By Angus McCrone
Chief Editor
Bloomberg New Energy Finance
Hari Seldon could tell us exactly what will happen to the world’s energy system. A character in Isaac Asimov’s Foundation novels, Seldon used what the author called “psychohistory” – a complex blend of galactic history, sociology and statistics – to work out exactly what civilisations would do in the future.
Unfortunately, I am no Hari Seldon and, according to our HR department, Seldon himself has yet to apply for an internship at Bloomberg New Energy Finance. In his absence, making forecasts about the world energy system in 2050, and even in 2040 and 2030, is fraught with difficulty. Indeed, we can be certain of only one thing – that all predictions about future energy, like all medium-term economic forecasts, will be wrong.
However, they still have plenty of value. They show the direction of travel. They show the possible long-term impact of current policies. They influence the behaviour of investors and policy-makers – indeed you could argue that an authoritative energy forecast might well be blown off course if politicians and energy sector players amend their actions in response (in Asimov’s story, Seldon’s psychohistory only worked if no one else knew about the prediction).
In addition, comparing the most sophisticated forecasts available can enable us to identify some of the most critical uncertainties, and to speculate on why people arrive at such different conclusions. That is certainly true of today’s crystal ball gazing on energy.
By way of example, I have been looking at the outputs of the International Energy Agency in its 2012 World Energy Outlook, Exxon Mobil in its Outlook for Energy to 2040, BP in its Energy Outlook 2030, and Bloomberg New Energy Finance in its 2013 Global Renewable Energy Market Outlook, known as GREMO for short. They are similar in some respects, and strikingly dissimilar in others.
Take the similarities first. In its central “New Policies Scenario”, the IEA says that annual global emissions will increase from 30.2bn tonnes of CO2 equivalent in 2010, to 37bn tonnes in 2035. Exxon Mobil predicts growth in emissions to 36.3bn tonnes in 2040, via a peak of about 37bn tonnes in the early 2030s. BP is the most pessimistic – suggesting that emissions could rise almost to 40bn tonnes per year by 2030.
Exxon and the IEA are both surprisingly optimistic about energy intensity and efficiency. Exxon expects energy demand to rise only 1% per year, well below its relatively modest economic growth estimate of 2.8% per year to 2040, while the IEA expects energy demand to increase at 1.2% per year, compared to GDP growth of 3.5% per year to 2035. These two estimates imply a major change in trend – because world energy demand actually increased at 2.3%-a-year between 2000 and 2010.
BP’s forecast is the closest to the average of that previous decade, looking for 1.7% global energy consumption growth per year from 2010, and that helps to explain its higher trajectory for emissions.
On electricity generation, the IEA projects an increase from 21,408TWh in 2010 to 36,637TWh in 2035, or compound annual growth of 2.2% per year. Exxon goes for a rise in electricity demand from 18,332TWh in 2010 to 34,198TWh in 2040, equivalent to growth of 2.1% per year. BP sees the 34,000TWh barrier being hit earlier, in 2030, and our GREMO team here at Bloomberg New Energy Finance is on the same track – seeing an increase in demand to 34,170TWh by 2030 on its central scenario.
MIXED VIEWS ON THE MIX
The plot thickens when you look at the electricity generation mix. The IEA says that coal’s share of generation will fall from 41% in 2010 to 33% in 2035, while gas rises from 22% to 23%, nuclear slips from 13% to 12% and renewables including hydro get to 30%. Within that 30%, hydro drops from 16% to 15%, wind rises from 2% to 7%, bioenergy from 2% to 4% and solar from next to nothing in percentage terms to 3%.
As Figure 1 shows, BP’s overall projection for renewables is roughly compatible with the IEA’s, bearing in mind that it addresses 2030, rather than 2035. BP sees renewables including hydro accounting for 25% of generation in 2030, with wind, solar and others on a combined 11%.
The numbers that are published in Exxon’s annual Outlook are differently based from those of the IEA or BP – relating to the electricity sector’s primary energy demand, rather than to the TWh generation mix. However the company has provided us with approximate figures for the latter in 2040, so I can compare apples with apples. These, shown in the chart, have gas accounting for fully 30% of the generation mix in 2040 – seven points higher than the IEA’s 2035 projection – with coal at 26%, nuclear at 15%, and renewables including hydro at 27% in 2040. Within the renewables figure, Exxon has wind at 7% and solar at just 2%.
Bloomberg New Energy Finance’s GREMO, published in late April, outlined three scenarios – “New Normal”, our central projection, in which renewables continue their moderate advance; “Barrier Busting”, in which they enjoy exceptional growth as cost and technical obstacles are systematically removed; and “Traditional Territory”, in which renewables are held back by policy, cost and technical issues. See our fact pack for further details. The New Normal scenario sees an electricity generation mix in 2030 in which renewables including hydro account for 37% of the world total, with wind on 10%, solar on 5% and biomass and waste-to-energy on 5%.
So, to summarise, we have the non-hydro renewables share far up from 4% in 2010, but as low as 11% (on the BP forecast for 2040, or 12% for Exxon 2040) and as high as 22% (on our forecast for 2030). There are other, interesting disagreements between the four forecasts on the shares of gas and coal.
COST DRIVERS
What explains these differences? Well, carbon costs are a big part of Exxon’s forecast that OECD countries would move from coal to gas between now and 2025. It said in its Outlook that this switch would be “driven in large part by the emergence of greenhouse gas policies that, together, will create a rising implied cost on carbon emissions through 2040”. In non-OECD countries, the change would be mainly post-2025, with coal “driven down in the mix due to climate change and a shift towards more gas, nuclear and renewables”. Exxon’s cost comparison model has gas-fired generation at less than six US cents per kWh in 2030, about a quarter of a cent cheaper than coal. But this advantage increases to three cents if an effective carbon price of $60-a-ton is included.
It sees the cost of onshore wind at nine cents per kWh in 2030, and solar PV at more than 12 cents. Exxon assumes there will be only modest capital cost improvements for both wind and solar between now and 2040 – of 15% and 25% respectively.
The IEA is more optimistic on costs for those two renewable technologies. Its World Energy Outlook forecasts for solar PV are based on a further reduction in capital costs of 45% or more, depending on the project scale and the region, between 2011 and 2035. For onshore wind, it has much more modest assumptions, showing a cost reduction of between zero and 10% during the 2011-35 period, again depending on the region.
Bloomberg New Energy Finance’s New Normal scenario is actually slightly more conservative than the IEA on PV costs, but much more optimistic on onshore wind costs. New Normal assumes a 39% reduction in the capital cost of utility-scale solar between 2012 and 2030, so the all-in system cost per MW would fall from $2.08 per Watt in the former year to $1.26 per Watt in the latter. For residential solar, the cost improvement over those 18 years is projected to be 40%, for onshore wind 30% and offshore wind 20%. By 2030, the all-in capex cost for onshore wind would be $1.22m per MW, compared to $1.73m today.
Much about the future depends on these cost improvements in clean energy technologies. So how likely are they to materialise? What we know is that onshore wind turbine prices fell about 20% between 2009 and 2012 and system costs for PV dropped by around 40% just between 2011 and 2012. So predicting a 40% cost improvement for PV, and a 30% improvement for onshore wind, over the next 17 years does not appear outlandish.
Admittedly, the recent pace of cost improvements is almost certain to ease. In wind, manufacturers are trying hard to make higher prices stick for their new models, according to our latest Wind Turbine Price Index, published earlier this year.
More significantly, in solar, after several years of crushing pressure on selling prices, the over-capacity among PV module manufacturers may be past its worst, as bankruptcies take their toll; and the threatened European tariffs on Chinese modules – if applied – could raise prices for a time. The fact that the NYSE Bloomberg Global Solar Energy Index has rebounded a remarkable 63% since its record low in late November last year suggests that investors also think the grip of deflation on manufacturers’ margins is starting to relax.
However we are confident that there are entrenched experience curves for PV and onshore wind that have been operating for 20 years or more. We expect them to continue to run for the foreseeable future, certainly as far as 2030, as economies of scale and technological improvements take effect. The crystalline silicon PV module experience curve implies continuing cost reductions per Watt of 24% for every doubling of cumulative capacity. The onshore wind experience curve cost reductions per MW of 7% per doubling of capacity, plus improvements to the capacity factor that take the learning rate in MWh terms closer to 14%.
POLICY IMPETUS
Eric Martinot, author of REN21’s Global Futures Report, has studied the landscape of energy forecasts and says that, along with the evolution of costs, another key differentiator is what they assume about policy changes. At one end of his spectrum are projections that assume only modest changes in policy settings, at the other end are scenarios based on what would be necessary to achieve particular climate goals.
The latter include the IEA’s “450 Scenario”, based on keeping carbon dioxide below 450 parts per million; Greenpeace’s “Energy [R]evolution” scenario for 2050; and the Global Energy Assessment study, again for 2050. This group all forecast very high renewable shares of electricity generation, at 62-94% by the middle of the century. These forecasts are particularly topical at the moment, given that the CO2 content of the atmosphere has this month touched the 400-parts-per-million barrier, according to the US National Oceanic and Atmospheric Administration, up from 280 in pre-industrial times.
However, for now, most governments and companies base their business plans on scenarios from the more mainstream forecasts, such as those of Exxon, BP and the IEA’s New Policies Scenario. Among these, Exxon takes the view that there is a great deal of uncertainty over the temperature impact of rising CO2 and therefore the policy response will be gradual. The IEA predicts greater efforts to spur the move to low-carbon sources, but warns that even so, “emissions in the New Policies Scenario correspond to a long-term average global temperature increase of 3.6 degrees Centigrade”.
BALANCING AND OPTIONALITY
Other factors may help determine which forecast is closest to being right. There is the matter of balancing costs. Exxon, for instance, says that wind and solar will continue to incur significant “costs to overcome the challenges of intermittency and reliability”.
However we would argue that the level of those costs is not fixed in stone. The options for balancing include flexible back-up capacity (generally gas-fired generation), storage, demand response and interconnectors. The last two can make it much easier to balance variable wind and solar capacity – as does the rapidly improving ability of grids to predict intermittent generation – and their costs are coming down their own experience curves. Meanwhile storage is a rapidly evolving area of technology. Most storage options available now – including pumped hydro and batteries – are relatively expensive, but given the amount of entrepreneurial and R&D effort in this area, it may be risky to assume that they will still be expensive come 2030 or 2040.
There is also the question of how utilities assess the value of diversification in their generation mix. This was one of the questions we examined during our Bloomberg New Energy Finance Summit in New York last month, where the theme was “The New Energy ROI – Resilience, Optionality, Intelligence”. Put in a nutshell, the economically rational strategy for a utility is not to put all of its eggs into one technological basket, particularly not that of conventional, centralised fossil-fuel power stations. Instead, the right option-value-adjusted strategy may be to diversify their fuel mix, invest in energy efficiency, distributed generation, storage and demand response, and positioning themselves as players in the roll-out of electric vehicles. All these are strategies which help hedge against volatility in gas and coal prices, security threats, natural disasters and changes in environmental regulation.
In the Foundation novels, Hari Seldon’s number-crunching work resulted in him predicting the imminent demise of the Galactic Empire and an ensuing 30,000-year dark age. Sadly, for all of their differences, the projections of today’s energy models do little to soothe worries about similarly dystopian outcomes, because of their implications for greenhouse gas growth in the atmosphere.
Seldon was forced to keep his predictions to himself, lest he inadvertently impact the future. Today, those of us reading the tea leaves should do just the opposite, and try to influence those who can shape future events.