US Strategic Gasoline Reserve: Solution or Band-Aid?

• The new Northeast Gasoline Reserve addresses some of the shortcomings of the current, 39-year-old federal emergency crude oil reserve, or SPR.
• Whether or not the DOE considered other options, the upcoming Quadrennial Energy Review provides an ideal opportunity to rethink our strategic energy stockpiles.

The recent announcement that the US Department of Energy (DOE) would establish a strategic gasoline stockpile to serve the Northeast was at least partly a response to calls for such a reserve in the aftermath of the fuel distribution problems caused by “Superstorm” Sandy in 2012. Secretary Moniz also framed it as part of a broader effort to beef up US energy infrastructure.

Although it is encouraging to see the DOE recognize the limitations of the current US Strategic Petroleum Reserve (SPR), I was disappointed that the new stockpile appears merely to copy the Clinton-era Northeast Heating Oil Reserve, in both quantity and approximate location, rather than reflecting a thorough rethinking of the entire concept of strategic fuel inventories, involving all stakeholders.

As I noted in a post here last summer, the crude oil SPR and its Gulf Coast facilities were envisioned and stocked for a different world of falling domestic oil production, rising oil imports–mainly through Gulf Coast ports–and US refineries that supplied only domestic customers. Yet while the SPR’s roughly 700 million barrels in storage should now last much longer in an emergency than they would have done in the previous decade, the reserve’s other shortcomings have grown as the US energy situation has evolved in the last several years.

For starters, it holds too much light sweet crude oil. Once in short supply, the US now has such abundant supplies of this grade, thanks to the shale production in North Dakota and Texas, that US refineries may eventually not be able to refine it all, without expensive upgrades or under-utilization of their costly conversion hardware.

The SPR's oil is also increasingly in the wrong place. While oil imports into the Gulf Coast have been falling rapidly, California now imports more than half its crude oil needs, with half of those imports sourced from the Middle East. The existing Gulf Coast SPR provides virtually no coverage in the event of a disruption in California’s supplies.

Finally, as became apparent in the wake of Sandy and of 2005′s hurricanes Katrina and Rita, a crude oil SPR provides little benefit if the refineries necessary to process its oil have been shut down by storms, electricity outages, or other causes. And more recently, the emergence of the US as a major net exporter of petroleum products raises questions about the extent to which SPR oil might be used to produce fuel for non-US customers.

The announced Northeast Gasoline Reserve represents a step towards addressing these shortcomings, positioning refined products near major markets. That avoids the possibility that refinery capacity might not be available when required, and it circumvents at least part of the distribution infrastructure–pipelines and ports–that might fail in a future Sandy-like emergency.

The title of the DOE’s press release also hints that the Northeast reserve might be just the first, with others to follow. Additional locations should be chosen with regard not just to today’s vulnerabilities, but those under a variety of future scenarios. However, while this decision moves in the right direction in several ways, it does not even address all the vulnerabilities highlighted by Sandy.

Sandy presented governments and consumers in the Northeast with both a shortfall of supply, from local refineries and long-distance product pipelines, and a massive failure of local infrastructure. Many distribution terminals had product in their tanks that they couldn’t deliver due to power outages, flooding or closed roads, while numerous gas stations were shut due to a lack of power to operate pumps and payment systems, product to sell, or both. Without addressing these local distribution issues, it is conceivable that the new gasoline reserve might contribute no more in a future emergency than the Northeast Heating Oil Reserve did after Sandy, supplying mainly first responders. While still useful, that would fall well short of the consumer benefits that the Senators from New York and Massachusetts seemed to be touting.

I also can’t help wondering whether the team at DOE that devised this measure considered alternatives such as those in use in Europe. The EU requires each member country to maintain 90 days’ inventory of oil and refined products and gives countries latitude in how to provide for that. In the UK, and as I recall at least several other EU countries, the responsibility for maintaining strategic stocks falls on the fuels industry. That approach offers significant benefits.

Aside from avoiding the need for governments to maintain idle inventory at taxpayer expense for many years, this option would also disperse fuel stocks across a much larger number of locations. That would reduce the risk that the strategic reserve facility itself might be incapacitated by the same event that triggered a call on its stocks, or might end up on the wrong side of temporary distribution bottlenecks.  It should also reduce the likelihood of an offsetting reduction in commercial fuel inventories, such as appears to have occurred in New England following the establishment of the Heating Oil Reserve in late 2000.

Putting the reserve in commercial hands would also help to ensure that the product maintained in strategic storage always meets current specifications, without the need for a complete turnover of the stockpile that occurred when the Northeast Heating Oil Reserve had to switch from ordinary to ultra low-sulfur diesel a few years ago.

These advantages, when combined with a rigorous auditing and oversight system, should compensate for the distrust that many consumers might feel for the industry as custodian of such a strategic reserve. I hope this option was at least given careful consideration before the administration decided to implement another federally owned fuel reserve.

The US Strategic Petroleum Reserve has been in place for four decades, and the Northeast Heating Oil Reserve for nearly 14 years. Much has changed since these stockpiles were justified and planned, to such an extent that it seems highly improbable that we would wish to implement them in the same way today, particularly in the case of the crude oil SPR. What should a state-of-the-art system of strategic energy storage consist of in 2014 and beyond? That’s the question I would expect the DOE to address with input from a range of stakeholders, including broad representation from the companies that produce and distribute these fuels under normal circumstances.

The press release announcing the gasoline reserve also mentioned the upcoming Quadrennial Energy Review, with its initial focus on infrastructure and participation by many parties outside government. While the composition and charter of that effort don’t appear to align with the needs of a major reform of the SPR system, it should at least be able to assess the fit-for-purpose of the current approach. It even invites public comment.

A different version of this posting was previously published on Energy Trends Insider.

Can Solar Fill the Hydropower Gap During California’s Drought?

• Although the scale of California's conventional hydropower remains much larger than that of solar power, solar's rapid growth provides a meaningful contribution to the grid.
• Solar power can work nearly anywhere, but installing it where it's actually sunny much of the time pays big dividends.

After reading a San Jose Mercury article with the unwieldy title, “Drought threatens California’s hydroelectricity supply, but solar makes up the gap” I was intrigued enough to do a little fact-checking on state-level  electricity statistics. The article quoted the head of the California Energy Commission, who implied that solar power additions were sufficient to make up for any shortfall in hydro, historically one of the state’s biggest energy sources. My initial skepticism about that claim turned out to be largely unfounded.

Solar has been growing rapidly, especially in California, but even with nearly 3,000 MW of photovoltaic (PV) and solar thermal generation in place, it’s still well short of the scale of California’s 10,000 MW of hydropower dams, especially when you consider that the latter aren’t constrained to operate only in daylight hours. However, I also know better than to respond to a claim like this without checking the data on how much energy these installations actually deliver.

My first look at the Energy Information Administration’s annual generation data seemed to confirm my suspicions. In 2012 California’s hydropower facilities produced 26.8 million megawatt-hours (MWh), while grid-connected solar generated just 1.4 million MWh. However, when I looked at more recent monthly data, the mismatch was much smaller, due to solar’s strong growth in the Golden State. For example, in September 2013 California solar power generated 435 MWh, or nearly 24% of hydro’s 1.8 million MWh.

The potential drought benefits of solar stand out even more sharply when we compare the growth in solar generation to the change in output from hydro. Last year solar electricity in the state increased by 2.4 million MWh, compared to 2012, while hydropower fell by 2.3 million MWh. That added solar power won’t provide grid operators the same flexibility as the lost hydropower, because of its cyclical nature, but it is clearly now growing at a rate and scale that makes it a serious contributor.

I’d be remiss if I didn’t point out that solar in California is still nowhere near the scale of the state’s biggest electricity source, natural gas generation, which in 2013 produced over 100 million MWh, or 57% of the state’s non-imported electricity supply. Gas is also filling much of the roughly 18 million MWh shortfall left by the early retirement of Southern California Edison’s San Onofre Nuclear Generating Station last summer, and if the state’s drought worsens, gas will be the main backup for further declines in hydropower.

Yet solar’s growing contribution to the state’s energy mix provides a clear demonstration that while generous state and federal policies can make installing PV economically attractive nearly anywhere, it’s abundant sunshine like California’s that makes it a useful energy source, especially when drought conditions reduce the output of other, water-dependent energy supplies.

A different version of this posting was previously published on Energy Trends Insider.

As US Oil Production Revives, New Vulnerabilities Appear

• The expansion of US oil production is centered in a handful of states, and in particular two whose gains more than offset declines in two former production leaders.
• For various reasons the West Coast has missed out on this revival, straining infrastructure and creating new vulnerabilities that should be addressed.

On the front page of today's Wall St. Journal I see that "US Rises To No. 1 Energy Producer." This news builds on a number of recent headlines such as, "US oil production reaches highest level in 24 years." Stories like these aren't as attention-grabbing as they were when this streak began more than a year ago, once shale oil production ramped up dramatically.  What occurred to me this time, however, was how different the current distribution of US oil output is than it was in the late 1980s.

A handful of states still account for the lion's share of US oil production. Then and now, Texas tops the list, exceeding its 1989 output by 37%. At nearly 2.6 million barrels per day (MBD) in the most recent reported month --140% above at its low point in 2007--its share of US oil production had grown to around 35% by June. However, beneath Texas  the list of top oil states has been jumbled in ways few would have anticipated two decades ago.

Alaska, California and Louisiana, the second-, third- and fourth-ranked producers in 1989, then supplied 41% of total US crude oil output. After decades of decline, the same three states now contribute just 17%, excluding production from the federal waters off Louisiana's coast. Meanwhile, thanks to the development of the Bakken shale, North Dakota has jumped from the number  6 spot just five years ago to number two, eclipsing Alaska early in 2012.  Traditional mid-tier producers like Colorado, Oklahoma and New Mexico are also contributing to the overall US oil revival. This surge of highly productive drilling in roughly the middle third of the country, on top of a million-plus barrels per day from the Gulf of Mexico --mainly from deepwater rigs--has scrambled existing oil transportation arrangements.

When onshore production in Texas and the rest of the mid-Continent shrank in the 1990s and 2000s, the region's pipeline network gradually evolved into the country's principal oil-import conduit. The growth of production in the federal waters of the Gulf of Mexico, which had reached 1.6 MBD at the time of the Deepwater Horizon accident in 2010 but subsequently declined to about 1.2 MBD, meshed well with that model.

Today's big challenge goes against that grain: moving the growing surplus of oil in the upper plains states to markets on the West, Gulf and East Coasts, increasingly by rail. Much of the turbulence we've seen in the US oil market  in the last two years reflects the delays inherent in realigning and expanding that network to accommodate newly abundant domestic supplies.

Yet on the other side of the Rockies, the picture looks very different. When I was trading crude oil for Texaco's west coast refining system in the late 1980s, balancing the crude oil surplus on the Pacific coast required shipping multiple tankers a month of Alaskan North Slope oil to the Gulf, where production was shrinking, and prompted the construction of a new pipeline to send surplus oil to east Texas over land. After two decades of decline from mature fields, along with moratoria on tapping new offshore fields, imports now make up roughly half of west coast refinery supply, even though regional petroleum demand is essentially back to 1989 levels. It remains unclear whether and when California will allow producers to tap the state's potentially game-changing oil resources in the Monterey shale deposit.

Barring further change, the regional nature of these shifts means that the energy security benefits accompanying the revival of US oil production are a party to which the West Coast has not been invited, or has perhaps declined the invitation. That's significant, because it leaves residents of California, Oregon, Nevada and Washington much more exposed to any disruptions in global oil trade, since the existing US Strategic Petroleum Reserve was never intended to provide coverage west of the Rockies. In this light, the appetite of west coast refiners for trainloads of Bakken and Eagle Ford crude looks strategic, rather than just a temporary response to market conditions.

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

Early Retirement of US Nuclear Plants Is a Step Backward

• The early retirement of the San Onofre reactor complex could increase California's greenhouse gas emissions by up to 6 million tons per year.

• Together with other announced and plausible retirements, the loss of existing US nuclear capacity would more than offset new reactors now under construction, along with their contribution to emissions reduction. 

Last month Southern California Edison announced that the utility’s San Onofre Nuclear Generating Station (SONGS), consisting of half of California's nuclear generating capacity, will close permanently.  The facility had nine years remaining on its operating license. The plant’s two reactors were shut down for repairs in early 2012, and the Nuclear Regulatory Commission (NRC) still hadn’t approved the company’s plan to restart them, despite a protracted review. Although this event is less dramatic than the 2011 Fukushima accident in Japan, its ripples are likely to extend beyond California, where both the state’s electricity market and its greenhouse gas emissions will be adversely affected.

Before considering how the San Onofre closures will affect the nation’s nuclear industry and generating mix, let’s focus on California. While accounting for only 3% of the state’s 2011 generating capacity from all sources, the SONGS reactors typically contributed around 8% of the state’s annual electricity generation, due to their high utilization rates. That’s a large slice of low-emission power to remove from the energy mix in a state that is committed to reduce its emissions below 1990 levels.

How much emissions will increase following the shutdown depends on the type of generation that replaces these units. If it all came from renewable sources like wind and solar, emissions wouldn’t go up at all, but that’s impractical for several reasons. Start with the inherent intermittency of these renewables, and then compound the challenge by its scale. Even in sunny California, replacing the annual energy contribution of the SONGS units would require around 7,200 MW of solar generating capacity, equivalent to nearly 2 million 4-kilowatt rooftop photovoltaic (PV) arrays. That’s over and above the state’s ambitious “Million Solar Roofs” target, which was already factored into the state’s emission-reduction plans.

Grid managers from the state’s Independent System Operator indicated that in the near term much of the replacement power for SONGS will be generated from natural gas. Even if it matched the mix of 71% gas and 29% renewables added from June 2012 to April 2013, based on “net qualifying capacity”, each megawatt-hour (MWh) of replacement power would emit at least 560 lb. more CO2 than from SONGS. That’s an extra 4 million metric tons of CO2 per year, or 8% of California’s 2010 emissions from its electric power sector and almost 1% of total state emissions. If gas filled the entire gap, or if the natural gas capacity used was not all high-efficiency combined cycle plants, the figure would be closer to 6 million metric tons, equivalent to the annual emissions from about 1.5 million cars.

The SONGS shutdown brings to four the number of nuclear reactors that have been closed permanently this year, reducing the operating US nuclear power plant fleet to 100 units. Several other plants face severe challenges, including the ongoing legal battle over the “certificate of public good” for Vermont Yankee, strong local opposition to the Pilgrim unit on Cape Cod, and a hotly contested license renewal process for the two Indian Point units near New York City. The early retirement of San Onofre can only embolden the opposition to other nuclear plants.

A few years ago, when the nuclear power sector planned a large new-build program in the US, it seemed reasonable to assume that most existing plants would easily obtain 20- or 30-year license extensions, in line with well-established precedent. That would carry the bulk of the fleet into the 2040s and beyond. Meanwhile, new construction would add many gigawatts of new capacity and enable nuclear power to gain market share against coal and gas. However, between a recession that stalled the growth of US electricity demand and the low natural gas prices brought about by the combination of the same recession and the shale gas revolution, the economics of new nuclear power in the US have become tenuous. Some operators have even canceled relatively low-cost “uprate” projects to increase capacity at existing plants.

As part of its Annual Energy Outlook for 2013, the Energy Information Administration (EIA) of the US Department of Energy looked at various scenarios for nuclear expansion or retrenchment. In addition to the four reactor retirements announced this year, Exelon Corp. has already announced that its Oyster Creek plant in New Jersey will shut down in 2019, after 50 years of operation. If the two Indian Point units were also shut down, then total retirements since 2012 would reduce US nuclear generating capacity of 101,400 MW by more than the 5,580 MW combined capacity of the five new reactors currently under construction and scheduled to start up by late 2018. The difference of around 650 MW would likely be made up by natural gas.

Between now and 2020, despite the first new nuclear power plants in a decade coming on-line, nuclear’s contribution to our energy mix won’t grow by much, and may actually shrink. That will have consequences for consumers and for efforts to reduce greenhouse gas emissions. Retiring fully depreciated power plants that still have many years of potential operating life remaining, and replacing them with new generation of any technology, is bound to increase the cost of electricity in the markets where these plants have operated. And even if the net loss of nuclear capacity were directly replaced with high-reliability renewable generation such as hydropower or geothermal, that’s still that much renewable capacity not available to displace higher-emitting generation. Opponents of nuclear power may see that as progress, but it looks like a step backward to me.

A slightly different version of this posting was previously published on Energy Trends Insider.

Will California Be the Next Big Shale Oil Play?

I've spent the last couple of weeks contemplating California's Monterey shale, which has been widely discussed recently as the country's next Bakken-style oil play, or even bigger.   The Bakken shale has turned North Dakota into the second-biggest oil-producing state in the US, at the same time that development of the Eagle Ford shale has been shoring up Texas's claim to the number one spot.  So far, The Golden State has largely missed out on the shale revolution, despite having shale oil resources estimated to exceed the rest of the US combined. The scale of the opportunity makes it an intriguing subject, but I find it particularly interesting, because the Monterey is deeply intertwined with the long history of the California oil industry, in which I spent the first half of my career. 

The Monterey shale is hardly a new prospect.  One of the first documents my search turned up was a 1905 USGS report on its fossil content, noting its oil potential.  First production from this shale apparently occurred a decade earlier.  Moreover, it appears that the Monterey formation, which underlies many of the state's conventional oil fields, is actually the "source rock" for those fields: the zone from which the hydrocarbons trapped in their reservoirs originated.  So the estimated 400 billion barrels or so of original oil in place in the Monterey have presumably already yielded a substantial share of the roughly 29 billion barrels of oil that California's oil fields have produced to date.

Development of this play doesn't just lag shale projects elsewhere because of California's well-known environmental sensitivity.  The geology of this deposit also differs significantly from that of the Bakken and other east-of-Rockies shale plays, partly due to its relative youth, as well as the effects of the Golden State's seismic activity.  Its oil-bearing strata are thick and often jumbled up by past earthquakes. One expert characterized this as signifying that the Monterey wasn't a "resource play" but a "structural play."  So unlike the Bakken or Eagle Ford, individual wells carry higher risks of failing to yield commercially useful output.  It also makes it less likely that steady efforts in the Monterey will result in an easily replicable recipe for unlocking the entire deposit. 

That brings us to fracking, which is surely as controversial in California as anywhere, even though, as in many other locations, it's been done safely and with little fanfare for decades.  The state recently announced preliminary fracking regulations, but this may have less impact on development of the Monterey shale than one might suppose.  That's because this formation seems to be less amenable to fracking, or at least to the combination of horizontal wells and multi-stage fracking that's been a game-changer elsewhere. Other techniques, such as acid injection, may prove more useful.

However it is eventually unlocked, the Monterey shale offers significant benefits to California.  Start with the fact that the state's oil production has been in steady decline since the mid-1980s. Together with the depletion of Alaska's North Slope field, that has meant that the US West Coast, which was once a net exporter of oil, now imports increasing quantities of oil--half of it from OPEC--to meet local demand.  That trend has continued even as the import dependence of the rest of the country has fallen substantially due to higher production and receding demand.  The Monterey could slash California's imports, while adding billions of dollars a year to the local economy and to the shaky state budget, along with lots of good jobs.

It could even provide environmental benefits. Restoring oil self-sufficiency would reduce the risk of spills from the tankers bringing in imports, while refilling existing infrastructure.  And if the Monterey yields oil similar in quality to the light, sweet crude now being produced from the Bakken and Eagle Ford shales, it could actually cut both greenhouse gas emissions and local pollution by reducing the refining intensity required to turn the state's current diet of heavier crudes into ultra-low sulfur gasoline and diesel fuel. 

I suspect from my research in the last few weeks that anyone betting on an imminent explosion of oil output from the Monterey shale is likely to be disappointed.  The process seems likely to be slower than elsewhere, though with a bigger potential payoff.  But that doesn't make it irrelevant to a state that has set its sights on being at the forefront of the transformation to cleaner energy sources.  California still consumes 1.8 million barrels per day of petroleum products, and it will burn many more billions of barrels on its way to its chosen future of electric vehicles running on wind and solar power, and trucks and buses burning compressed or liquefied natural gas. Developing the Monterey shale won't solve all of California's energy challenges and might create a few new ones, yet it could prove another timely contribution from a local oil industry that has been a major driver of the state's economy for well over a century. 

Sacramento's Role in California's Gasoline Price Spike

How much higher were gasoline prices in California last week than elsewhere?  Enough to raise the national average price for unleaded regular by about $0.10 per gallon.  So while the rest of us were paying an average of $3.75/gal., down slightly from the previous week, gas prices in the Golden State went up by 48 cents, leaving Californians paying nearly a dollar a gallon more than other Americans.  In general the media have done a good job of explaining the direct causes for this spike: a pair of unexpected outages at large refineries in the Bay Area and L.A., combined with the difficulties of supplying the state's unique gasoline blend when local refiners fall short.  Robert Rapier does an even better job of explaining the intricacies of that blend.  But what's missing from all this commentary is an explanation for why the supply for the nation's largest gasoline market, with more than 11% of US sales, should be so tightly balanced that such disruptions would lead to economic hardship for consumers.

As I've indicated before, California is effectively a gasoline island. The product pipelines connecting it with neighboring Arizona and Nevada run out, not in, and the only routes between California and the other West Coast refining center north of Seattle travel over water.  So the principal refineries serving the California market are in California, and obtaining supply from elsewhere that hasn't been prearranged takes time for special batches of fuel to be blended up, tankers to be chartered, and for those vessels to complete their voyages from ports as far away as the Gulf Coast or Singapore.  That entails at least a couple of weeks.

In a posting I wrote in 2007 during a similar price spike in California, I referred to a 2003 study by the Energy Information Agency of the US Department of Energy, looking at an earlier California gasoline spike. (This is a recurring problem.) Among the major factors explaining the higher prices and volatility of the California gasoline market, they found,

"The California refinery system runs near its capacity limits, which means there is little excess capability in the region to respond to unexpected shortfalls."

That also means that there is typically no local surplus from which to rebuild inventories once refinery production returns to normal.  That's a crucial factor in the speed at which prices return to normal.

So much for the diagnosis, but what about the cause?  Tackling the local pollution from large, stationary sources like oil refineries, and from the tailpipes of the state's 31million cars and other vehicles has been a top priority for the state's Air Resources Board (CARB) since the 1970s, for good reason.  However, over the years, CARB's increasingly strict regulations made it harder and less attractive to operate refineries in the state, and more difficult to blend the fuel it allowed to be sold there.  As it happens, I saw much of this first-hand when I worked as an engineer in Texaco's Los Angeles refinery and later when I traded refined products, crude and feedstocks for the company's West Coast operations in the 1980s and early '90s.  I watched one small refinery after another go out of business, and the magnitude of periodic price spikes grow, as the market became more constrained and isolated. I also saw refining margins for the survivors improve relative to those on the Gulf Coast and other parts of the country.  These trends seemed related, since the state, by its actions, was turning California gasoline into a boutique product and effectively blocking competition from outside the state.

The normal response of companies operating in a market such as that, with growing demand and healthy margins, would have been to invest in more capacity--new refineries or major refinery expansions--and collectively to overshoot somewhat.  But by then the prospect of obtaining the permits necessary to build a new refinery in California had gone from difficult to impossible, and most refining investment was focused on the substantial upgrades required to keep up with the state's periodic tightening of product specifications.  And since those investments generally did little to increase output or improve product quality in ways a consumer might notice and pay a premium for, they had awful returns and dragged down the total return on investment for the entire facility. This contributed to refineries shutting down or being sold to independents with less capacity to make further such investments in the future. 

The net result of all these factors is a California refining system that today is 21% smaller than in 1982, at least in terms of crude processing capacity, but must meet gasoline demand that has grown by a third in the meantime, even after shrinking from its 2006 peak.  Now, when an unplanned refinery outage occurs, the result provides as classic and dramatic a demonstration as you'll ever see of the price response to a shift in the supply curve for a good with inelastic demand.

As an ex-Californian and ex-Angeleno there's no doubt in my mind that air quality, especially in Southern California, has improved as a result of many of the regulations imposed on industry and on fuels.  However, you'd have to ask the state's current residents whether that result is worth the high price they periodically pay at the gas pump, or whether some degree of compromise that would have allowed refineries to expand to keep pace with demand, while cleaning up the air almost as much, would have been preferable. 

Should the US Become An Oil Exporter, Again?

Last week I missed attending a fascinating panel on the growth of US oil production, hosted by  the New America Foundation in Washington, D.C. Fortunately, I was able to catch most of the live webcast, which is still available for replay. Much of the discussion focused on the potential of new "tight oil" production techniques, similar to those used to extract shale gas, to help usher in a new period of relative oil abundance.  If this comes to pass, among other things it could challenge long-established views about exporting US oil.  The politics of oil exports look absolutely dire at the moment, but the economic and logistical benefits--not just for oil companies but to the nation--are such that we shouldn't dismiss the possibility lightly.

Two hours was not enough time to do justice to all the ramifications of resurgent US oil production, and I know from following the Twitter feed for the event that some in the web audience were frustrated by the limited attention given to the climate implications of these developments.  However, if you'd like an overview of the possible economic and geopolitical impact of the US becoming more self-sufficient in petroleum for at least the next decade or two, this stellar panel was highly informative and worth your time.  Much of the discussion focused on tight oil, liquid hydrocarbons trapped in rocks that can't be economically tapped by conventional drilling, but that have proved susceptible to combinations of horizontal drilling and hydraulic fracturing similar to those that have unleashed the current shale gas boom. Although the full potential of this resource hasn't been reflected in the latest forecasts from the Energy Information Agency (EIA) of the US Department of Energy, the results from the Bakken shale in the Dakotas and the Eagle Ford shale in Texas are instructive.  Together these two fields now produce around 750,000 barrels per day, or 12% of current US crude oil output, up from just a trickle a few years ago.  They also hold billions, and possibly tens of billions of barrels of recoverable resources.

I was a little surprised that the first panelist to mention the possibility of exporting some of this oil--with appropriate caveats--was Adam Sieminski, the newly confirmed EIA Administrator. After all, current US law restricts the export of most US crude oil production, with special exceptions for some oil from Alaska, California, and near the Canadian border.  In practice, crude exports from those fields have declined to very low levels.  Despite that, and even after significant reductions in imports since the onset of the recession, the US is still a major net oil importer.  If that's the case, and if US refineries can benefit from the increasing domestic output, why would we even consider exporting any of this new oil?

Unfortunately, the answer doesn't reduce to a neat soundbite; it depends on two key factors that require a bit of explanation.  The first issue is the quality of the oil coming out of these tight oil plays, which at least so far has been very high. Oil from different fields varies as much as fingerprints, even when we consider only a few characteristics of concern to refiners, and these differences strongly influence the market values of the various grades of oil.  Light crudes refine easily into valuable products like gasoline, diesel and jet fuel, while heavier crudes require more processing, using more expensive hardware, and often yield large quantities of low-value products like petroleum coke, even after intensive refining. There's also sulfur content--the sweet to sour spectrum that overlays the light/heavy distinctions--as well as other impurities.  Eagle Ford crude is light and sweet, as is the North Dakota Sweet crude produced from the Bakken. These crudes compare favorably with West Texas Intermediate (WTI), Brent and other premium crude streams.

The second, related factor involves the complexity of US oil refineries and the crude diet they've evolved to run. As production of high quality crudes in the continental US declined over the last four decades, many refiners invested billions of dollars to enable their facilities to run some of the heaviest, most sour crudes from around the world, because these were more readily available and usually significantly cheaper than the light sweet crudes.  This trend was particularly evident on the West Coast and Gulf Coast. The addition of complex processing hardware like hydrocrackers, delayed or fluid cokers, and residuum fluid catalytic crackers has given these refineries tremendous flexibility, but it also increased their operating costs and made it harder for them to go back to a diet of much lighter crudes.  As a result, while many of them could handle significant quantities of light crude from the tight oil fields, this would be less than optimal, resulting in economic penalties and perhaps eroding the advantages that have recently enabled gulf coast refiners to capitalize on export markets for their products. Those penalties would translate into discounts for the tight oil grades, compared to similar international crudes, much like the large gap in value we currently see for WTI compared to Brent, though for different reasons as discussed previously.

At current production levels, the mismatch of quality and capabilities isn't as big a problem as the lack of infrastructure for transporting these crudes to market.  That has resulted in discounts so large that it makes sense for private equity firm Carlyle to plan to ship large quantities of Bakken crude by rail from North Dakota to the Philadelphia refinery they've just acquired from Sunoco.  However, if tight oil output grows in line with forecasts such as those in a recent analysis from Citibank, domestic sweet crude refiners will have more than enough supply and the excess must either be sold to heavy crude refineries at a discount or left in the ground.  That's where exports come in. 

The last time exporting domestic crude became a big issue was in the late 1980s, when output from Alaska's North Slope (ANS) field reached peak levels of roughly 2 million barrels per day, far more than west coast refineries could absorb. I was trading crude on the West Coast at the time, and I observed first-hand the effects of the export restrictions that had been put in place when the Trans Alaska Pipeline was originally approved.  Those restrictions didn't just depress the price of ANS crude; they also depressed the price of the California crudes with which ANS competed, and made both types less attractive to produce. West coast consumers benefited from a few years of lower gasoline prices than they would have otherwise paid, but the net result was less industry investment and probably higher oil imports in the long run.  By the time ANS exports were finally approved in 1996, the field was already in decline and the biggest opportunity had been missed. 

The advantages of allowing a portion of these new tight-oil streams to be exported would derive from the difference between the global market premium for crude of this quality and the typical discount paid for the lower-quality crudes that gulf coast refiners would continue to import in order to optimize their product yields and costs.  A difference of just $5 per barrel across a million barrels per day of exports would translate into a nearly $2 billion per year improvement in the US trade balance.  The benefits might also include higher tax revenues and royalties if exports supported higher production.  The biggest drawback I see is that in the event of a global supply disruption, some domestic crude would be committed to non-US buyers, reducing our emergency cushion.  However, that problem might be circumvented by requiring exporters to include provisions in their contracts allowing them to suspend deliveries whenever the US government released oil from the Strategic Petroleum Reserve, or a similar contingency.

Perhaps the best summary of the benefits that US oil exports could provide was given by President Clinton, when he authorized exports from the Alaskan North Slope: "Permitting this oil to move freely in international commerce will contribute to economic growth, reduce dependence on imported oil and create new jobs for American workers."  It's probably premature to provide a similar exemption for tight oil now, but it's certainly not too soon to start the national debate that should precede such a decision.

What Would It Take for Gas to Hit $5 per Gallon?

After returning from a business trip to California, I don't find media speculation concerning the possibility of $5 gasoline later this year quite as far-fetched as I might have last week. Perhaps seeing $4.299 per gallon posted for unleaded regular on many street corners there, compared to $3.699 or so here, gave me a touch of "availability bias" even if I also understand that gasoline taxes in the Golden State are a full 29¢ per gallon higher than in Virginia, and that environmental regulations there make it very much more difficult for refineries to produce fuel that meets California's specifications. Without dwelling on regional differences that could make $5 gas likelier in some places than others, I thought it might be worth spending a moment considering what it would take to reach that level on a national average.

In a situation such as the current one, as I described a few weeks ago, it comes down to crude oil prices. Calculating the oil price implied by $5 gasoline requires backing out the other key components of the pump prices we observe. Start with federal and state taxes, which according to API averaged 48.8¢/gal. in January. (That's only a snapshot, because many states include sales taxes that change in proportion to the overall price level.) You also have to subtract the retailer/distributor margin, which is typically around 15¢/gal. That leaves $4.36/gal., or roughly $183 per bbl, for pre-tax wholesale gasoline. But we still have to account for refining margin, or more accurately the spread between wholesale gasoline and crude oil, since a true refining margin would include the influence of a range of other products and byproducts like diesel, jet fuel, lubricants and petroleum coke. In 2010, before the Cushing crude bottleneck depressed West Texas Intermediate prices to the extraordinary degree we've seen in the last year, the average difference between gasoline and light crude futures on the New York Mercantile Exchange was $9.67/bbl. Knock that off the above calculated wholesale price and we get an implied price for light sweet crude of just under $175/bbl.

As of today, Louisiana Light Sweet and UK Brent, the best current indicators for this kind of crude, stood at $127 and $126, respectively, while poor old WTI languished at $109. So based on the above calculation, $5 gasoline would require world oil prices to rise by about $50/bbl--or more if you back-calculate from last week's average US gas price of $3.72/gal. Short of the saber-rattling in the Persian Gulf turning into a shooting war, it's hard to see that happening without the kind of economic conditions that took oil close to $150/bbl in 2008. That experience also suggests that if we reached $5/gal., the event might be short-lived as the shock waves it would cause undermined the economy and thus the fundamentals of oil prices.

Unlike Tom Kloza of Oil Price Information Service, I will not don a clown suit if the average US price of gasoline reaches $5 this year. However, I would be very surprised, barring the outbreak of hostilities between Iran and the US or Iran and Israel, a global or self-imposed boycott of Iranian oil exports, or a sudden, unexpected problem in another major producing country. Whether that makes predictions of $5 gas "hyperbole", as Mr. Kloza apparently suggested, or merely the result of failures to do the math, I leave for you to decide.

Gas Taxes and Price Divergence

Rising gasoline prices got my attention pretty forcefully this weekend when I filled up our rental car in South San Francisco, at the end of a short holiday trip to California. I expected to pay a bit more than usual near the SFO airport, but $4.439 per gallon for unleaded regular was a jolt, because prices in Northern Virginia, where I live, have been hovering at or under the $4 mark. This served as a reminder that while I have tended to focus in my writing on the average US gasoline price, local and regional variations can be significant, and their effect can amplify the economic impact of high oil prices in markets like California, where the unemployment rate is still in double digits. Most of these differences in gas prices can be attributed to taxes, which some would like to see increased further, to promote energy security.

As in so many other aspects of life, California provides a laboratory for testing the effect of higher gasoline taxes, for which I've been seeing a growing number of calls, lately. As of January 2011, the Golden State's gas tax was 18 ¢/gal. higher than the national average and 28 ¢/gal. higher than I pay in Virginia. However, that's not the whole story, because California effectively taxes gasoline twice: once by means of the state and local taxes collected at the pump and again via regulations that make it difficult for refiners to blend gasoline to the state's strict fuel specifications, and even harder for local refiners to expand output. The combination of these explicit and implicit taxes cost Californians on average an extra 29 ¢/gal., compared to the national average gas price over the last five years. That works out to about an additional $140 a year per car based on typical usage and fuel economy. That's not enough to provide a big incentive to buy hybrid or electric vehicles, but it surely puts a dent in the purchasing power of low-to-middle income residents.

Nor have alternative fuels been of much assistance in reducing this premium. If anything, the economics of ethanol have contributed to higher gas prices in California. That's because the state's few ethanol plants are capable of producing only about 16% of the roughly 1.5 billion gallons of ethanol blended into California's gasoline annually, based on 10% of sales. The rest must be shipped in by rail, mainly from the Midwest, with significant freight costs.

The key question in terms of supporting a higher national gasoline tax is whether California's higher existing gas tax has actually reduced fuel consumption, compared to the rest of the country. Based on Energy Information Agency statistics, 2010 gasoline sales in the state were 7% lower than in the peak year of 2006. That's more than twice the 3.3% reduction the entire US experienced in the same interval. Of course there are many other factors at work in that comparison besides gas taxes, including the large difference in unemployment cited above, the disproportionate exposure of California consumers to falling home prices, as well as variations in population growth and other demographic factors. Teasing apart all those influences is beyond the scope of this blog. But even if we attributed half of the additional reduction to fuel taxes, I question whether the result is large enough to justify the resulting drag on the economy, if conservation were the only goal.

Based on this simple analysis, California's higher gasoline taxes appear to have at least contributed to reducing gasoline consumption, although they also increase the financial burden on the state's consumers, especially at times of high gas prices such as we are currently experiencing. That was noticeable even from a single fill-up of my relatively thrifty rental car. What they don't seem to have done, despite raising billions of dollars for state and local government, is to have had a discernable impact on the state's financial health or the condition of its roads, compared to other states with lower gas taxes.

Tell California No

One of the most eagerly-awaited environmental decisions of the year is currently in the hands of the new Administrator of the Environmental Protection Agency. California has requested a waiver under the Clean Air Act to regulate CO2 as a pollutant from cars, based on the Supreme Court decision in Massachusetts v. EPA that confirmed that the EPA had the authority to regulate greenhouse gases. When I examined this issue in late 2007, I expected California to prevail in its request, and I still do. That doesn't mean, however, that there are not compelling reasons why it shouldn't. I can't think of a better signal the Obama Administration could send concerning the new federal direction on climate change than telling California, "Thanks for keeping the torch burning, but we'll take it from here."

There are two good reasons to turn down California's request to regulate tailpipe emissions, which would result in a de facto standard for Corporate Average Fuel Economy (CAFE) much more aggressive than the federal standard enacted by the Energy Independence and Security Act of 2007. The first reason is unlikely to gain traction, because frankly this boat has already sailed. I mention it only because I still believe it has merit. Simply put, based on engineering principles, the Supreme Court was wrong to designate CO2 as a pollutant, and any extension of the Clean Air Act (CAA) to cover it is based on a misunderstanding of the origins of this greenhouse gas.

Although it's widely accepted that CO2 emissions are a primary cause of climate change, that doesn't make CO2 a pollutant. Too much CO2 is bad, but then so is too much water, if you are drowning or standing downstream of an approaching flood. That doesn't make water a pollutant. CO2 emissions are not the result of a fuel impurity or a byproduct of combustion in engines and boilers, like the smog-forming pollutants the CAA was designed to regulate. It is a fundamental, inescapable consequence of all combustion and many natural processes, and the vast majority of it is recycled into plants and rocks, or dissolved in the oceans. The steady accumulation of the small remaining excess in the atmosphere creates the central problem in global warming. Unfortunately, we can't eliminate CO2 from car exhaust with filters, catalytic converters, additives, or more intensive fuel refining, but only by changing the way cars use energy, and by changing the way we use cars. That goes well beyond any reasonable interpretation of the intent of the CAA, though I suspect this point is no longer of any concern to policy makers.

What ought to be of great concern to policy makers is another, more pragmatic reason to turn down California's request, and by extension that of the thirteen states that wish to opt in to the California standard. Climate change is a global problem, and the science of predicting its local consequences is still in its infancy. Managing our greenhouse gas emissions must ultimately be addressed globally. Until that happens, they need to be tackled at the largest level of aggregation available, because the consequences of climate change will affect us all, directly or indirectly, and because the industries and consumption patterns involved in reducing emissions are so fundamental to the economy. Changing them will require resources and innovation on a national scale. I know that California is larger than many countries--I used to trot this point out regularly when I lived there--but that does not alter the nature of its connection to and interdependence with the rest of the country. In particular, while California has a few bits and pieces of the US car industry, in the form of an assembly plant or two, some parts suppliers, and design centers, the primary impact of its regulation of CO2 would be felt not in the Golden State, but in states such as Michigan, Ohio, Kentucky, Alabama and North Carolina. The effect on interstate commerce and the absence of overridingly unique local impacts should put regulation of CO2 explicitly within the purview of the federal government, not the various states.

A little more than a year ago I reluctantly conceded that California's desire to regulate CO2 from cars was justified by application of the notion of "lead, follow, or get out of the way," in the absence of any immediate prospect of the federal government's taking that lead with respect to climate change. The election has drastically altered those circumstances. It is inconceivable that the Obama Administration, with strong majorities in the Congress, will fail to enact sweeping federal measures to address climate change urgently and aggressively. It looks very likely that we'll have cap & trade within the next year or two, and if tighter CAFE standards are part of the solution--though I remain skeptical of their efficacy without a strong price signal to drive consumer behavior--they should cover the whole country, not just a few states. If we want Detroit to invest in emissions-reducing technologies, then it must have a national market for them. It ought to be instructive that Europe has done precisely that with a tailpipe emissions standard for the whole EU, not member by member.

Administrator Jackson has promised an "impartial review" of California's request, complete with public hearings. Her decision should follow the public comment period that will apparently end April 6. I hope that her finding will signal the end of a long period in which states were forced to blaze the trail on climate change, but can now yield leadership back to the federal government that must speak with one voice in the negotiations toward a global climate agreement in Copenhagen, this December.

Calling Solomon

Since the passage of California's AB 32 legislation establishing a cap on greenhouse gas emissions, the state has been locked in a struggle with the federal Environmental Protection Agency over the implementation of its provisions on tailpipe emissions. The Supreme Court ruling in Massachusetts v. EPA was expected to pave the way for California to obtain the Clean Air Act waiver it sought, to regulate automotive CO2 emissions--and effectively fuel economy--at the state level. Yesterday, however, the EPA denied California's petition, setting up a court fight that could well find its way back to the Supreme Court, unless the 2008 Presidential Election resolves the matter, first. Both sides are at least half-right, and I don't envy those who will be called to discern where the greatest service to the national interest lies. In the end, I believe California will prevail.

California's argument for the waiver is straightforward. The Supreme Court has ruled that CO2 is a pollutant, and California has been granted waivers in the past to regulate pollutants more stringently than the country as a whole. Moreover, California's greenhouse gas emissions are large enough to matter on a global scale, and the state's elected representatives believe they have a mandate from their constituents to address those emissions aggressively and comprehensively. Failure to do so would contribute to the risk of adverse outcomes from climate change in California, with some pointing to reduced precipitation and coastal erosion as early indicators of such damage.

But while my heart is with California in this matter, my head is with the EPA. Even if we accept that CO2 is now recognized as a pollutant--the logic of this escapes me, but I concede my minority status--it still does not result in the kind of direct local impacts that provided the self-evident justification for granting the state's past waiver requests concerning regulation of the "criteria pollutants" that affect air quality and produce smog. Climate change is a global problem, the local ramifications of which cannot yet be predicted reliably. With the US struggling to maintain its competitive edge in a global marketplace for goods and services, should we really desire the further Balkanization of auto and fuel standards?

Both sets of arguments are legitimate and compelling. Where I believe the EPA's case fails is in the implied responsibility of turning down California's request. If there were a similarly comprehensive set of federal greenhouse gas regulations in place or waiting in the wings--even if it was not as stringent--the EPA would be right to ask California to follow the federal government's lead. Yet the energy bill provisions cited by the Administrator in defense of his decision don't constitute such a plan. Unless and until something like the Lieberman-Warner Bill, S.2191, passes, the closest thing we have to a national greenhouse gas regulation is an array of voluntary programs. And as the Washington Post pointed out, a list of states accounting for nearly half the nation's cars has lined up behind California, rather than the EPA.

There's an old saying, "Lead, follow, or get out of the way." The last year has seen the publication of an impressive collection of reports on the science of climate change and on the economic consequences of ignoring the problem or tackling it head-on. These reports, including three from the same Intergovernmental Panel on Climate Change (IPCC) that shared this year's Nobel Peace Prize with Mr. Gore, underline the urgency of the issue and provide the real underpinnings of California's waiver request. On these grounds and with the precedent of Mass. v. EPA, I believe the high court will ultimately find in California's favor, but time is wasting in the interim.

The Twelve Days of Bali

I have been following with great interest the news out of Bali, where the thousands of delegates to the 13th Conference of the Parties to the UN Framework Convention on Climate Change have been meeting. Unlike the session in Kyoto ten years ago, the meeting in Bali is not intended to deliver a new climate treaty, but rather the guidelines for another couple of years of negotiations on an agreement to pick up where the Kyoto Protocol leaves off at the end of 2012. As such, the concluding statement out of Bali on Friday may not be terribly dramatic, unless the next couple of days produce a breakthrough on the issue of binding emission reduction targets. Although I disagree with its authors' interpretation of the data, a Wall Street Journal op-ed critical of the whole process asks the right question about the Bali outcome, in terms of how it will relate to an objective assessment of the success or failure of Kyoto.

The authors suggest that if Bali produces a framework that is little more than a bigger version of Kyoto, it will fail. They base this conclusion on their assessment that most of the countries that agreed to reduce emissions have fallen short of their commitments, at least at this point, and that where reductions have occurred, they resulted mainly from factors unrelated to the Kyoto targets and their implementation mechanisms, such as emissions trading and the Clean Development Mechanism. There's more than a grain of truth to this, but I believe reality is more complicated, and that Kyoto has not been an unmitigated failure. At a minimum, it has served as a global focal point on climate change, and the template on which national emissions reduction efforts--and of states such as California--have been based. Absent Kyoto, it's hard to imagine the same impetus for action.

As to the performance against Kyoto's targets, it is not as bad as often portrayed. However they get there, the EU has a reasonable chance of achieving its target of 2012 emissions that are 8% below what its member countries emitted in 1990. By the end of 2005 its emissions were already 1.5% lower than 1990 for the core 15 nations that signed Kyoto, and almost certainly lower than they would have been, had they not undertaken any of these measures--though one might argue about whether the process has been as efficient or the cost/ton of the cuts as low as possible. Even in the US, which did not ratify Kyoto and has so far avoided a firm commitment on reductions, our 16% growth of emissions since 1990 (14.5% taking the 2006 result into account) is well below the status quo projections I saw in the late '90s, which anticipated emissions growing by around 30%.

The Achilles heel of Kyoto, as most skeptics are quick to point out, is its treatment of the large developing countries. The growth of emissions in China alone, in just the last five years, has been larger than all the cuts that Kyoto asked of the EU and US combined. Nor is there any reason to expect that China's rate of emissions growth is about to turn negative, any time soon. Simply increasing the severity of cuts required of the Kyoto-compliant developed countries and adding the US and Australia to that list seem unlikely to attain the underlying goals that are being discussed in Bali, of ensuring that total global greenhouse gas emissions begin falling within 10-15 years, and that the rise in average temperature does not exceed 2 degrees Celsius.

If a bigger version of Kyoto is insufficient to the task, then what do we need? There are plenty of opinions out there, but I will be encouraged if the 12 days in Bali end with a charge to the negotiators of the details that is flexible enough to allow them to address the widely disparate political and economic circumstances of the world's nations, and particularly of the largest emitters. The key success criterion ought not to be its fit with our preconceptions about the relative importance of emissions cuts, technology transfer, and other key elements, but whether it results in a framework that can be implemented and enforced across all the big emitters, offering a realistic expectation of actually working, not just satisfying our notions of equity.

Zero Net Energy

An article in today's San Francisco Chronicle provides another example of California taking the lead on connecting energy and environmental policies. The state's Public Utilities Commission wants to require developers to build homes so energy efficient that they will require no net energy from the grid by 2020. This is consistent with the state's goal of drastically reducing greenhouse gas emissions, and it would also shrink the infrastructure burden associated with adding six million additional residents between now and then. Timing is sometimes as important as substance, however. It would be hard to imagine a worse time to impose such a potentially expensive new requirement on the housing sector.

As my regular readers know, I'm hardly unbiased about California, having spent three-fifths of my life there, including my entire education. Californians have long believed that they are about 10 years ahead of the rest of the country, and that what you see there today, you will see everywhere else eventually. It's probably more accurate to say that California represents a useful testing ground for new ideas, giving the rest of us a preview of some of their consequences, intended and unintended. Not all of these experiments have turned out well, as evidenced by the state's botched electricity deregulation a few years ago, and the impact of unregulated immigration on a massive scale.

The concept of zero-net-energy housing has much to recommend it. The technology to do this is certainly available, at least for homes in an area with as benevolent a climate as California's. It also makes a lot of sense to incorporate features such as solar roofs, extra insulation, and efficient appliances into original construction, and thus into the mortgageable purchase price of a home. A decade ago, my Texaco colleagues and I suggested that this was the most logical way to implement distributed generation technologies such as home fuel cells, including long-term supply contracts for the natural gas these devices would use. But whether it's fuel cells or solar panels, they are easier to incorporate into a house when it is built than as a retro-fit, and the economics work better, too.

Unfortunately, timing matters. You would have to be living under a rock to have missed the implications of the sub-prime mortgage crisis for home construction in California, one of the worst-affected states. Putting a major new requirement such as energy self-sufficiency onto developers at this juncture looks like a recipe for failure. The engine of easy credit and bootstrapped home equity from strong, steady appreciation has stalled and gone into reverse in California, where home sales are down and property values are declining. No one knows how long this situation will last, but it could take the California housing bubble years to deflate and return to normal growth.

I don't fault the PUC for wishing to align California's large housing sector with the state's overall emissions and efficiency targets. Floating this proposal now seems a bit tone-deaf, though. Hopefully, the California Energy Commission and the legislature will take a bigger-picture view and shelve this idea until conditions become more propitious. That shouldn't affect existing incentive programs for solarization and efficiency, nor would it preclude developers from packaging these systems as selling features. After all, there's nothing wrong with this idea, other than making it mandatory. In the meantime, California should seek big emissions reductions in less distressed sectors, since all such cuts are equivalent in their impact on climate change.

States' Rights

Today's Washington Post included a remarkable op-ed on climate change policy. The Republican governors of two states in which I resided for about 80% of my life are asking the federal government to lead on climate change or get out of their way. In their first sentence they use the word "malfeasance" in their assessment of inaction. This is strong stuff, indeed, particularly coming from members of President's own party. However, the ironies involved here are dwarfed by the prospect of fragmenting our response to this serious global problem into 50 little pieces, or even a few regional blocs or "coalitions of the willing." Climate policy is a poor application of the principle of states' rights.

The strongest arguments in the governors' op-ed rely on the facts and statistics of greenhouse gases, rather than the precedent of previous waivers for state action under the Clean Air Act. And those facts make it abundantly clear that we are dealing with a problem of global emissions, not local pollution. While I can appreciate their frustration with the time required for a federal response to emerge--and the emissions that are accumulating in the meantime--I don't believe we can create a cohesive approach to climate change one state-house at a time. Worse, this could lead to a truncated national response, in which federal leaders defer to the states, but the states never reach unanimity in their actions.

That doesn't mean the states are wrong about the urgency of action. We must have a comprehensive federal policy on climate change, at least, and preferably on energy and climate change, since the two are so connected. But the time when it was useful for states to experiment with local measures, the results of which could be weighed for inclusion in federal policy, is passing. We don't need regional cap-and-trade mechanisms to know that this is a leading option for the country as a whole to reduce its emissions. Nor do we need 10-state tailpipe rules to tell us that any federal response to climate change that ignores the contribution of personal transportation will fall short.

As I described last week, the Administration has served up an ambitious renewable-and-alternative fuel standard and a cabinet-agency planning process. The former is a solution to something--though not necessarily climate change--while the latter is being interpreted as foot dragging. The focus now shifts to the Congress, where legislation on climate change is making its way through committee. Although Governor Rell's and Governor Schwarzenegger's op-ed was addressed to the Executive Branch, it now falls to the Senate and House to address their concerns, while acting to prevent the balkanization of US climate change policy

Gasoline Island

Yesterday’s posting grew too long to include a relevant current example of the side-effects of California’s environmentally-driven de-industrialization. While retail gasoline prices across the US have jumped by 30 cents/gallon since January, prices in California are up by 50 cents, averaging $3.07/gallon for unleaded regular last week, with a few stations charging over $3.50. Before outraged consumers clamor for another investigation of collusion and gouging, though, they might consider what previous investigations have concluded: fundamental structural problems make the California gasoline market unusually vulnerable to local refinery outages. As a Marin County paper recently put it, “the state is like an island.” That was already true when I traded West Coast refined products for Texaco in the late 1980s.

Two minutes of Googling yielded a 2003 study by the Energy Information Agency of the Department of Energy, prepared at the direction of the Congress to assess that year’s California gasoline price spikes. It includes a nice graph showing that from 1995-2003, gasoline prices in the Golden State were consistently higher and more volatile than the national average. In addition to the unique problems of switching from MTBE to ethanol that year, the EIA identified the following contributing factors:

• California’s distance from alternate gasoline supplies
• The complexities and higher cost of producing gasoline to California’s unique, environmentally-oriented specification (CARB), especially when switching from winter to summer formulations.
• California’s over-extended refining system, which has not expanded as fast as gasoline demand.

The last point is particularly important, because it has a strong influence on price volatility. Since normal demand keeps these facilities running near capacity, California refiners must plan carefully for annual plant maintenance, lining up supplies from outside the state to cover anticipated shortfalls. But when something unexpected happens, such as the recent fire at Chevron’s Richmond refinery, more imports are needed, and they are typically weeks away, depending on whether product is available from Seattle-area refiners, the Gulf Coast, Europe or Asia. In addition, once refinery production returns to normal, there is no large, local surplus from which to rebuild the inventories that help to dampen price swings.

While the media has generally been doing a better job of reporting these issues than they used to, NBC News’s coverage on Monday included an interview in which an official of the Automobile Club of Southern California blamed “speculators” for pushing the price up. In fact, it is this normal spot market price response that enables California to attract supplies from other, more distant markets. A refiner in Texas, for example, must recoup the cost of blending a tanker-sized batch of gasoline--worth over $20 million--to California’s stringent specifications, plus freight, plus enough profit to cover the risk that prices will have fallen again, by the time the cargo is discharged a couple of weeks later. Without a significant price differential between the California and Gulf Coast spot markets, no cargoes would be forthcoming.

All of this ultimately flows from decisions taken decades ago by state and local air quality regulators to control air emissions (plain old pollution, in those days) by tightening up on stationary sources--including refineries--and requiring carmakers to install better smog equipment and refiners to make cleaner-burning fuel. What they didn’t do was ask consumers to buy more efficient cars. As a result, California consumers routinely pay the higher cost of making CARB gasoline, and whenever local supplies are disrupted, they pay extra for the lack of a capacity cushion.

As I’ve suggested in the past, this is still not a bad deal for Californians. Before these regulations really took hold, air quality in the state’s big cities was very poor, especially in the Los Angeles Basin. California consumers sacrifice a little of their material standard of living at the gas pump—about 23 cents per gallon more than the rest of the country, on average since 2001—in exchange for cleaner air. Going forward, as I discussed yesterday, they will sacrifice a little more to address climate change, with benefits that won’t be nearly as immediate or noticeable. It will be interesting to see what happens to the level of consumer complaints.

The Green Coast

Sunday's Washington Post reported on a decision by the Premier of British Columbia (BC) to back down on plans to build two coal-fired power plants in the province, while aligning with California to meet ambitious green energy and climate change goals. This move follows a series of state-level energy and climate initiatives within the US, putting states and regional blocs in the lead on this issue. Although much less populous, BC, with its large hydropower resources, makes an interesting partner for California and other western states wishing to pursue green electricity, but like them, it will have to reconcile these measures with the over-arching challenge of enabling continued economic growth for their expanding populations. The California example is both half full and half empty, in this regard.

California boasts some impressive statistics on energy and emissions. The state's per capita electricity consumption is among the lowest in the US, and it has remained essentially flat over a long period, with total consumption increasing at roughly the same 1% rate as population since 1990. A benevolent climate is certainly a factor, but even after including petroleum consumption--a major consideration for a state with over 30 million cars--average per capita energy consumption is a third less than the US average. Greenhouse gas (GHG) emissions have followed a similar path and compare favorably with those of other states and countries on emissions per $ of GDP. After accounting for the emissions associated with electricity imported from neighboring states, California's total GHG emissions grew by about 15% between 1990-2004, while population grew by 20%, resulting in a slight decline in per-capita emissions. However, the US as a whole did almost as well over the same period, with emissions up by 16%, and population increasing by 18%.

California has shown it can create a successful economy that is less dependent on energy inputs than the rest of the US. And although reducing GHG emissions wasn't the goal when all this was set in motion, that has been an important result of the state's consistent environmental policies since the late 1970s, which emphasized reducing stationary sources of pollution. Ahead of much of the nation, California shifted away from heavy manufacturing and toward the technology and service sectors, which use less energy and create fewer emissions of all types. BC seems to be following a similar path to California's, as its manufacturing and natural resources production decline in importance, and services grow, so they make a compatible partner in building a larger "Green Coast."

But now things get more difficult. If California’s GHGs continued to track population growth, then meeting the legislated target of restoring them to their 1990 level by 2020 would require an absolute reduction of about 40%, relative to where they would otherwise be in 13 years. That’s a tall order, particularly since most of the reductions from changing the economy are built into the statistics above. Once you've done that, it's hard to repeat, and the remaining "low-hanging fruit" becomes rarer and hangs higher. Requiring compact fluorescent light bulbs will yield another couple of percent (2/22/07), and initiatives like the Million Solar Roofs Bill will help, too, though California's electricity sector is already quite efficient, in greenhouse gas terms.

The state generates nearly half its power from low-emission sources such as hydroelectricity, other renewables and nuclear. Natural gas-fired power plants, which emit half as much as coal, account for another 47%. Because it is already so efficient, extracting further savings will likely be more difficult and expensive. The richest lode of potential reductions here is those attributable to imported power from coal, which are larger than those from the state's own generating fleet, but this, too represents a one-time opportunity.

It would be easy to look at these statistics and suggest that California--and by inference, BC--is unlikely to meet its stated goals on emissions reduction. Instead, I think they render a necessary experiment that much more challenging. If climate change is as serious a problem as it appears, the Green Coast is blazing a trail that we must all soon follow. If they succeed, it will bode well for the rest of us. If they fail, then it will imply that we must either institute more painful measures, or simply focus on adapting to a warmer world.