid capacity is available for new generators. For instance in the current “RIIO ED-1” business plans that will define the activities of the DNO’s between 2015 and 2023, Ofgem has ruled out permitting any form of strategic investment mechanism, despite evidence submitted by stakeholders.

This means that all generation or demand related network reinforcement can only take place once developers have paid a significant proportion of the costs up front. Apart from the challenge of SME’s with a limited asset base raising significant amounts of capital, the scale of reinforcement required means that this approach guarantees that connection dates will always lag the build date of the generator.

Ofgem insists that “innovation” will be sufficient for finding the capacity required without investment “in copper and steel”. However we know from the experience of pilot innovation projects in Scotland that on fundamentally weak networks innovation is not a panacea. While some additional capacity can be created, it is often by transferring risk to generators, and it is nowhere near the scale required by the pipeline of generation coming forward.

In the context of the infrastructure spending earmarked by the Treasury post 2015, it is striking that none of it has been targeted at one of our most valuable public assets, vital to a low carbon transition- the grid. It is also ironic that at the same time as Ofgem are briefing the public on the risk of a generation capacity shortfall, and DECC are considering how best to subsidise new nuclear and gas plant, there are 100’s of MW of operational capacity currently being constrained or remaining unbuilt as a result of inadequate grid infrastructure.

An undiverse generation portfolio largely dependent on imported gas cannot be in the best interests of UK consumers, and yet Ofgem appears to be committed to strangling our renewable potential through a stop start approach to network investment- that in itself is likely to be higher cost as a result of piecemeal build programmes- and by placing a disproportionate financial burden on the local energy sector.

We would urge DECC to review the current RIIO TD-1 business plan for National Grid, and the proposed RIIO ED-1 business plans for the DNO’s, and consider whether they are aligned with the government’s generation and low carbon priorities.

A more detailed analysis of these issues and specific recommendations is contained in appendix 1.

APPENDIX 1

GRID CONNECTION ISSUES FOR DG IN SCOTLAND—JULY 2013

Below is Community Energy Scotland’s assessment of the barriers to DG projects in relation to grid connections and grid charging

The key barriers that are significantly impacting the installation of Distributed Generation and the ability to realise Scottish Government’s renewable energy targets are as follows;

1. Current grid connection delays to projects—

projects in Uists, Barra, Skye, Fort William and Fort Augustus area will not be able to gain a connection until 2021 ( earliest)

Projects in Caithness delayed until 2020

Projects in Orkney , Shetland delayed until 2018

Projects in Lewis and Harris until 2018? (Dependant on progress with interconnector and available capacity)

Projects on Western Highland 2018

Projects in Argyll—Taynuilt area- no proposed date, Southern Argyll in Port Ann area 2017

Other areas delayed until 2016 and beyond

2. Current high costs of distribution upgrades falling to developers- £5.25m for 27km upgrade of network for a 2MW project- DNO pays very little of this cost. Full review of this is required.

3. Continuation of requirement of higher cost charges applied to distribution connected projects than compared to transmission connected projects, for transmission works liabilities. Currently in Scottish Power area this is happening ie distribution projects have to pay upfront 100% of transmission liabilities while transmission connected projects have to pay reduced amounts. SSE currently considering changing their current position of applying no charges for transmission liabilities to projects under 10MW and reduced burden in line with CMP192 to projects over 10MW. CES have requested SSE maintain this position in recent correspondence. OFGEM need to take cognisance of impact on DG of this issue.

Community Energy Scotland believes the main reasons behind the barriers are:

Lack of strategic investment

Strategic investment in grid networks is not a real possibility for network companies at present. The upgrades required on the transmission system to facilitate renewable generation after many years of little investment are significant and completion dates are scheduled for 2018, 2020, 2021 etc. Also in some areas significant upgrades needed on the distribution system to facilitate renewable generation—some areas of Scotland are still on single phase supply which hampers economic development and does not facilitate renewable generation export. Renewable generation projects cannot connect until these works are complete. Delays at both transmission and distribution network levels impact distribution connected generators.

The current regulation by OFGEM is set to protect the GB consumer from increased charges in the short term––and so investment is only undertaken when there is contracted generation requiring connection—and these upgrades are underwritten by those contracted generators. The DNO’s and TO’s cannot invest ahead of need within the current regulatory framework.

Costs of connection for small projects

In terms of the cost barrier to generators there is a current £200/kW cost cap on the socialised investment in any distribution upgrade. For example we are currently supporting a project which is facing an exorbitant price for connection which involves a large upgrade to the DNO’s assets with long term benefits accruing to the DNO and the wider GB customer but currently the generator has to pay for the bulk of the cost.

Project Size	Upgrade required	Cost accruing to developer	Cost accruing to GB customer
2MW	27km of 33kV network upgrade total costs—£5.25m	£4,850,000	£400,000

Similarly underwriting of large scale transmission assets by small scale distribution projects is having a significant impact in project financing and places the burden on the generator for large scale works of national importance.

Unless quicker and more strategic- and socialised (without developer underwriting) investment is facilitated by the UK and Scottish Governments and OFGEM then our understanding is that the timelines won’t change. Also required will be sufficient capacity at network company level to achieve delivery in realistic timescales. This is something that the recent Intergovernmental Panel report on Scottish Islands also highlighted—but obviously the situation is much more widespread than the islands.

Our key asks would be

At a UK/SG level

An Intergovernmental review of the impact of onshore mainland grid delays and grid connection and underwriting costs in the deployment of renewable generation—both transmission and distribution

Review of the £200/kW high cost cap by OFGEM for distribution upgrades as this is currently resulting in very high costs of connection for small generators . If this cap was increased it would reduce the impact on individual generators and could be implemented speedily during the current price control period for Distribution networks ( 2010–2015)

Inclusion in RIIO-ED1 ( the distribution price control business planning ( from 2015–2023) currently underway by DNO’s and for review by OFGEM in summer 2013) of a strategic investment fund or mechanism—from recent conversation with SHEPD they had proposed a mechanism to allow low risk strategic investment on the distribution network to OFGEM , but OFGEM have not supported this.

Greater strategic investment facility at transmission level –with greater socialisation of costs of strategic investment in the first instance. The upfront underwriting requirement currently in place is stifling delivery of upgrades.

Greater and speedier innovation between transmission and distribution networks- SHEPD, SHE-T and National Grid to monitor actual power flows and release capacity based on actual network conditions- active network management (ANM) between transmission and distribution. SSE have said they are increasing the roll out of ANM in areas other than Orkney but have stated this will NOT be in areas of transmission constraints. Scottish Power have started to work on this -but it is only as part of a specific funded project. This work will be crucial to facilitate more generation on existing networks without the need for massive reinforcement.

Greater collaboration between distribution and transmission across the regulatory system and industry– the fact that transmission and distribution are regulated by different divisions within OFGEM, that their business plans are not aligned timewise , and also an apparent lack of communication between some DNO’s and TO’s within sister companies only exacerbates the lack of transparency and communication on the impact of transmission system delays to smaller projects.

Speedy reallocation of some recently released Transmission capacity following the recent TEC amnesty. OFGEM have not clarified the process for this. Community Energy Scotland is working with SSE and National Grid to ensure consented community projects are allocated some of the released capacity.

At Scottish Government level

Greater innovation at a local level—creating Local Energy Economies –increasing the ability of local generation to supply local needs with the integration of storage and active network management to enable full utilisation of Scottish renewable resources and supplying transport and heating needs. This would facilitate more distributed generation with less need for large network upgrades. A much increased focus from the Scottish Government Energy and Markets and Renewables Routemap divisions will be required along with multi stakeholder involvement. Community Energy Scotland are already investigating the possibility of such a programme and would welcome further discussion.

July 2013