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    Wednesday, October 23, 2013


    Energy Darwinism; The Evolution of the Energy Industry

    Jason Channell Heath R Jansen Alastair R Syme Sofia Savvantidou Edward L Morse Anthony Yuen, October 2013 (Citi GPS)

    Energy Darwinism; The Evolution of the Energy Industry

    The global energy industry has been transformed in the last five years in ways and to an extent that few would have thought credible. The emergence of shale gas has transformed the U.S. energy market while Germany has seen some gas-fired power stations running for less than 10 days a year due to the impact of solar leading utility owners to issue profit warnings. Developed markets now spend more on renewable capital expenditures than they do on conventional generation, largely due to uncertainty over commodity pricing and likely future utilisation rates, while the legacy of Fukushima has seen Japan burning gas at $16-17/mmbtu while the U.S. basks in $3 shale, driving the introduction of the world’s most attractive solar subsidy scheme and catapulting Japan to be the world’s second largest solar market. Conversely, the intermittency of renewables has led to the greater demand for the flexibility of gas-fired power plants in some markets.

    So, fuel and technology substitution is happening – and not just in developed markets. The shift in emerging markets is less marked, but is nonetheless there. The voracious appetite for power displayed by emerging markets will engender a higher level of new conventional generation (in particular coal), though gas is gradually taking demand from coal and renewables are forecast to represent 10% of new installed power generation capacity in China over the next two years.

    Despite these shifts, the analysis of individual fuel and technology cost curves – a key determinant in setting the market price – has continued largely on a standalone basis, with limited emphasis on the risks of substitution. Accordingly, in this report we have combined the work of our alternative energy oil & gas, mining (coal), utility and commodity research teams to create an integrated energy cost curve, which allows us to assess the impact and risks of this substitutional change across all fuel and technology types. Importantly, this integrated curve looks at incremental energy demand and supply, meaning relatively small changes in the mix can have a material impact on the returns of projects, particularly those at the upper end of the cost curve.

    To make the comparison easier, we have focused on the power generation market, as this is by far the largest and fastest growing consumer of primary energy with the highest level of substitution risk. To do this, we have used the levelised cost of electricity (LCOE) concept which allows us to compare different fuels and technologies on a like-for-like basis. We also examine the different evolutionary pace of the various fuels and technology, in an attempt to assess how this curve itself will evolve. Given the long-term nature of both upstream and consumer projects, these changes could well have a material impact within the life of many of these projects.

    This analysis of ‘Energy Darwinism’ highlights the uncertainties and hence risk inherent in upstream projects at the upper end of the gas cost curve, in the coal industry overall, for utilities and for the power generation equipment manufacturers. These changes and risks will affects investors, developers, owners, products and consumers of energy, which given the sums of money involved, makes it of paramount importance to be understood.

    The evolution of the energy industry

    While the world of energy is constantly evolving, we believe that the last five years has seen a dramatic acceleration in that rate of change and, more importantly, that the pace of change is set to at least continue if not accelerate further. Simplistically, we believe that certain power generation technologies are evolving -- most notably gas via the shale revolution or solar via technological and manufacturing advances -- while other technologies such as wind are evolving much more slowly, with some such as coal showing more limited evolutionary change. Given the long term nature of investments in these technologies and fuels, we believe that the pace of change will have a profound impact on the returns of both upstream and generation projects. A case study of Germany where the generation landscape has been radically altered in just the last five years shows this is not a ‘tomorrow story’ — it is happening now, and while it will take longer to impact emerging markets, it will impact an increasing number of industries and countries going forward.

    Who would have thought five years ago that the U.S. would become a net petroleum exporting country, edging out Russia as the world's largest refined petroleum exporter? That the U.S. would be generating more electricity from gas than coal? That German utilities would profit warn with some gas power stations running for less than 10 days a year, because solar has stolen peak demand? Or that utilities would be putting on hold conventional generation projects and building renewable capacity in their stead, even without sizeable subsidies or incentives? The energy market has changed dramatically in recent years and we believe that this mix is only going to alter more rapidly going forwards.

    Despite this rate of change and the level of fuel substitution, detailed analysis of fuel cost curves has largely remained separated by fuel or technology type rather than undertaken within a holistic energy framework. However, as the experience of the German electricity market shows, fuels and technologies do not exist in their own bubble. There is the risk -- or indeed now the reality -- of technology and fuel substitution, which we expect to become a more prevalent feature in an increasing number of markets as time progresses.

    What is a cost curve?

    A cost curve is a graph generated by plotting the cost of a commodity produced by an individual asset (e.g. a specific gas field or coal mine) on the vertical axis, against the ‘volume’ of reserves in that specific asset on the horizontal axes. This is done for all assets (e.g. all gas fields for a gas cost curve) starting with the cheapest first on the horizontal axis, with each volume being added cumulatively. Hence, if we know a likely demand level on the horizontal axis, we can read up to the line and deduce the cost of the marginal producing asset which should be a key determinant in setting the market price.

    With this in mind, we have decided to construct an integrated energy curve, combining the work of our alternative energy, oil & gas, metals & mining (coal) and commodities teams. While previous work has highlighted the obvious higher levels of commodity price risk to those reserves or technologies further to the right on their respective cost curves, they did not take the analysis to the next level by examining the interplay between those fuels, and in particular this risk of substitution.

    To do this we have focused on the electricity generation market, using an LCOE approach (see overleaf). While this analysis is not perfect (not least as significant quantities of energy do not go into power generation) power generation is by far the largest consumer of primary energy (50% greater than the next largest) and is by far the fastest growing, Moreover it is perhaps the most transparent and rapidly changing market, as well as the market which offers the greatest potential for substitution, and hence is of most interest in terms of marginal energy supply/demand going forward.

    What is LCOE?

    LCOE is the ‘Levelised Cost of Electricity’, which attempts to compare different methods of electricity generation in cost terms on a comparable basis. Different technologies vary materially in the proportion of upfront capital expenditure vs. fuel cost or operating costs, as shown in Figure 1. LCOE incorporates all of these costs and calculates the ‘price’ of electricity needed to give a certain rate of return.

    Investments being made now will be subject to relative cost transitions in the energy market which will affect the competitiveness of those fuels or generation technologies, and hence their success or failure. This fuel and technology risk can be witnessed at a customer level by the reluctance of utilities to invest in some large, capitally intensive power generation projects (e.g. nuclear in the UK, US utilities swapping gas peak shaving plants for solar, or German utilities generally) given the medium and long term uncertainty over power prices, utilisation rates and hence returns on investment. As another example of risk, despite the ‘shale boom’, we would also note that the returns of the US E&P stocks have remained sub- WACC, not something that might have been expected given the excitement surrounding the shale gas boom.

    We believe that these transitions are happening faster and to a greater extent than is widely recognised, and hence our efforts to integrate and forecast the various energy curves in an examination of ‘Energy Darwinism’.

    The integrated curve shown in Figure 2 shows incremental energy supply coming onstream between now and 2020, and consists of the LCOE’s derived from the cost of extraction from individual upstream gas and coal projects (the vertical axis), combined with their expected output, which creates a cumulative volume on the horizontal axis.

    As Figure 2 shows, gas dominates the first quartile of the integrated cost curve, largely thanks to the advent of shale. However, the gas curve is itself very long, with the lower end of the solar cost curve impacting the upper end of the gas cost curve; moreover, solar steals the most valuable part of electricity generation at the peak of the day when prices are highest. This effect has already caused the German utilities to release profit warnings, with some gas power plants in Germany running for less than 10 days in 2012, all of which makes some utilities reluctant to build new gas plants given fears over long term utilisation rates and hence returns.

    Wind is already overshadowing coal in the second quartile. While wind’s intermittency is an issue, with more widespread national adoption it begins to exhibit more baseload characteristics (i.e. it runs more continuously on an aggregated basis). Hence it becomes a viable option, without the risk of low utilisation rates in developed markets, commodity price risk or associated cost of carbon risks.

    Perhaps most importantly is the evolution of each of these industries, fuels and technologies. Solar is exhibiting alarming learning rates of around 30% (that is for every doubling of installed capacity, the price of an average panel reduces by 30%), largely due to its technological nature. Wind is evolving, though at a slower ‘mechanical’ learning rate of 7.4%, and gas is evolving due to the emergence of fracking and the gradual development and improvement of new extraction technologies. Conversely, coal utilises largely unchanged practices and shows nothing like the same pace of evolution as the other electricity generation fuels or technologies. Nuclear has in fact seen its costs rise in developed markets since the 1970’s, largely due to increased safety requirements and smaller build-out.

    What is a learning rate?

    Learning rates typically refer to the speed of improvement in outcomes of a given task or situation relative to the number of iterations of that task. We use learning rates in the context of this note to describe the speed at which technological or manufacturing improvements reduce the cost of electricity from a particular type of generation (e.g. solar) relative to the cumulative installed base of that generation technology. In this context, a learning rate of 10% would mean that for every doubling of installed capacity, the average cost (or price) of that capacity would decrease by 10%.

    Given the long term nature of upstream fossil fuel and power generation projects, this substitutional process and the relative pace of evolution is vitally important to understand. The sums of capital being invested are vast; the International Energy Agency (IEA) forecast that $37 trillion will be invested in primary energy between 2012 and 2035, with $10 trillion of that in power generation alone. Clearly the value at risk from plant or the fuels that supply them becoming uneconomic in certain regions, both in terms of upstream assets and power generation, is enormous.

    This analysis of ‘Energy Darwinism’ as we have chosen to call it highlights the uncertainties and hence the risk inherent in upstream projects at the upper end of the gas cost curve, in the coal industry overall, for utilities, and for the power generation equipment manufacturers. These changes and risks will affect any investor, developer, owner, producer or consumer of energy which, given the sums of money involved, makes it of paramount importance to understand…


    So why does any of this matter? Quite simply the sums of money at stake in terms of investment in energy over the coming decades are staggering, and getting a choice of fuel or technology ‘wrong’ could have dramatic consequences for both countries and companies, be they upstream oil & gas companies, utilities, industrial consumers, renewable developers of power generation equipment providers. Understanding the evolutionary forces at work and their interplay in a holistic manner will prove vital for anyone exposed to the energy markets.

    As discussed earlier, the IEA estimate that some $37 trillion of investment will be required in global energy supply infrastructure between 2012 and 2035. Of this $37 trillion, $16.9 trillion will be in the power industry (i.e. electricity), with $9.7 trillion of this latter figure being in power generation, the remainder thereof being accounted for by transmission and distribution. This leaves $20 trillion to be invested in ‘primary energy sources such as upstream coal, oil and gas.

    Accordingly, a 5% swing from one fuel source to elsewhere in power generation would equate to a swing in capex of $500 billion over that period; depending on the fuel sources involved, the impact on the upstream industry in terms of demand could be at least as big again, if not multiples thereof (for gas fired generation capex is around 15% of the cost of a unit of electricity, with fuel being 70%, whereas for coal the figures are around 35% and 30% respectively).

    This is not a ‘tomorrow’ story, as we are already seeing utilities altering investment plans, even in the shale-driven U.S., with examples of utilities switching plans for peak-shaving gas plants, and installing solar farms in their stead. The same is true for other fuels, for example the reluctance on the part of utilities to build new nuclear in the UK, or the avoidance of coal in some markets due to uncertainty over pricing, likely utilisation rates and or pollution. Even in China, we believe that coal demand is likely to peak this decade as its generation mix starts to shift. If we look at the situation facing European utilities, the future looks particularly challenging, given a potential halving of their addressable market, an ageing fleet, and deeper questions about what a utility will look like in 5, 10 or 20 years’ time. In transportation, the emergence of electric vehicles, and more importantly the rise of oil to gas switching show that evolution is not restricted to the power generation market.

    The impact of the energy decisions taken by companies and governments will have impacts on equipment suppliers, as well as the upstream providers of the fossil fuels on which these plants do (or don't) run. It will affect the demand for these commodities, as well as the price and hence the likely returns on upstream investments.

    As we examined earlier the impact is undoubtedly different in developed vs. emerging economies. However even in emerging economies new technologies are taking enough of incremental energy demand (and an increasing amount going forwards) that it will have an impact on demand for conventional power generation. For the purposes of this note it is incremental energy demand and supply which are important. Hence even small movements in relative economics, i.e. the positioning on the integrated cost curve, could result in a switch in customer choice which will have an important impact on the economics of some upstream projects, particularly those towards the upper end of the cost curve.

    In summary, we believe that the global energy mix is shifting more rapidly than is widely appreciated, and most importantly that consumers face economically viable choices and alternatives in the coming years which were not foreseen 5 years ago. Accordingly, we believe that long term investment into some conventional fuels must be considered in the context of at worst the risk of substitution, or more likely lower demand than might otherwise be expected, with implications on prices and hence returns of those upstream projects. Moreover, the further up the cost curve conventional fuels are, the higher these risks associated with that investment. Investing in a project with an assumed 25 year life, when new technologies will be competing with that fuel in the first quarter of that project’s life entails significantly more risk than we believe is widely recognised. There will always be more subjective choice factors involved such as fuel diversity and energy independence that may offset cold, hard economics, but investors, companies and governments must consider the sea change that we believe is only just beginning.

    The shale gas boom is now widely understood and accepted, and it is notable that gas now dominates the bottom quartile of our integrated cost curve. In the second and third quartiles, however, coal is being impinged upon by both wind (now) and solar (in the coming years). Perhaps most important is that expected energy demand intersects the curve at the upper end of the second quartile, meaning that the level of risk associated with upstream projects to the right of this intersect (i.e. third and fourth quartiles) is enhanced. We should obviously remember the demand from both industry and heat related markets which also take significant elements of gas and coal supply, and hence we are not saying that these fuel sources will not be used. However, their relative attractiveness may change, their position on the cost curve is likely to move given the different evolutionary speeds of the fuel choices, all of which will have an impact on demand and hence pricing, and therefore the returns of the upstream extraction industries. Accordingly we believe that an understanding of these dynamics and the pace of this evolutionary change is crucial for any investor, owner, producer or customer of energy; in short, just about anyone involved in or exposed to the energy industry.


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