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.

Renewable Energy Faces the European Debt Crisis

With all the bad economic news and political turbulence in the US, it's been easy to lose track of the sovereign debt crisis in Europe, which appears to be spreading from smaller, peripheral countries like Greece to affect the banking systems of core European Union members like Italy and France. To read Paul Krugman's column in last Sunday's New York Times, Europe could be on the verge of another financial crisis on the scale of the one triggered by the collapse of Lehman Brothers in 2008. Aside from the global economic consequences of such an event, it would send ripples throughout the energy sector, affecting both conventional and renewable energy markets and participants. While such an outcome is far from certain, it's a worrying scenario to contemplate.

The 2008 financial crisis is a good place to begin looking for the implications of a potential 2011 credit crunch in Europe. Start with oil, which in the fall of 2008 slid from around $100 per barrel to below $40 by mid-December of that year. Of course oil prices had already retreated from a high of $145 that summer, as the weakening US economy and collapsing housing market slowed US demand for oil. Yet it's worth noting that despite their generally more efficient use of energy and higher consumer energy prices, the countries of Europe together import slightly more crude oil and petroleum products than the US does. And as I've noted before, the economies of the EU's Euro area have been partially sheltered from high oil prices by the strength of the Euro relative to the US dollar, in which most oil transactions are settled. Even without a full-blown financial crisis, a sharp drop in the Euro/dollar exchange rate resulting from sovereign debt worries would create a regional energy price spike that could further hamper the EU's growth and reduce its energy demand. OPEC appears to be preparing to trim output for just such an eventuality.

Next consider what happened to renewables, such as wind and solar power. Lending to renewable energy projects in the US dried up in late 2008, as credit became harder to obtain in general, and participants in "tax equity swaps" retreated. Without the generous renewable energy supports in the 2009 stimulus, wind turbine installations might have ground to a halt, and the expansion of solar manufacturing that has recently hit a rocky patch might never have occurred. European projects and suppliers weren't affected to the same degree, thanks to a combination of higher direct subsidies for renewables and robust lending from EU agencies such as the European Bank for Reconstruction and Development.

Those protections look less dependable in a new crisis. European governments have been busily cutting renewable energy subsidies, and growth is already slowing, squeezing local firms like Germany's Q-Cells between a weaker domestic market and low-cost import competition from China and elsewhere. It's anyone's guess whether commercial lending to the renewable energy sector and loans from groups like the EBRD could be sustained in another financial crisis focused on the Eurozone.

A sudden contraction in European funding for renewable energy projects would be felt around the world. Suppliers in the US and Asia have relied on European sales of wind turbines, solar panels and components for much of their planned growth, and the further decline in equipment prices that would follow a big demand drop would leave all but the best-capitalized, lowest-cost competitors scrambling. And even as renewable energy growth has shifted in recent years toward developing countries and away from North America and Europe, Europe has remained the most important market for many of these technologies--particularly for solar PV and offshore wind power--just as Europe has retained the strongest focus globally on reducing the greenhouse gas emissions implicated in climate change. Every aspect of the global energy business has a big stake in the success of Europe's leaders in navigating through the current crisis, but none more than the renewable energy sector.

Energy from All Around Us

It's somewhat ironic that the long-awaited approval of the Cape Wind offshore wind project by the Department of Interior (DOI) should come in the same week that the nation's attention is focused on the problems of another, more traditional offshore energy project. Although the renewable electricity from the former scarcely substitutes for petroleum from the latter, Cape Wind is nevertheless emblematic of an intentional shift from energy sourced far away, in places like the deepwater Gulf of Mexico, to energy derived from sources all around us. If Secretary Salazar had turned it down, it would have cast serious doubts on the administration's entire clean energy agenda. However, concurrence with this one project doesn't answer all questions concerning the larger shift, of which it represents just a small component. Similar issues are bound to come up with increasing frequency as the transition to new energy continues.

Cape Wind and the Macondo prospect that the Deepwater Horizon rig was drilling into represent opposite poles of the energy spectrum, and not just because the latter is now leaking oil into the marine environment at a rate that the latest estimate puts at 5,000 barrels per day, much higher than initially thought. Cape Wind would tap into the clean and renewable, but extremely diffuse energy sources that surround us. After taking into account the restrictions imposed by DOI, its 130 turbines would on average generate as much electricity as a gas turbine power plant consuming a quantity of natural gas equivalent to 6,000 bbls/day of oil. In other words, it takes a very large array of offshore wind turbines to match the energy in the oil currently leaking from a single well. Platforms similar to what BP might have been planning to install after successfully completing the exploration of Macondo routinely produce up to 20 times that much oil.

The implications of this huge difference in energy density are clear. Without the energy concentration that nature has embedded in fossil fuels over many millennia, the hardware required to tap natural energy flows in real time becomes vast in extent. Generating 20% of US electricity needs from wind, which some see as just the beginning, will ultimately require more than 8 times as much wind capacity as the 35,000 MW installed as of the end of last year, even if US electricity demand remains static in the interim. Solar power, which last year generated just 0.02% of our electricity, would have to increase by a much larger factor. This is one of many reasons that increased reliance on nuclear power is such an important element of the transition to more sustainable energy sources, because nuclear--and to a lesser extent geothermal power--represents a critical source of highly-concentrated, low-emission energy. The more nuclear in the mix, replacing baseload coal, the less we must rely on distributed energy gathered in our immediate vicinity.

In any case, in order to obtain a much larger portion of our energy diet from sources like onshore and offshore wind and solar power, projects like Cape Wind must go from being rarities to ubiquitous features of our seascapes and landscapes. The opposition to Cape Wind that has delayed this project for years is focused on a central dilemma of that shift: Many of the same underlying trends that lead us to want to harness clean energy from wind, sunlight and geothermal heat have also increased our focus on the broadly-defined environmental impacts of doing so.

Our grandparents wouldn't have blinked at putting up tens of thousands of wind turbines, let alone the few hundred slated for Nantucket Sound. They'd have thought of them as signs of progress, just as they viewed oil derricks and power lines. It's incumbent on us to balance our more modern sensibilities related to the "viewscape" with fundamental environmental challenges of climate change and sustainability, as well as the need to sustain the energy supplies our civilization requires. Approving Cape Wind--whether it eventually gets built or not--is entirely consistent with those imperatives.

It's Time to Let Virginia Drill

At last Thursday's Summit on Virginia's Energy Future in Richmond, Governor Robert McDonnell delivered a detailed talk on the state's energy opportunities and the bi-partisan commitment of the legislature and Virginia's US Senators and Congressional delegation to capitalize on them, including its offshore oil, gas and wind resources. He also declared his goal of making Virginia the "energy capital of the East Coast." While neither Virginia nor any of its neighbors up and down the coast seems likely to compete with Texas or Louisiana in total energy production, the new Governor's aspiration might be more than just wishful thinking. However, as the business and governmental leaders who spoke at the session made clear, Virginia doesn't control its own destiny in this regard. The Commonwealth's plans for tapping the value of those resources to help close its budget deficit depend on the cooperation of the US Department of the Interior (DOI), which controls the leasing and permitting process for exploration and development on the Outer Continental Shelf (OCS).

Attending the summit provided me with a much better appreciation of my state's energy situation. When we moved our family here nearly four years ago, I confess I didn't spend a lot of time thinking about local energy issues, beyond confirming that electricity was cheaper and likely to be more reliable than where we had lived in Connecticut. Although Virginia produces essentially no crude oil, it does have respectable quantities of natural gas and coal, a bit of hydro and biomass power, and is home to two nuclear power plants, each with two reactors. Unfortunately, like many states, Virginia's own energy production isn't sufficient to meet our needs, and we must import significant quantities of power, along with 100% of our petroleum supplies, either as crude oil for the single small refinery at Yorktown, or as finished products. Several speakers mentioned that the Commonwealth is second only to California in state electricity imports.

Also like many other states, Virginia faces a significant budget shortfall as a result of lower tax receipts, mainly due to unemployment that, while lower than the national average, is still well above pre-2008 levels. A consistent theme from the participants at the summit was that although Virginia's offshore energy resources don't appear to be large enough to make it energy independent, a share of the bid premiums, rentals, and royalties similar to that received by Texas, Louisiana, Mississippi and Alabama for their OCS resources under the GOMESA law of 2006 would be very useful in addressing state funding shortfalls, particularly for transportation. Together with the job creation and non-royalty tax revenue that would accompany development, the offshore resources constitute a very attractive economic proposition.

Estimates of potential resources included in Virginia's first lease area are around 130 million barrels of oil and 1.1 trillion cubic feet of gas. That's a lot smaller than the kind of deposits that have been found in the deepwater Gulf of Mexico, though as several speakers pointed out these figures are based on outdated technology and would likely increase significantly with current techniques. That's important because when the surveys underlying these estimates were done, the state of the art most likely wouldn't have found any of the big plays now being exploited in the Gulf or off the coast of Brazil. And even if any resources discovered were closer to the DOI's current estimate than the 800 or 900 million barrel upside potential that a couple of Thursday's panelists mentioned, it could still create a valuable stream of royalties and taxes for a medium-sized state. In addition to its oil & gas potential, coastal Virginia also has an excellent wind resource in the Class 5/Class 6 category desirable for offshore wind farms, with several firms indicating interest.

Having passed legislation declaring the Commonwealth's support for offshore development, along with a bill allocating resulting government revenues to transportation funding and renewable energy R&D, Virginia is, as the Governor put it, "ready to go." Under the previous US administration DOI included Sale 220 for Virginia's OCS in the 2007-2012 leasing program of the Minerals Management Service. That put Virginia in the first lease round for the Atlantic and Pacific coastal regions that had previously been subject to the expired offshore drilling moratoria. The sale was expected to occur in 2011. With appropriate revenue sharing in place, Virginia wouldn't have to wait for production to begin in five or more years, but could begin receiving bid premium and rental income as soon as the sale is held. Unfortunately, the current management of DOI has not exhibited much enthusiasm for advancing these plans. Virginia officials, including the Governor and our two US Senators, have contacted Secretary Salazar to convey the urgency of proceeding with the sale.

As I've noted on many occasions, the US still has significant undeveloped oil resources, and we're likely to need every barrel they can contribute in the years ahead as global demand grows. The Congressional and Presidential drilling moratoria that formerly blocked development on two of our coasts no longer apply, and it is in the financial and energy security interests of the nation to move ahead with development where the affected states support it. The clear message last Thursday was that it is now the official policy of the Commonwealth of Virginia to develop its offshore resources. By leasing Virginia's OCS oil and gas, DOI would turn the President's comments in support of offshore drilling in this year's State of the Union address into concrete action. That would produce immediate and long-term economic benefits for the state and local communities, while providing badly-needed revenue for the federal government. After decades of delay, there is no better time than now to move ahead with this.

FYI, I'll be traveling on business this week. Postings will likely resume Friday.

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.

2010 and Beyond

The start of my seventh year of blogging on energy and its related environmental concerns coincides with the start of a new decade, unless you're of the traditional school that believes the twenty-teens don't really begin until next January 1. Over the holidays I was struck by the number of retrospectives focused on the amply eventful, but profoundly disappointing decade that was ending. Having spent several years reassuring my readers that we weren't reliving the 1970s, in retrospect I'm not so sure. Yet as bad as the '70s were on so many levels, they gave birth to the '80s, which brought revitalization and tremendous technological developments, and culminated in the end of a Cold War that most of us had considered perpetual. There's cause for guarded optimism about the decade ahead, particularly for energy, which is still in the early stages of a massive transformation. The 'Teens will test the capacity of current energy systems to support a return to rapid economic growth and of new energy technologies to go from niche to mainstream.

I could fill the rest of this posting with grandiose predictions about the next ten years, but instead I want to focus on two stories that could provide early clues about energy in the crucial 2010-2020 period. The first almost escaped notice in the energy retrospectives I read last week. Many of them, including one in the Wall St. Journal, attributed the recovery of oil prices in 2009 mainly to the stabilization of the financial system, yet scarcely mentioned the essential role of OPEC's self-restraint. According to the figures in the latest public version of the International Energy Agency's Oil Market Report, between May 2008 and February 2009 OPEC reduced its output by more than 10%, taking well over 3 million barrels per day (MBD) off the market in response to a 3% drop in global oil demand. Despite the usual cheating on its official quotas, its members have avoided the competition for shares of a shrinking market that crashed oil prices from the $30s to $11/bbl in the mid-1980s and set up a decade of low oil prices.

In the process, OPEC's spare production capacity has expanded from less than 2 MBD to roughly 6 MBD. That's quite a buffer against a big price spike as the economy recovers, though it's also the reason oil isn't drastically cheaper than it is today. While we can't know precisely what would have happened if, for example, Saudi Arabia had tried to squeeze the output of its new, Texas-sized Khurais field into the market on top of its existing sales, it's a good bet that oil wouldn't be trading anywhere near its current $81/bbl. The reason this is relevant for the decade ahead is that OPEC could be forced to accommodate even bigger increases from the production agreements recently signed in Iraq, along with more reliable output from Nigeria, if that country's ceasefire with rebels in the Niger Delta leads to a lasting resolution of the problems there. With many of the world's best onshore oil prospects currently off-limits for anyone else to develop, OPEC's members and their continued cohesion hold one of the main keys to oil prices in this decade.

Meanwhile the growth of renewable energy faces a number of important tests as it expands beyond the scale at which it can be tucked safely out of sight and out of mind. We've already seen large solar projects in California's Mojave Desert--one of the most reliably sunny spots on the planet--canceled or relocated to accommodate concerns about wilderness preservation, and now I read that the long-suffering developers of the Cape Wind project off Cape Cod are at risk of having the project's location declared a Historic Site by the National Park Service. With all due respect to the local tribes that apparently consider Nantucket Sound to be sacred, it's worth recalling some of the other history of the region that ought to bear on such a finding. In its heyday Nantucket Island was the center of the global whaling industry, made possible by a fleet of tall-masted sailing ships that used wind power to harvest a key energy resource of the time, from the slaughter of whales for their oil. It's hard to think of a better way to recognize that history--and in a more environmentally-sound 21st century way--than by putting up offshore wind turbines to harness the wind for direct energy production.

And while the permitting for America's first offshore wind farm drags on interminably, the UK government is expected to announce the results of its Third Round of offshore wind bids this week. The new installations would add 25,000 MW of new capacity to a base of offshore UK wind farms in operation or under construction that is already about four times larger than that contemplated for Nantucket Sound.

Oil prices and the expansion of renewables are only two of many factors that will determine the shape of the world's energy economy in 2020, though they rank high on my list of things to watch as the decade begins. Tight oil supplies and high prices would do a lot to promote energy efficiency and new vehicle technologies, while lower, more stable prices might result in a return to the complacency we saw in the late 1980s and '90s. And although renewable power sources are hardly the only means for reducing greenhouse gas emissions and rendering our steadily-growing energy use more sustainable, much depends on the capability of wind, solar and geothermal power to continue their recent impressive expansion. That's true whether you are banking on cleantech and "green jobs" to turn around the US economy or merely interested in the size of the potential opportunity for our suddenly-ample natural gas supplies. I look forward to sharing my observations about these and other trends in the months and years ahead.

Offshore Wind Potential

Last month the Interior Department issued its framework for developing the offshore wind potential of the US Outer Continental Shelf (OCS.) In a speech on Earth Day Interior Secretary Salazar highlighted the enormous opportunity that offshore wind represents, tapping a perpetually renewable resource to provide large increments of low-emission electricity, particularly in proximity to the populous East Coast, where the National Renewable Energy Laboratory of the DOE has apparently identified a million megawatts of developable wind potential. Offshore wind could provide an important segment of the renewable energy growth necessary to reduce US greenhouse gas emissions and achieve the ambitious goals of the proposed federal Renewable Electricity Standard. At the same time, it's essential to put this potential into perspective, particularly if the development of offshore wind and offshore oil and gas resources should conflict in the future. While offshore wind offers a somewhat more reliable supply option than its onshore cousin, its energy contribution is still significantly less than that of the conventional sources it is intended to displace.

In remarks early in April Secretary Salazar suggested that a million MW from offshore wind would dwarf the power currently generated by coal-fired power plants. Last year the US generated just under 2 trillion kilowatt-hours of electricity from coal, from power plants with a combined capacity of 336,000 MW. Generating the same number of kWhs from wind at a typical average capacity factor of 33% would require nearly 700,000 MW of wind capacity. So if we ignored the distinction between baseload power and the intermittent output of wind turbines, we might say that the Secretary only slightly exaggerated the potential of offshore wind, which appears to be on roughly the same order of magnitude as coal. But this comparison becomes more suspect when you break down wind's potential contribution into realistic projects, such as the much-delayed Cape Wind project in Nantucket Sound. Cape Wind would consist of 130 turbines with a total capacity of 420 MW. Replacing coal with offshore wind would require no less than 1,642 offshore projects the size of Cape Wind. To put that in perspective, consider that the UK Crown Estate--roughly equivalent to our Minerals Management Service (MMS)--is currently evaluating 40 bids for projects totaling 25,000 MW, to add to the roughly 1,100 MW of offshore wind currently on line or under construction there. That would lead Europe's offshore wind sector. I'll let you draw your own conclusions about the feasibility of replacing coal power with offshore wind anytime soon.

Since the MMS will administer the new offshore wind leasing program in parallel to its long-standing oil and gas leasing on the OCS, we must trust that they also have a firm handle on the relative energy contribution of these resources and would factor this into any future offshore resource conflicts. Consider Cape Wind, again. The approximately 1.2 billion kWh of electricity its 420 MW should generate annually could displace gas-fired power generation consuming roughly 10 trillion BTUs of natural gas per year. That sounds simply enormous, until you convert it to barrel of oil equivalents (BOE). It works out to about 4600 barrels per day, about what a single well on an offshore oil platform might produce. Compare that to Chevron's new Gulf of Mexico platform, Tahiti, which just began production and is expected to ramp up to 137,000 BOE per day. (Disclosure: I am a Chevron shareholder.) Tahiti apparently cost $2.7 billion to build. Wind farms capable of producing a comparable amount of energy (via displacement of natural gas at a gas turbine heat rate of 8,000 BTU/kWh) would cost somewhere on the order of $25 billion.

Now, these comparisons are somewhat simplified, and I've completely ignored the greenhouse gas emissions from the conventional power plants that offshore wind would displace. However, there's no imaginable cost of carbon that could close the value gap between offshore wind and the energy and economic contribution of offshore oil and gas projects. While I'm not suggesting that offshore wind inherently conflicts with oil & gas, I do think it would be helpful for the administration to temper some of its hyperbole on renewable energy with the kind of pragmatic, numbers-based analysis of which the staffs at both the Interior Department and the Department of Energy are capable. Offshore wind promises to be a useful element of our future energy mix, but it is still a very long way from replacing the primary energy sources upon which we rely today.