The UK government has released further details of its intended approach for the 1^st capacity auction, now scheduled for December 2014.  These provide information on factors such as bidding rules, auction process and the publishing of information to the market.

DECC has also confirmed that 15 year capacity agreements are available for new build plant (rather than the initially proposed 10 years).  This should materially reduce the cost structure of new build plant.  Importantly it is also likely to provide a bigger relative benefit to OCGT versus CCGT plant.  Most UK asset developers are focused on CCGT development.  But in our view the Capacity Market brings the OCGT investment option back on to the table.

What’s new from DECC?

DECC’s Capacity Market policy team released a ‘working synthesis’ specification paper in early April.  The paper emphasises the ‘work in progress’ nature of some of the information announced.  But this paper has clearly been released to provide a guidance update on DECC’s intentions given the rapidly approaching 1^st auction.

Key details in the paper include:

• 75 £/kW auction price cap in 2012 terms – escalated at CPI to delivery year.
• Price taker/setter threshold to be published at a later stage (based on net CONE).
• 15 year capacity agreements are now available for new build plant, but DECC refurbishment agreements remain limited to a maximum of 3 years.
• Refurbishment and new build capacity thresholds confirmed as in Oct 2013 (i.e. 125 and 250 £/kW), note that this is on de-rated not nameplate capacity.
• Non-performance penalties are to be capped at 200% of monthly capacity payment revenues, with an overarching annual cap of 100% of capacity revenue.
• DECC’s aim is to include interconnectors in the 2015 auction.

There are no standout surprises here, but these details provide some further clarity to feed into pre-qualification submissions and bidding strategy development.  The diagram below that we published previously, is a reminder of the key elements of the capacity market structure.

Auction process and DECC published information

Auction format

DECC has also provided some more clarity on how the auction rounds may evolve.  There will be up to 4 auction rounds per day for up to 4 days.  DECC suggests it intends to step price down in small decrements.  An example of 5 £/kW is given, which is consistent with the 75 £/kW cap and maximum of 16 auction rounds.  A full price schedule will be published as part of the auction guidelines.

DECC published information

DECC has indicated it intends to provide some useful details on capacity supply following the pre-qualification stage.  This includes:

• Which CMUs qualified for the auction and at what de-rating, and whether as existing, new or refurbishing plant – but not whether they qualified as price maker or taker
• Which CMUs have opted out and how much capacity will be deducted from the demand curve
• Which CMUs said they will be retiring / unavailable (and so not had their capacity deducted from the demand curve).

However during the auction information release will be limited to how much spare capacity there is at the conclusion of each auction round.  This again raises a key question as to how much information players will actually gain from one auction round to the next (e.g. on implied energy market expectations).  And whether there will actually be much market participant adjustment of capacity bids through the auction rounds.

Auction cancellation

The government also retains a key ‘get out of jail’ card.  DECC intends to require all pre-qualified participants to confirm auction participation 10 business days prior to the 1^st auction.  This includes whether they are price takers or setters and their intended length of contract.  Two business days later a list will be sent to the Secretary of State who has the ability to cancel the auction if it is not deemed to be sufficiently liquid/competitive.   Given the market design complexity, remaining uncertainty and tight timelines, it would seem a prudent strategy for market participants to have an auction delay contingency plan close to hand.

New CCGT vs OCGT

UK generation asset developers have historically focused on CCGT plant.  From a total asset margin perspective this makes complete sense.  CCGT have a clear efficiency advantage over OCGT and with 30GW of existing CCGT capacity merit order competition is fierce.  As a result it is hard to build an OCGT investment case based on significant energy margin returns.

However the availability of 15 year fixed price capacity agreements may change the UK power market investment landscape.   With a capacity price cap of 75 £/kW/year, new build CCGT plant will still need to bank on recovering a healthy energy margin (given capital costs in excess of 100 £/kW/year).  But energy margin expectations may be heavily discounted by players given the potential for capacity overbuild and general market uncertainty.  CCGT plant may still be the best solution on a total margin basis, but the capacity market design is swinging the balance back towards OCGT assets.

An OCGT investment case will revolve principally around capacity margin.  So CCGT investment concerns over energy margin expectations and tolling agreements disappear.  OCGT capital costs are also significantly lower than for CCGT.  And if plant margin is covered under a 15 year capacity agreement, there are some attractive leveraging options.  There do not appear to be many ‘auction ready’ OCGT projects out there.  Yet a credible OCGT development option may undercut new build CCGT as well as being a valuable diversification opportunity for generation portfolio players.

The countdown has commenced to the implementation of the UK Capacity Market.  Between now and November, the UK power market will be focused on the volume and pricing of capacity delivered in the first auction.  And the rest of Europe will be watching, given capacity markets are the subject of whiteboard sketches across the offices of the EU’s energy regulators.

For all that has been said and written about the UK Capacity Market, industry views range widely as to its commercial impact.  What will the outcome of the 1^st auction be?  How will the capacity price interact with the wholesale power price?  What are the implications for generation asset returns?  We consider these questions in this, the final article, in our three part series on the Capacity Market.

The 1^st auction outcome

Understanding the capacity price & volume outcome in the first auction means taking a view on two key factors:

1. The volume of incremental capacity that the system will require to meet the government’s 3 hour LOLE security standard (estimated by National Grid to be equivalent to a de-rated capacity margin of 3.8%)
2. The source and cost of the marginal provider of this incremental capacity.

The government will provide a clearer view on the incremental capacity volume requirement (1.) when it publishes its capacity demand curve (scheduled for June).  In our view, there is a risk that political influence leans towards a more ambitious capacity target for the first auction given concerns over security of supply.  After all, the costs of providing capacity via the Capacity Market are less transparent than via the wholesale power market, and are smeared over a multiple forward year horizon.

Once there is more clarity around capacity demand, the key determinant of capacity price will be the cost of the marginal source of supply (2.).  In our view the capacity price in the first auction is more likely to be set by existing gas and coal assets rather than new build CCGT/OCGT.  This may either be via refurbishment of existing capacity to enhance/extend assets lives, or via existing assets recovering the ‘going forward’ costs required to remain open (as we set out here).  However it cannot be ruled out that the government really leans on the capacity lever, pulling the capacity price up to levels that support new build.

There are also still a number of unresolved issues around market design which could impact the auction outcome.  For example, the length and legal basis of capacity contracts, qualification for price setting ability and the amount and nature of capacity costs that can be bid in.

Impact on wholesale power price levels

In the current world with no Capacity Market, the absolute level of power prices is driven by the fuel & carbon costs of marginal generators (primarily CCGT).  This will not change with the Capacity Market, regardless of capacity pricing outcomes.

However the Capacity Market is set to have a pronounced negative impact on power price levels, relative to the current energy only market.  Adding an additional capacity revenue stream for generators has two important effects:

1. It is likely to support higher levels of system capacity than in an energy only world
2. It reduces the requirement for generators to recover fixed costs via wholesale power prices.

Both these factors are likely to put downward pressure on power prices.  In order to better understand the dynamics of capacity and energy market interaction, it is useful to use a supply curve framework as shown in Chart 1.

Chart 1: The UK supply stack, power prices and generator rents

Source: Timera Energy

The left hand diagram shows a short run marginal cost (SRMC) view of the UK supply stack (net of intermittent generation).  The CCGT portion of the supply curve (blue line) which typically sets marginal power prices is very flat, given there is around 30GW of CCGT competing to supply power at similar marginal cost levels.  That translates into a flat SRMC duration curve in the right hand chart (the grey line).

In a market which has a very tight capacity margin (e.g. the UK in 2016), wholesale power prices rise significantly above SRMC.  This yields a steeper price duration curve (the red line in the left hand chart), with generators earning rents above SRMC, particularly in periods of peak net system demand.   The principle mechanism that drives these higher rents is reduced competition between marginal generators in setting market price (given capacity tightness).  This means marginal generators have a greater ability to price power above marginal cost.

However in a market with a more comfortable capacity margin (e.g. the UK in 2019), wholesale power prices are likely to more closely reflect SRMC.  Rents are reduced given an increased level of competition between marginal generators at higher capacity levels.  In other words, the ability of marginal generators to price power above marginal cost is reduced and the price duration curve flattens accordingly (the green line in the right hand chart).

So implementation of the Capacity Market, combined with delivery of new renewable generation, will mean higher system capacity levels.  These factors act to stretch the supply curve, shifting the intersection of supply and demand to the left.  This in turn reduces rents in the wholesale market and places downward pressure on power prices.

Impact on power price volatility & market liquidity

The effect of renewable intermittency in increasing prompt power price volatility is a well understood concept.  Fluctuations in wind and solar output stretch and contract the supply stack, causing changes in marginal price setting generation units and hence price volatility.  This effect is set to increase between 2014 and 2018, as the system capacity margin tightens and wind & solar volumes increase.

But implementation of the Capacity Market may act as a volatility dampener from 2018/19.  The factors behind this are the same ones that place downward pressure on power prices.  Higher levels of system capacity reduce the system tightness that drives price volatility.  And as the focus of fixed cost recovery for peaking assets shifts to the Capacity Market, a reduction in the extraction of peak period rents should dampen wholesale price fluctuations.

The Capacity Market will also do little to help wholesale market liquidity.  The government’s other EMR reforms have eroded the requirement for low carbon generators to hedge output in the power market.  The Capacity Market is likely to have a similar effect on gas and coal generators.  As the margin focus of these asset shifts to annual capacity payments, it reduces their wholesale market hedging requirements (particularly for peaking assets).

Implications for gas plant owners

The Capacity Market will have profound structural implications for the margins and risk/return profiles of gas assets.   Most importantly it should boost and de-risk plant margins.  Capacity prices will fluctuate from one year to the next, but more stable fixed annual capacity payments will reduce asset dependence on volatile wholesale market revenue.  While this is good news for asset owners, it introduces a new set of challenges in understanding and managing the interaction between capacity and energy margins.

Chart 2 provides a simple illustration of the margin recovery path for gas plant between now and the end of this decade.

Chart 2: CCGT margin recovery path

Source: Timera Energy

Healthy system capacity margins and steadily increasing renewable volumes are currently depressing CCGT margins in the wholesale power market.   As scheduled regulatory retirements occur mid-decade, the capacity margin is set to tighten which should in turn increase gas plant energy market rents (as described above).  Then a new capacity margin stream is available from 2018/19, but one that will have an important interaction with the existing energy margin stream.

As long as there is a system requirement for the Capacity Market to deliver incremental capacity, capacity prices are likely to cover the fixed cost base of CCGT assets (otherwise older CCGT plant will close).  This, combined with a 4 year forward visibility on capacity revenues, will help support and de-risk the value of CCGT assets.  In addition CCGTs will be able to recover capacity margins significantly above fixed costs in periods when the capacity price rises to incentivise capacity delivery.

For older CCGT assets, currently out of merit and suffering low or negative cashflows, the Capacity Market is a potential game changer (as long as plants meet the required flexibility standards).  The key challenge for asset owners is how to manage margin in the period between now and 2018/19 and how to bid assets into the capacity auctions.

Newer CCGT assets running at higher load factor will also benefit from capacity margin, but will retain a significant exposure to the wholesale power market for recovering capital costs.  The key challenge here is for asset owners to understand the interaction between capacity and power pricing and to manage, hedge and bid their assets accordingly.

As the November auction approaches, asset owners are confronted with a set of decisions on how to manage asset value across the energy and capacity markets.  The cost structure and expected energy market returns of individual plant are key factors in defining a capacity bidding strategy. But there are also important considerations around anticipating actions of other generators, pricing capacity based on alternative bids and bidding with a generation portfolio perspective.  Most importantly, the Capacity Market has a key bearing on lifetime investment decisions on asset retirement, mothballing, capex spend and refurbishment.

Changes to the UK power market have been coming thick and fast this decade.  The implementation of a Capacity Market in November 2014 is just one of a growing list of market reforms.  But the Capacity Market is set to have a unique & structural impact on UK power market dynamics and asset values.  Replacing an energy only market with separate energy and capacity markets is quite a dish to swallow.

Two factors make the Capacity Market a big deal:

1. It introduces a new revenue stream for UK power plant, in addition to the current wholesale market revenue stream
2. It gives the government the ability to tightly control the level of capacity in the market

These factors will have a key impact on wholesale power prices and the return on generation assets.  From 2014 onwards, commercial and investment decisions will involve taking a view (either explicitly or implicitly) on the level and dynamics of pricing in the new Capacity Market.  In this article, the second in our series on the Capacity Market, we look at the drivers behind capacity pricing.

How will capacity prices be determined?

Up until late last year, a lack of detail on Capacity Market design from DECC (the Department of Energy and Climate Change), made it difficult to draw meaningful conclusions on capacity pricing.  That is starting to change.  There are still many design factors to be resolved before the first auction in November.  But there is now enough detail to start drawing some sensible conclusions on capacity pricing dynamics.

We start with a basic overview of the market mechanism that will set capacity prices.  If you are familiar with the capacity market design, you may want to skip ahead to the next section.

Structure of the capacity supply curve

In order to understand capacity price levels it is important to have a grasp of the cost of providing incremental flexible capacity.  To the extent that the Capacity Market is competitive, pricing should broadly reflect the cost of providing incremental capacity (caveat the reality that there may be significant opportunities to exercise market power in setting market price).

There are a number of potential sources of incremental capacity, but the key ones likely to drive capacity pricing can be grouped as follows:

1. Preventing existing gas & coal plant from closing
2. Refurbishing existing gas & coal plant to enhance/extend lives
3. Developing new OCGT or CCGT plant

Deriving the cost structure of the incremental sources of capacity is not simple.  The relevant benchmark for each source is the cost of capacity net of energy market returns (i.e. net of margin earned in wholesale power market).  But as plant owners bid into the auction this year, they will need to make an assumption on the impact of the Capacity Market on power prices and implied energy market returns in 2018/19.  Views on this may vary significantly.

In Chart 2 we show some estimated ranges of incremental capacity cost by source.  The ranges around each category reflect two factors.  Firstly, different cost estimates depending on asset/technology.  But secondly and more importantly, uncertainty around how plant owners will net off anticipated energy market returns when bidding into the Capacity Market.

Chart 2: Estimated net cost ranges for key capacity sources

Source: Timera Energy

Plant across all of these categories will compete to provide capacity, but the key question is which category will represent the marginal (price setting) source.  These plants will have the greatest influence in determining capacity price, as well as the greatest ability to exercise market power.

What type of plant will set the capacity price?

In order to understand which category of plant will set capacity prices it is important to understand how much incremental capacity will be required to meet the DECC target.  Of foremost importance is a snapshot of the projected capacity requirement, 4 years in advance of delivery.  This is because the main 4 year-ahead capacity auctions (e.g. in 2014) will be driven by the government’s forward estimates of capacity requirement (e.g. in 2018/19).  The capacity price will then be set in the auction based on the available capacity options to meet the target.

So considering the dynamics across the 3 main capacity categories:

Retaining existing plant

Paying existing CCGT and coal assets to remain in service requires at a minimum that plant fixed costs are covered.  So in a situation of capacity oversupply, plant fixed costs will be an important benchmark because the capacity price is likely to fall below these levels until older plants retire to redress the capacity balance.

Given the current conditions of capacity tightness in the UK, oversupply is unlikely to be an issue this decade.  But paying existing plant to remain open may have a key influence on the first capacity auction in November.  This is because DECC may allow loss making plant (e.g. many of the 90s built CCGT assets) to include in their capacity market bids, the losses suffered over the 4 year period prior to capacity delivery (i.e. 2014-18).  This may significantly inflate the cost structure around existing plant in the first auction (although this will be a one-off effect).

Plant refurbishment

As well as just delaying retirement, owners of existing CCGT assets can also make a more substantial investment in upgrading the plant.  DECC has indicated such refurbishment must involve investment over and above normal major maintenance capex (e.g. gas turbine refurbishment, CCGT to OCGT conversion or coal supercritical conversion).

The advantages of refurbishment for the owner are not just the enhanced asset, but the ability to lock in a capacity price over a longer duration contract (at least 3 years, maybe 5).  It also allows the asset owner ‘price setter’ rights in the auction.  Refurbishment may prove to be a fruitful source of incremental capacity.  This may act as an important buffer to prevent capacity prices from rising to support new build OCGT/CCGT capacity.

New build plant

DECC has, somewhat controversially, proposed to base the price cap on the cost of a large modern OCGT plant rather than the traditional market benchmark of a new CCGT plant.  DECC has published a gross cost estimate for an OCGT of 47 £/kW/yr, implying a net cost of 29 £/kW/yr (based on their courageous assumption of 18 £/kW/yr of OCGT energy margin).

This comes in substantially below DECC’s net cost estimates for a new CCGT which range up to 60 £/kW/yr.  While in theory, if it is only capacity that DECC wants to deliver, it may be logical to structure capacity pricing around OCGT assets.  But in practice OCGT investment has been ‘off the table’ for most UK market participants given the more favourable all in economics of CCGT assets.

The key interaction determining the cost of OCGT versus CCGT plant comes down to assumed energy market returns.  Because a new CCGT is significantly more efficient than an OCGT, it will earn higher energy market returns to offset its higher capital costs.  In fact it is difficult for an OCGT plant to earn any significant energy market returns in the UK given they must compete against a large volume of existing CCGT and coal assets, most of which are likely to have a variable cost advantage.

The first auction will reveal to what extent new OCGT actually play a role in setting capacity prices. But OCGT aside, there are a raft of potential new CCGT projects that will act to constrain upwards movement in capacity prices.

Marginal capacity pricing dynamics

The level of UK capacity prices will largely be determined  by which of the three categories of plant sets the price.  Given current capacity tightness, the market is likely to clear significantly above the fixed costs of CCGT (10-20 £/kW/yr).  In other words existing CCGT plant are set to earn substantial margins in the CM.

But in our view it is unlikely that capacity prices in the first auction will rise to levels that support OCGT/CCGT new entry (e.g. 60+ £/kW/yr).  That is unless the government sets a very aggressive capacity target and/or disadvantages existing coal plant (causing it to retire early).  Instead there looks to be a fairly comprehensive range of plant life extension/enhancement options that can bring forward the incremental capacity required.  The capacity supply curve is however likely to be lumpy which may mean sub-groupings of plant have considerable opportunities to exercise market power in setting price (e.g. by bidding up towards a level that supports OCGT/CCGT new entry).

Whichever category of plant sets marginal capacity pricing in November, capacity is likely to price at a level that places downward pressure on wholesale power prices in 2018/19.  In other words UK power market returns are going to undergo a rapid and structural change.  We consider the implications of this for portfolio managers and asset investors in our next and final article in this series.