UK peaker investment: here comes consolidation

Competition to provide new capacity across the UK’s first three capacity auctions has been dominated by thousands of small peaking units. In contrast, only one relatively small CCGT has bid successfully (Centrica’s 0.4GW Kings Lynn plant).

3.5GW of distribution connected diesel and gas fired peakers have received 15 year capacity agreements across the 2014-16 auctions. An additional 2GW of new Demand Side Response (DSR) has been successful, mostly supported by peaking units behind the meter.

The capacity market has been designed to deliver competitively priced capacity. And the relatively low capital and fixed costs of distribution connected peaking units has seen developers substantially undercut competition from larger scale, grid connected CCGT and OCGT plants.

Peaker investment to date has been driven by a range of smaller developers. But larger players are eyeing the peaker sector which appears ripe for aggregation and consolidation. And portfolios of small scale peakers fit the risk/return profile of large infrastructure investors, unlike larger scale thermal assets which have a higher dependence on more volatile wholesale margins.

State of play in the peaker sector

There are several established medium sized players focusing on peaker investment in the UK market. At least two of these, Green Frog Power and UK Power Reserve are flagged for sale. But these initial sales processes may just be the tip of the iceberg.

There is strong infrastructure investor interest in peaker portfolios given margin protection from 15 year capacity agreements. Market entry options include acquiring an established player, aggregating smaller projects and/or growing organically via development of new capacity. All of these options are being actively pursued in a flexing of investor muscles that is yet to determine who will dominate the peaker sector going forward.

The other factor that suggests consolidation is a shift in the regulatory environment. The investment case for distribution connected peakers was dealt a blow by Ofgem earlier this year, when it indicated its intention to slash the ‘triad benefit’ that peakers earn by generating in peak periods to reduce supplier transmission charges.

In addition the UK government has indicated it intends to remove ‘double payment’ for the Capacity Market Supplier Charge (on top of the capacity price) and to constrain investment in higher emission diesel peakers.

While the more established players have been preparing for these regulatory blows, reduction of the triad benefit has hit some smaller, less experienced developers hard. A number of projects may be scrapped or consolidated within other peaker portfolios.

But despite these regulatory changes, distribution connected peakers are still a competitive source of highly flexible and low capex capacity, to support low load factor backup of intermittent renewable generation. But there are a number of challenges  investors face in getting comfortable with the peaker investment case summarised in Table 1.

Quantifying peaker portfolio risk and return

A key challenge for investors looking at peaking units is getting comfortable with the evolution of the multiple margin streams that drive asset economics. These can be broadly split into four streams:

1. Capacity margin: driven by capacity market pricing
2. Energy margin: driven by the wholesale energy market and Balancing Mechanism evolution
3. Balancing services margin: driven by e.g. STOR market and ancillary services pricing
4. Embedded benefits: driven by the evolution of regulatory policy and supplier grid charges

Peaker margin streams are not simply additive e.g. a decision to provide STOR services directly impacts energy and BM margin capture. This means it is key to overlay a realistic view of how peaking units will practically generate value.

The regulatory changes described above are shifting the relative risk/return profiles of peaker margin streams. Gas reciprocating engines are now the principal technology (given diesel unit emissions). These units have higher capital costs than diesel generator sets. But they are also more efficient, meaning significantly lower variable costs.

Lower variable costs increases the opportunities for gas engines to capture value from power price volatility in the wholesale energy market and Balancing Mechanism (BM). Peaking units are extremely flexible (e.g. fast ramp times, low start costs), but quantifying this flex value requires a robust probabilistic plant modelling approach. This means using a stochastic pricing simulation engine and associated plant dispatch optimisation model. The two key advantages of this approach are:

1. It is consistent with the way trading desks actually optimise and dispatch portfolios of peaking units
2. It generates margin distributions (as opposed to scenario forecasts), providing a robust view of asset risk/return dynamics

The peaker investment case is still built around 15 year capacity agreements and access to balancing services revenue. But understanding wholesale energy market and BM margin are becoming a key element of gas peaker economics.

A traditional Base, High and Low scenario approach for peaker margin may have been adequate when the investment case was driven by the triad benefit and diesel engines. But gas engine investment requires a more sophisticated analytical approach.

Article written by David Stokes and Olly Spinks