Valuing portfolio diversity in power generation

May 10, 2010

That reflects an emerging consensus among many utility economists and the industry’s own regulator, the Office of Gas and Electricity Markets (Ofgem).

Until now, deregulated power producers have largely selected power plants according to their “levelised costs” (expressed in pounds per megawatt hour, MWh).

Levelised costs are essentially the minimum power price needed for a plant to earn back its full costs (including construction, operation and maintenance, fuel, and cost of capital) over its expected lifetime-output, using an appropriate discount rate for present-valuing future costs and revenue.

Levelised cost is the electricity price for which the project’s net present value is zero.

Different technologies are ranked in terms of which has the lowest (most favourable) levelised cost. The approach has favoured investment in combined-cycle gas turbine (CCGT) technology, which is quick and cheap to build. CCGT plants are faster to ramp up, thereore  more flexible than coal-fired units, and a better fit for the market-driven generating model.

Most new capacity commissioned and installed over the last two decades has employed CCGT as part of the “dash for gas”. It has resulted in a big shift in the total generating portfolio from one dominated by coal and supported by nuclear to one dominated by natural gas.

EU legislation will lead to further closures of coal-fired plant in the coming decade, while some aging nuclear plants are also set to close, making the system even more gas dependent.

Given declining UK gas output and increasing reliance on imports, as well as the sharp increase in gas price volatility over much of the last decade, many analysts now question whether the market-driven focus on levelised costs is appropriate or if it is leading to a dangerous build up of risk in the system.


The late Professor Shimon Awerbuch of Sussex University’s Science and Technology Policy Research Unit (SPRU), and formerly a senior adviser to the International Energy Agency (IEA), pioneered an alternative approach combining both cost minimisation and risk minimisation.

Awerbuch’s approach is borrowed from modern portfolio theory, used by pension funds and other institutional investors to select financial assets.

In the same way that prudent investors diversify their portfolios to achieve the most efficient combination of risk and return, rather than simply picking the financial instrument with the highest expected return, Awerbuch argued prudent generators should maintain a diverse portfolio of sources of supply, rather than simply building least-cost plants.

Financial assets are evaluated not just in terms of their own risk and return profile, but their contribution to risk and return in the portfolio as a whole. Portfolio risk is not simply the sum of risks associated with each asset. If returns on different assets are not perfectly correlated, adding more assets to the portfolio can reduce the overall volatility or riskiness of the portfolio as a whole.

Generating assets should be evaluated in the same way, according to Awerbuch. Even if nuclear and wind plants are more expensive than CCGT, adding them to a portfolio of generating assets could still make sense if costs are not perfectly correlated. Diversified portfolios create more certainty about future electricity prices for any given level of cost (or alternatively lower costs for any given level of uncertainty about future prices).

CGT has relatively low construction costs per MWh but substantial exposure to volatile (therefore risky) gas prices. Nuclear and wind are expensive to construct but once built fuel costs are zero (very low for nuclear). Adding nuclear and wind plants to a portfolio of CCGT units can lead to less volatility or risk in terms of total costs once both construction and running costs are taken into account.


Awerbuch’s approach is increasingly being adopted by policymakers, including Ofgem. In a consultation paper published in February 2010, Ofgem acknowledged current market arrangements and price signals are not producing the right generating mix.

It represented a significant about-turn for the agency, which has been at the forefront of deregulating power markets worldwide, with an emphasis on leaving decisions about new capacity to investors.

The regulator “noted that companies sought to benchmark their hedging and procurement strategies against each other in order to minimise the risk of their energy costs deviating materially from the average. Such behaviour is the consequence of the market structure and the lack of threat from new entry”.

“There is a risk that such dynamics could impact the perceived riskiness of generation investments, such that, perversely, investments with stable operating and fuel costs (such as nuclear and wind) could be viewed by the Big 6 suppliers as more risky than investments whose costs vary with volatile global fuel costs”.

“Under the current market structure, in the absence of effective new entry, there is no obvious mechanism for consumers to express a preference for more stable energy costs”.

In plain English, the high degree of concentration of in the power market, and the adoption of common, benchmark-hugging investment and hedging strategies, has enabled generators to pass through volatile gas prices to consumers, effectively externalising the risks associated with fuel-price volatility.

If gas prices rise, it hits all the suppliers equally. They all pass them through to retail and industrial consumers at the same time and magnitude, so there is no risk to market share.

Freed from any real risks linked to fuel prices, generators have focused on minimising risks associated with construction and capital costs, opting for CCGT and against nuclear and wind.

The result has left consumers increasingly exposed to shifts in international gas prices; utility investors only have to worry about risks associated with construction and funding.

Ofgem is worried the government’s CO2 reduction plans will make the situation worse. “Uncertainty surrounding future carbon prices may encourage companies to invest in CCGTs since these are less exposed to carbon price uncertainty … This could exacerbate gas import dependency and make decarbonisation of the power sector over the longer term more difficult”.

Awerbuch and Ofgem both argue consumers put a positive value on certainty about the level of future power prices, rather than just caring about receiving the lowest expected price.

Uncertainty associated with a gas-dominated portfolio can be reduced incorporating a greater share of nuclear and wind into the generation slate to “hedge” against gas supply disruptions or a sharp rise in fuel costs.

But there is at present no mechanism for consumers to express that preference effectively. With the industry dominated by six suppliers all adopting the same investment and pricing strategy, and no real threat of entry, consumers cannot opt for a supplier that promises greater price stability in exchange for slightly higher electricity prices. Consumers are left exposed to gas price risks they probably do not want.

Ofgem argues this “market failure” creates a reason for it to intervene to ensure a more diversified, less risky portfolio in future that would give consumers more stable power prices, though it seems uncertain about what form that intervention should take.

In any event, there is an emerging consensus that levelised costs are no longer a sufficient approach to capacity planning; more attention needs to be paid to interconnections between gas, nuclear and wind, and the resulting balance of assets and risks in the generating portfolio as a whole.

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