Capacity payments are coming

23 April 2015

A review of the inexorable drive towards capacity markets in Europe and the lessons to be drawn from the UK's recent auction.

By David Stokes, Timera Energy

European power markets are slowly but
steadily moving towards implementing
capacity remuneration mechanisms
for flexible generation. A consistent pan-
European solution looks unlikely. Instead
the approach and pace of implementation is
being driven by security of supply concerns
in individual countries. However, a regulatory
consensus is emerging as to the need for some
form of remuneration for flexible capacity as
renewable generation volumes rise.
Theoretical discussions are raging across
Europe as to the 'missing money' problem
of under-remuneration of peaking capacity,
the academic basis for capacity payment
intervention. But ultimately capacity
remuneration implementation is likely to
be driven by practical rather than academic
In the absence of capacity payments
(or much higher power price volatility),
renewable capacity subsidisation across
Europe will squeeze flexible generator
margins to the point that power plants close.
The current capacity oversupply situation
across much of Europe may provide a
temporary buffer, but ultimately plant
closures will undermine security of supply.
Different approaches across Europe
The concept of capacity payments in
power markets is not new. Several markets
in the United States have implemented
capacity markets with varying degrees of
success. There are also European markets
that already have some form of capacity
payment, eg, Ireland and Spain. But for the
larger north west European power markets,
the design and implementation of capacity
payment mechanisms is a relatively new
There are broadly three forms of capacity
remuneration model being considered:
¦ Central buyer solution: for example as
was implemented in the United Kingdom
in 2014 (for capacity delivery in 2018/19),
driven by concerns about security of
supply and a rapidly tightening system
capacity margin.
¦ Supplier obligation solution: for example
as is being implemented in France in 2015
(for 2016/17), driven by concerns about
having sufficient capacity to meet peak
winter heating load.
¦ Strategic reserve payments: for example
the 'Strategic Generation Reserve'
contracts that were awarded in Belgium
in the lead up to the current winter to
address system tightness concerns after
nuclear outages.
The map below (courtesy EY) provides a
summary of the approaches to capacity
payments across Europe.
Strategic reserve payments are being used
as a convenient temporary (or 'stepping
stone') solution to address system capacity
issues. There is typically a lower regulatory
hurdle for the introduction of these
payments compared with transitioning to
a more structural capacity market solution.
The payments are being introduced under
the guise of greater powers for the system
operator to contract reserve. But there is
increasing disquiet within the industry
about the lack of transparency around
remunerating capacity in this way.
For example, the UK Supplemental
Balancing Reserve (SBR) payments are
being used as a somewhat opaque 'stop gap' means of remunerating capacity over winter
periods, while the more structural capacity
market solution is rolled out. Germany has
taken a different but equally controversial
approach by mandating certain assets of
strategic system importance to remain
available for reserve purposes.
Oversupply in Continental power markets
has reduced the immediate urgency for
structural capacity remuneration solutions.
But as time passes, increasing renewable
output will only further compromise the
economics of flexible peaking assets. It is
unlikely that politicians and regulators will be
willing to stomach the power price volatility
required to keep adequate peaking capacity on
the system. And local transmission constraint
issues (eg, in markets like Germany) are also
pressuring regulators to respond.
A number of countries across Europe are
now openly considering more structural
capacity remuneration solutions, eg Germany,
Belgium, Poland and Italy. The momentum for
capacity remuneration is only likely to increase
over time with interesting implications for
asset margins and investment returns.

The UK experience
The UK led the way in Europe with
implementation of traded wholesale gas and
power markets. This was driven primarily by
a pro-liberalisation regulatory agenda. The
UK again finds itself leading the way with
the design and implementation of a capacity
market. But this time it is driven more by
reactive necessity than proactive ideology.
The UK is facing a rapid decline in system
capacity margin, at the same time growth
in renewable output threatens to close a
number of fossil fired plants required to
provide peaking capacity.
The first UK capacity auction was
concluded just in time for Christmas 2014,
with the government procuring 49.3 GW of
capacity at a clearing price of 19.40 £/kW.
The auction results gave little in the way
of Christmas cheer for most UK generators,
with the clearing price close to half that of
market consensus expectations.
The conditions that set up the downward
price pressure in the auction stemmed
from a relatively low government capacity
target that saw an 'oversupply' of existing
capacity. Existing capacity volume (54.9
GW) exceeded the procured volume in the
auction (49.3 GW) by 5.6 GW.
Some 2.8 GW of new capacity (Carlton
Power's 1.8 GW Trafford CCGT project and
0.9 GW of smaller scale peaking plants (eg,
reciprocating engine based plants/diesel
gensets/small gas turbine units)) were
successful in obtaining capacity agreements
despite the low auction clearing price. In
addition, 0.2 GW of demand side reduction
(DSR) capacity also secured agreements.
Interestingly, although the planned
Trafford CCGT plant (which intends to
employ GE's new HA gas turbine technology)
was successful, ESB's Carrington CCGT
plant, which is next door, did not secure a
capacity agreement despite already being
under construction.
Capacity agreements were not secured by
8.4 GW of older existing capacity: 4.5 GW of
coal (Rugeley, Eggborough, Ferrybridge and 1
unit of Fiddlers Ferry & West Burton); and 3.9
GW of CCGT (Barry, Brigg, Killingholme A&B,
Peterborough, Corby, Deeside & Peterhead),
putting plant owners in a difficult position.
The auction outcome has been heralded
as a success by the government ('capacity
procured cheaply for the consumer'). But it
is unclear whether the first auction has done
anything to improve UK security of supply over
the critical period of market tightness, 2015-
18. In fact the outcome may have exposed
one of the key weaknesses in the capacity
market design, where capacity is procured on
the basis of uncertain forecasts of conditions
four years in advance. This leaves little ability
for the capacity market to respond to market
tightness over the next three years.

Four lessons learned
The UK capacity market implementation
is not a shining example of how to design
and deliver capacity support from a policy
perspective. But the commercial 'lessons
learned' by UK generators in the lead up to
the first auction have a broader relevance
for generators across Continental power
markets as they prepare for capacity
payment mechanisms.
The transition to capacity remuneration may
in some ways appear to be a relatively minor
tweak to market design. But in practice capacity
payments have an important structural impact
on thermal power plant asset risk/return
profiles and generation portfolio dynamics.
The following are some observations on the
transition to capacity payment support:

1. Capacity and profit margins
Capacity payments add a more stable margin
stream for flexible thermal assets. But they
tend to have a significant adverse impact
on the wholesale energy profit margin by
supporting higher levels of system capacity.
This tends to increase competition to provide
the marginal MW of capacity and therefore
reduce energy market rents. Analysis of
the interdependence between capacity and
energy pricing and the associated impact on
generation margins, provides an important
foundation from which to understand the
commercial impact of capacity payments.

2. Investment, technology and costs
As capacity constraints begin to bite, the
cheapest incremental flexible capacity
will typically be provided by keeping
open existing thermal plants that have a
competitive fixed cost structure and that
have capital costs which are already paid
down (eg, less efficient CCGTs). Capacity
payment support can fundamentally change
the economics of these assets (most of which
are currently cash flow negative).
Once existing capacity options are
exhausted it is important to understand the
economics of new build options. Capacity
payment mechanisms may skew new build
investment economics. Capacity payments
tend to favour lower capex small scale
peakers (eg, diesel generators, reciprocating
engines and small gas turbines) ahead of
more efficient but more capital intensive
technologies (eg, new CCGTs).
Capacity payments also impact the financing
opportunities for new plants. A consensus is
emerging across lending banks that debt sizing
should be based on the capacity payment
margin stream, with equity required to support
the balance of the investment.

3. Capacity pricing dynamics
There are some good benchmarks for capacity
pricing that can be derived from a combination
of technology costs and historical price data
from existing capacity markets. Conclusions
on capacity pricing bounds can be drawn to
some extent independently of the capacity
mechanism design. For example:
¦ Lower price bound: A reasonable lower
bound benchmark for capacity prices (in
a market that faces a capacity constraint)
is provided by the fixed costs of thermal
peaking assets that would otherwise
close (eg, less efficient CCGTs).
¦ Upper price bound: Reasonable upper
bound benchmarks can be derived from the
costs of delivering incremental new flexible
capacity. It is important to note however
that capacity mechanism design may
skew this benchmark towards lower capex
smaller scale peakers rather than CCGT.

4. Asset lifetime horizon
Perhaps the most important conclusion from
preparations for the UK capacity market is to
develop a strategy for capacity remuneration
over an asset lifetime horizon. It is human nature
to focus on the most immediate problems to
hand. In the case of capacity payments this can
mean focusing on capacity returns over a near
term horizon, eg, defining a specific bidding
strategy for the next capacity auction. But it
is much more important to develop generation
portfolio and investment strategies around the
interdependent evolution of wholesale energy
and capacity margin streams over a longer
term horizon. This means deriving capacity
bids based on a risk adjusted asset lifetime
NPV view.

The way forward
It is easy to ignore capacity remuneration until
there is greater certainty around policy design
and implementation. But the UK experience
suggests that the specifics of policy design do
not preclude generators from taking proactive
steps to alter their investment and generation
portfolio strategies. In fact there is a clear
first mover advantage from anticipating the
structural impacts of capacity payments
on asset margins, portfolio structure and
investment strategy.

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