UK Nuclear Deal Is A Bet on Baseload Power

• An agreement to build the UK's first new nuclear power plants since 1995 endorses the role of baseload generation in the future low-emission energy mix.
• Rather than constituting a choice of nuclear instead of renewables, this looks like nuclear plus renewables as a hedge on rising UK natural gas prices.

Monday's agreement between the UK government and French utility EDF and a pair of Chinese firms marks the start of the long-awaited turnover of the country's aging nuclear power infrastructure. The deal is controversial, not least for the power price of £92.50 per megawatt-hour (MWh) guaranteed to the developers. That's equivalent to about $0.15 per kilowatt-hour (kWh) at today's exchange rates. It's also strikingly different from the choices Germany and France itself have made recently.

The UK has a long history with nuclear power, having started up the world's first commercial-scale civilian reactor in 1956, following demonstration units in the US and USSR a few years earlier. Many of the plants built in the construction wave that followed have already been retired, and none has been started up since 1995. Another 40% of the country's remaining 10,000 MW of nuclear capacity is due to shut down by the end of this decade, with all but the newest, largest nuclear plant at Sizewell scheduled for retirement by the early 2020s. Even if the two new reactors that EDF and its partners will build at the Hinkley Point site in Somerset--adjacent to two 1970s-vintage reactors still in service--are completed on schedule, Britain's nuclear output is likely to shrink before it grows again.

The Hinkley C deal hinged on a question that can still only be answered theoretically today: What is the most effective future electric generating mix for achieving the necessary combination of affordability, reliability and low greenhouse gas emissions? In the aftermath of the Fukushima accident the German government decided that nuclear had no place in that mix and doubled down on its commitment to renewable energy, particularly wind and solar power, though that shift appears to require an increase in coal-fired generation to pull off. Meanwhile, France, which currently gets 75% of its electricity from nuclear, has embarked on a plan to reduce its share to 50% while expanding renewables.

The electricity mix in the UK is already changing as large offshore wind projects and onshore wind farms come online, and as the country's inexplicable flirtation with solar power increases. The gas turbines that dominated the previous wave of power plant construction are becoming more expensive to operate as waning UK North Sea gas output must increasingly be replaced by imported gas, while more coal plants shut down. All of this is underpinned by a legally binding commitment to reduce greenhouse gas emissions by 80%, compared to 1990, by 2050.

The UK's options for devising a reliable low-emission electricity mix are limited. If it wanted to build that mix around the combination of gas and renewables that California has chosen, then it would need a cheaper source of gas. That explains the government's interest in shale gas, although the outcome--both in terms of the rate of development and the future extent and cost of shale gas production--remains uncertain. It also can't rely nearly as much on solar, since it receives on average around half as much sunlight as the Golden State. Coal won't fit without carbon capture and sequestration (CCS) that is still expensive, and large-scale hydropower potential appears to be limited. That leaves nuclear as the largest-scale low-emission baseload option to anchor the energy mix, with quick-reacting natural gas turbines left to even out the fluctuations of offshore and onshore wind, and possible future wave and tidal installations.

In that context, it was surprising that the UK energy minister apparentlhy chose to frame this week's transaction as a choice for nuclear over the "blight" of the tens of thousands of wind turbines required to generate the same electricity, annually. Configuring wind power to provide enough reliable baseload energy to make nuclear unnecessary would require more overcapacity, grid upgrades and energy storage than even California's legislators could imagine. That would cost far more than the £92.50/MWh price tag for new nuclear.

And that brings us back to the price guarantee, or "strike price", which was apparently the key to getting EDF and its partners to commit to proceed on Hinkley Point. Since the UK's coalition partners had previously determined to provide no subsidies for nuclear power, arrangements such as the loan guarantees offered to US nuclear developers were out of the question. Whether the "contract for difference" scheme chosen to support Hinkley Point's future revenue--funded by ratepayers rather than taxpayers--constitutes a subsidy by another name, it is functionally similar to the Feed-In Tariffs (FITs) offered to wind, solar and other renewables in Germany and elsewhere. For comparison, the current German solar FIT guarantees utility-scale installations the equivalent of £84/MWh for a period extending past the planned start-up of Hinkley C.

Solar and nuclear power aren't interchangeable on the grid, but the spread between them highlights the financial risks involved in the current deal. The UK is placing a potentially expensive bet on low-emission baseload power from nuclear energy, while its biggest neighbors on the Continent are turning away from nuclear to pursue steadily rising shares of intermittent wind and solar power, the cost of which keeps falling. The government's call looks justifiable today for reasons of reliability and as a long-term investment--Hinkley C should still be producing billions of kilowatt-hours a year when the wind turbines and solar panels installed in Britain this year are rust and dust. However, if the UK's Bowland shale turns out to be the first Marcellus-like play outside the US, that price guarantee could cost future British ratepayers hundreds of millions of pounds per year.

Unlocking the UK's Shale Gas Potential

• Following estimates of substantial shale gas resources underlying parts of Britain, the UK government is proposing incentives for companies and local communities to encourage its timely development.
• Even if it ultimately proved less transformative than in the US, shale gas could balance the UK's future energy mix, while setting an example that other shale-rich EU countries could follow. 

Shale gas development has been slow out of the starting blocks in Europe, for reasons that have been widely discussed.  These include differences in mineral rights ownership, smaller onshore oil and gas service sectors, and significantly fewer onshore wells drilled in the past, compared to the US.  Local opposition to hydraulic fracturing also plays a role in some countries. Last month the UK government announced new proposals intended to address some of these challenges and make shale gas more attractive to produce there. The Prime Minister underlined these proposals in an op-ed in Sunday's Telegraph.

The UK's natural gas market has been experiencing problems similar to those the US encountered in the last decade, prior to wide-scale development of shale gas resources.  Natural gas production from the offshore fields of the UK sector of the North Sea, which provided an energy surplus until about ten years ago, has declined rapidly. As a result, the Interconnector UK, a bi-directional gas pipeline linking Britain to continental Europe, has recently operated mainly in import mode. UK natural gas prices have been correspondingly high and volatile, spiking briefly to around $17 per million BTUs this March. Prices in excess of $10/MMBTU are typical.

Against this background, the UK government is understandably interested in pursuing the exploration of the country's potentially enormous shale gas deposits.  In June the British Geological Survey released its detailed estimate for the Bowland shale in the north of England.  With a range of 822-2,281 trillion cubic feet (TCF) of gas-in-place, and a "central estimate" of 1,329 TCF, this looks like a significant resource. Even at the low end of the BGS assessment, and using a conservative figure of 15% recovery based on relevant US shale gas recovery rates, the Bowland could provide 120 TCF or more of technically recoverable gas, the equivalent of over 40 years of current UK consumption.

Two aspects of the government's proposals caught my attention.  First, the Chancellor of the Exchequer indicated his plan to make development attractive for producers with a new tax structure that he intends to be "the most generous for shale in the world." Earnings from shale would be taxed at 30%, compared to 62% for other hydrocarbon projects.  With only a few companies currently exploring for shale, that should attract additional drillers, along with the service companies that perform many of the key activities at the well site. 

I was more intrigued by the proposal--apparently originating with industry--to provide local communities with a benefit of at least £100,000 per well-site that is hydraulically fractured, or "fracked", plus a small share of gas revenue. In a country where the government owns the sub-surface property rights, this could be a crucial step in gaining local support for projects that, in addition to significant economic activity and eventually local employment, will also result in unavoidable increases in noise, traffic and other intrusions in daily life during the weeks or months in which each site is being prepared, drilled, completed and brought on-line, and for the longer periods that crews would be operating in the area.

We've certainly seen the importance of local benefits in promoting receptiveness towards gas drilling in the US, where most shale development has occurred on private land, and where royalties from production provide property owners with regular payments ranging from helpful to lifestyle-altering, depending on production rates and the ownership interests. Sharing financial benefits from shale production at the community level, rather than with individuals, might even galvanize broader-based support than in some parts of the US. Much will depend on whether British communities consider the offered compensation sufficiently generous.

UK shale development still faces significant above- and below-ground uncertainties that only time and drilling can resolve.  Nor is it clear whether development of the Bowland shale would have as large an impact on the UK gas market as shale gas has had here.  Skeptics can be found among opposition politicians and respected energy analysts, though I must say their arguments about high costs and low production rates sound very similar to those that I heard in energy conferences in the US not many years ago.  Signposts to watch include the number of drilling companies moving into the north of England and emulation of the UK government's pro-development policies by other countries.

A different version of this posting was previously published on the website of Pacific Energy Development Corporation.

Big Wind

Even with my long experience in an industry dominated by big structures and gargantuan flows of liquids, gases and power, I was impressed by the scale of last week's announcement awarding the third round of the UK's offshore wind licensing program. The 32,000 MW of wind turbines planned for installation in the waters around Britain over the next ten years or so would match the entire onshore wind capacity of the US, to date, while delivering perhaps a quarter more energy annually, because of their larger size and access to more reliable wind. With the UK facing a significant shortfall in generation and energy output, this isn't just about responding to climate change. Yet big wind won't come cheap, and it's worth spending a few moments putting its scale and cost in perspective.

Round Three of the UK Crown Estate's offshore wind bids dwarfs both the country's 4,000 MW of existing onshore and offshore wind capacity and its first two rounds of offshore licensing. When completed, the turbines in the nine offshore zones awarded last week would generate roughly the same amount of power annually as a dozen nuclear power plants, based on a 40% capacity factor, and considerably more when the wind is blowing strongly. That's directly relevant, because Britain's aging fleet of nuclear power plants is being phased out, and by the time the first of the new offshore wind farms is done, UK nuclear generating capacity could be less than half its current level of around 11,000 MW. If proposed new reactors are delayed or never built, the UK would be down to a single nuke by 2023. It's an interesting coincidence that some of the same companies from continental Europe that participated in Round Three are also involved in the nuclear new build proposals.

Unfortunately, the retirement of the UK's nuclear fleet coincides with the decline of the North Sea gas fields that have powered Britain's shift away from coal in the last couple of decades. The amount of electricity that the Round Three turbines would generate annually is equivalent to around 2.5 billion cubic feet per day (BCFD) of natural gas run through gas turbines. That equates to 38% of the 6.6 BCFD of gas the UK produced last year, or roughly the amount by which UK gas output has declined since 2004. That makes offshore wind a significant contributor to the country's energy supplies, but not the whole answer by itself.

Nor will big wind come cheap. At a reported £3.1 million per MW, the estimated cost for the Round Three build-out comes to almost £100 billion ($161 billion at current exchange rates) not counting National Grid's estimate of £10.4 billion to connect these new wind farms to the onshore power grid. It also doesn't count the substantial subsidies involved. In the UK, those come mainly from utilities--and ultimately power customers--via a system of tradable Renewable Obligation Certificates (ROCs) issued under the country's Renewable Obligation, which is similar to the renewable portfolio standards mandated by many US states. At present, offshore wind projects can earn 2.0 ROCs per MWh generated, though that could fall back to 1.5/MWh before some of these wind farms come onstream, creating some financial uncertainty. At the recent ROC value of £45, the winners of Round Three could be earning as much as £10 billion per year ($16 billion) from the sale of ROCs to utilities needing to meet their renewable quotas. With this subsidy factored in, the cost of the UK's big wind aspirations will run well over £200 billion over the next decade.

I can't help admiring all this as an engineering feat and demonstration of will, despite the enormous cost. It's a tougher call whether the US should be pursuing something similar. The UK has fewer energy options than we do, particularly for solar energy. You don't need maps of solar irradiation to know that it's not a very sunny place, and Britain gets points for not pursuing the kind of misplaced solar mania that Germany has. And with North Sea oil & gas in decline and no big surge of shale gas waiting in the wings, combining large-scale wind with nuclear looks like a sound energy strategy. At a minimum, the UK's plans demonstrate greater seriousness in dealing with energy more realistically than the US is able to manage. We can't even seem to differentiate between domestic vs. imported oil, and we've allowed the influence of a few wealthy residents to block the first offshore US wind farm for years. Big wind, with all its limitations of intermittency and non-dispatchability, might not be the answer here, but we need big something--probably big everything--and we had better get on with it. Our continued status as a global superpower ultimately depends on it.

What Europe Pays

With American consumers reeling from gas prices that have gone up by fifty cents per gallon since the beginning of the year, it occurred to me to wonder what Europeans are now paying. Although the decline of the dollar has amplified the impact of recent increases in oil prices, Europe hasn't been immune, either. Crude oil expressed in Euros or Sterling is roughly 75% and 110% higher, respectively, than it was in January 2007, and this has boosted the price of fuels that were already much more expensive than those sold here. While searching for European fuel price data, I was surprised to discover proposals for gas tax cuts similar to those being debated here. Consumer displeasure with petroleum product prices is increasing the pressure on governments on both sides of the Atlantic to respond.

Having lived in both Germany and the UK, I chose them as my basis of comparison--one inside the Euro zone, the other outside. As of today, Normalbenzin (regular gasoline) averages €1.457/liter, or €5.51/US gallon. So whether you assess the dollar/euro exchange at its market rate of $1.55 to the Euro--which gets you to $8.55/gal.--or adjust it based on purchasing-power parity, or even the Economist's Big Mac Index, which was close to 1:1 last summer, gasoline in Germany is a darned sight more expensive than it is here, thanks to Europe's stout taxation of motor fuels. And while diesel is taxed at a lower rate, to promote the use of diesel automobiles as a means of reducing oil consumption and greenhouse gas emissions, €5.26/gal. ($8.15/gal.) is hardly a bargain. Petrol is not much cheaper in the UK, either. At a current average of 110 pence per liter, or £4.18/US gallon ($8.25/gal.), even filling up your Mini would set you back $80.

Of course, it's not only the absolute fuel price that counts, but the magnitude and rate of its recent change. A big part of our problem is that most Americans are still driving cars that were purchased when gasoline was under $1.50/gal., to commute between work and home locations that were chosen when fuel was even cheaper. As of this week, nominal US retail gasoline prices have gone up by 25% in the last year and by 130% in the last five years. How does that compare to other countries? Well, motorists in the UK are experiencing prices that are now 25% higher than the average of last year, and 42% higher than five years ago, but gas hasn't been cheap in Europe for more than a generation. Buffered by the strong Euro, gasoline in Germany has increased by a smaller percentage, 19% vs. the 2007 average and 29% over five years.

Although proportional fuel-price increases have thus been smaller in Europe than here, the high absolute price level is still causing serious discomfort and prompting calls for governments to act, particularly by reducing fuel taxes. Consider that while it accounts for more than 70% of the US retail gasoline price, crude oil makes up less than a third of the gas price in Germany. Because most of the difference is attributable to taxes, the scope for reducing the retail price via tax relief is enormously greater than here. A member of the German coalition government has suggested instituting a cap on gasoline, diesel and heating oil prices, adjusting the tax rate periodically to hold prices steady. Other proposals include rolling back the 3% increase in the value-added tax that kicked in on 1/1/07, which at current prices is worth as much as the entire US federal fuel excise tax that Senators McCain and Clinton wish to suspend this summer. The arguments against lower German gas taxes are similar to those economists have raised here: fuel supplies will tighten even further, and government revenues will fall.

It's small comfort, but high gasoline prices are a global phenomenon, unless you live in a major oil exporting country, such as Kuwait or Venezuela. Consumers in Europe are no happier about this than we are. But instead of waiting for our governments to decide whether higher fuel prices or lower tax receipts are more harmful to the economy, we could follow the advice on fuel conservation from the Alliance to Save Energy. As reported in yesterday's Wall St. Journal, a combination of six strategies could save the average household up to $600 per year, or at least 20 times the expected benefit from a summer gas tax holiday. And instead of protesting in Washington, truckers might achieve more by posting "Slow Down" signs on our highways. Even the airlines are reducing aircraft speeds to save fuel.