Energy and Climate ChangeWritten evidence submitted by Air Products

Introduction

Air Products, a leading global provider of industrial gases and equipment, energy and environmental systems and an inward investor in the UK, welcomes the opportunity to provide input to the Energy and Climate Change Select Committee’s Inquiry into Local Energy.

Air Products gained planning permission to build a 49MW advanced gasification energy from waste plant on a brownfield site on Teesside in August 2012. Construction is now well under way and the facility is due to come on-stream in 2014. It will create 700 construction jobs and 50 permanent jobs, divert up to 350,000 tonnes of waste from landfill per year and produce enough predictable, controllable, clean electricity to power up to 50,000 homes. A second project on an adjacent site and of a similar size is currently awaiting planning and board approval. As part of the Government’s Energy for Growth initiative, the Cabinet Office recently signed a deal with Air Products to buy the electricity from the plant, subject to the approvals outlined above.

If these two projects are successful, three further projects of a similar size are possible in the UK with a total potential capacity of roughly 250MW of renewable electricity, representing £1 billion of investment.

Air Products believes that projects up to 50MW in size could play a significant role in meeting UK’s climate change objectives, improving energy security and controlling future energy prices. This is particularly true of those which provide baseload renewable electricity.

However, over the past 12 months we have seen delays and uncertainty in energy policy which have caused a concern amongst our US-based investment management team. The perception is that UK policy is becoming more uncertain and less predictable for companies investing in energy projects such as ours.

The following submission focuses on answering the questions on barriers to developing our “medium-scale” energy projects in the UK and the effectiveness of Government policies in encouraging such projects to come forward.

What are the barriers to medium-scale energy projects in the UK?

1 Barriers existing in the current market

1.1 Development costs are proportionately higher than for larger projects

Although medium scale energy projects of less than 50 MW may not have such extensive planning or environmental reporting requirements as larger ones, they are still subject to significant development costs which of course have to be spread over much smaller anticipated pro rata project revenue.

1.2 The electricity market is principally designed to accommodate wholesale trading of power and delivery to customers through a small number of large vertically integrated suppliers

Market power of the large vertically integrated players means that independent generators with smaller projects are in a weak negotiating position.

1.3 Finance has become harder to obtain and terms have deteriorated

To date, the route to market for medium scale energy projects has been to contract with suppliers, who will typically offer 12- to 15-year power purchase agreements (PPAs). For project-financed projects, the offtaker will also agree to provide a route to market for all of the ROCs, LECs and REGOs although they are purchased at a discount, typically around 90% of full value. In order to be financed, a medium-scale energy project will require some form of base-price certainty over the tenor of the debt by means of a floor price in the PPA. Even though many banks are only willing to offer debt with a shorter (eg seven year) tenor on a so-called hard or soft “mini perm” basis (meaning that the debt must be repaid in full after seven years or there is a strong financial incentive to do so through an increase in the margin/interest rate), they are still requiring developers to have a 12–15 year PPA to ensure there is a clear basis on which to refinance after seven years.

1.4 PPA terms have deteriorated recently

There is clear evidence that, in the last few years, suppliers have become less willing to offer PPAs to independent generators and when they do, the terms have deteriorated. Specifically, PPA offers have deteriorated in the following areas:

(a)Imbalance risk: Suppliers have historically been willing to take the risk of differences between forecast and actual output which, because of their large portfolios, they are better able to manage. Increasingly we are seeing PPA offers which shift some of this risk back to the generator eg by electricity price re-openers if imbalance costs increase. To some extent this is understandable: there has been a steady stream of consultations about balancing reforms and “sharpening” of cash-out prices, without any certainty over the 12–15 year term of a PPA. Suppliers naturally will build in terms (or in their pricing) to address this uncertainty, which adds to the costs of developing renewable projects.

(b)Change-in-law risk: suppliers have historically been willing to take the risk of changes in law affecting the electricity market (including changes in industry documents such as the BSC, CUSC and Grid Code). Increasingly we are seeing PPA offers which shift some of this risk back to the generator eg by changes to the electricity price floor or by specific circumstances (eg new market zones created by the European Target Model or the impact of capacity payments on the wholesale price) not being covered. Again, this is a natural consequence of the significant uncertainty about the future structure of the market created by regulatory change.

(c)Commercial terms: We have seen:

(i)increases in the discounts required by suppliers for the purchase of electricity, ROCs and LECs and the sharing of embedded benefits;

(ii)offers with no floor price or with floors which are of limited duration, without indexation or which can be re-opened in certain circumstances (see change in law above)—this makes project finance very difficult; and

(iii)a general change in the market index forming the basis of the electricity price from a month-ahead index to a day-ahead index, which places more risk on the generator.

In our view, the key reasons for this deterioration in PPA terms are:

a preference among the supply businesses of the large vertically integrated utilities to prefer their own sister companies in contracting for renewable power;

uncertainty about numerous aspects of the market (including the volume of ROCs required, the impact of CfDs on the market price for power, imbalance costs, future changes in law, impact of the capacity market, etc) which makes entering into a 12–15 year PPA a very risky prospect.

2 Barriers created by Electricity Market Reform

2.1 The structure of CfDs discourages long-term fixed price offtake contracts

More recently it has been possible to negotiate a long-term fixed price ‘sleeved’ contract with a credit-worthy retail customer (such as a supermarket chain, fast-food outlet, etc.), which spans the project lifetime. A licensed supplier registers the meters and performs certain services for a fee. The fixed price is attractive as it provides certainty for both the generator and the customer. However, in contrast to the ROC system under which the generator receives a reasonably fixed level of price support, the difference of payments under a CfD (using a market index as the reference price) will decrease price certainty. CfDs are designed to provide a “top up” from the reference price to the agreed strike price and only work if the generator is selling its power on the same basis as the reference price is calculated (effectively “spot”).

Air Products’ first Tees Valley advanced gasification waste-to energy-project, currently under construction, is financially underpinned by such a long-term fixed price contract with a retail customer. Our second Tees Valley project has recently been awarded a long-term fixed price contract by the Government Procurement Service (the Cabinet Office contract mentioned in the introduction). The Government intends to secure other such fixed priced contracts with other energy generators in the next five years through the Energy for Growth scheme. Under the CfD regime, we see no economic incentive on the part of the energy customer to enter into a long term PPA and take on future price risk, which the variability of the CfD is intended to mitigate. As a result, we fear that PPAs will become rarer as the route to market is curtailed, thus undermining not only future projects like Air Products’ but also the success of the Government’s own Energy for Growth programme. To avoid this from happening, the Government must reconcile the variable reference price with the need for long term power price contracts.

2.2 The removal of ROCs takes away an important incentive on suppliers to contract for renewable power from independent generators

The appetite of suppliers to purchase renewable energy from independent generators is strengthened by the suppliers’ obligation to purchase an increasing percentage of energy from such sources. Although suppliers have a buy-out option, in practice there are reputational as well as financial incentives on suppliers to buy ROCs (which are invariably priced under long-term PPAs at a discount to the buy-out price and recycle payment). Independent generator have a genuine and real concern that, without ROCs, suppliers will be much less willing to buy their power.

2.3 Embedded benefits are threatened by the EMR proposals

Projects connected to the electricity distribution system (as opposed to the transmission system) can achieve “embedded generation” benefits, as suppliers can offset the contracted output against their registered demand. These benefits include avoidance of National Grid’s transmission network use-of-system (so-called triad) charges, avoidance of transmission losses, avoidance of balancing services use of system charges, avoidance of distribution losses and avoidance of some distribution charges. Although the embedded benefits are initially received by the supplier, the overwhelming majority of current PPAs share the financial value of these benefit, with the generator receiving the bulk (usually around 90%) of the value.

The supplier’s ability to achieve most of these embedded benefits depends on the supplier registering the generator’s output meters in the same Balancing Mechanism (BM) Unit under the Balancing Settlement Code as its customers’ demand in the same region (the relevant base Consumption BM Unit)..

Paragraph 159 of the CfD Operational Framework proposes that embedded generators will be required to register—via their suppliers—an additional BM Unit, and that the “loss adjusted” metered energy would then be used for settlement purposes. This proposed arrangement would destroy any embedded generation benefits that medium-scale projects currently receive. We can see no logical reason for removal of the embedded benefits currently enjoyed by medium sized projects. There does not appear to have been any impact assessment made of this change and it appears to be driven by the administrative convenience of calculating difference payments under CfDs.

If the current (supplier counterparty) arrangements cannot be replicated, and medium-scale generators are required to be treated in the same way as larger, licensed generation their costs will increase as they will no longer be able to anticipate embedded generation benefits. They will also be exposed to transmission charges, even though they will be connected at distribution voltage levels (and are not eligible for constraint payments). This potential increase in costs, and elimination of benefits may mean revisiting the CfD submissions already made by such generators, so that some form of extra uplift is provided to compensate for the loss of the benefits and increased charges.

April 2013