Tuesday, January 22, 2013

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. 

Tuesday, January 15, 2013

Could Diesel Fuel Made from US Natural Gas Compete with CNG and LNG?

The announcement last month of a $21 billion project to capitalize on abundant, low-cost US natural gas should have caught the attention of everyone interested in this resource. As reported in the New York Times, Sasol, a South African energy company, intends to build a 96,000 barrel-per-day gas-to-liquids (GTL) plant in southwestern Louisiana, in conjunction with a new gas processing plant and ethylene cracker. The synthetic diesel fuel produced by this facility would provide a different pathway for shale gas to displace imported crude oil in the US transportation sector, in competition with compressed or liquefied natural gas (CNG or LNG.)

GTL involves a two-step conversion of the methane that makes up the bulk of natural gas into synthesis gas and hydrogen, which are recombined into liquid hydrocarbons by means of the decades-old Fischer-Tropsch (FT) process. GTL is also energy-intensive, with an overall efficiency around 60%. South African companies have vast experience with such synthetic fuels. Sasol are partners in the Oryx GTL plant in Qatar, and their coal-to-liquids plants in South Africa utilize a similar syngas step and the same FT process as GTL.

With the US suddenly perceived to be sitting atop a century's worth of natural gas, mainly in the form of unconventional gas from shale, tight gas formations and coal-bed methane, T. Boone Pickens isn't the only one to see an opportunity to displace imported oil with gas. Yet as attractive as that sounds for reasons of energy security and trade, it isn't obvious whether the public or even fleet operators are willing to switch on a larger scale to a lower-density gaseous fuel requiring both new distribution networks and new or modified powertrains. Only 0.1% of the natural gas consumed in the US now finds its way into vehicles, equivalent to less than 0.1% of US oil demand. Under the circumstances, it would be surprising if someone weren't looking seriously at GTL, one of the few practical ways to circumvent the mechanical and logistical barriers that have impeded the fueling of more US cars and trucks with natural gas.

When I read about Sasol's proposed project, I immediately thought of another, less well-known South African synfuels facility. Since 1992 the Mossel Bay GTL plant has been turning natural gas into gasoline, diesel and other fuels, drawing first on the Mossel Bay gas field and then on newer fields as the original one depleted. Although owned by another firm, the ongoing struggles to keep the "Mossgas" plant supplied are well-known in South African energy circles. I can't imagine Sasol embarking on a project like the one in Louisiana if they had any doubt about their ability to keep it supplied for decades.

Of course volume and price are two very different aspects of supply. A decade ago, conventional wisdom held that GTL required a gas cost of around $1 per million BTUs to be viable. Even with the shale bonanza today's US natural gas price is well above that level. What now makes it possible to conceive of GTL in the US is that the price of the crude oil used to make diesel and other fuels has risen so much higher than that of natural gas. That comparison is more obvious when one converts natural gas prices into their energy equivalent in crude oil. Today's US natural gas price is below the $23 per equivalent barrel that it was in 2001. Meanwhile crude oil has increased from about $26 to $95 per barrel. The drastically improved attraction of GTL becomes even clearer when comparing ten years of wholesale US Gulf Coast diesel prices to natural gas prices using the approximate GTL conversion rate of 10 million BTUs of gas per barrel of liquid product.

As the chart above reveals, this theoretical GTL margin has exploded since 2009. Yet it also shows that if gas prices returned to the levels we experienced just a few years earlier, the proposed project would encounter significant risks. Perhaps that helps explain Sasol's concept of a larger integrated gas complex with multiple sources of margin, capitalizing on the waste heat from the GTL process and the lighter hydrocarbons it yields as byproducts.

It remains to be seen whether GTL will prove an attractive means of leveraging the US shale gas revolution to back out imported oil. However, if Sasol and others proceed with US GTL projects, anyone eyeing our gas surplus for other purposes, whether in manufacturing, fertilizer production or power generation, would face serious competition linked to the global oil market. That includes potential LNG exporters, who passed an important hurdle with the publication of a favorable analysis by the Department of Energy.

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

Wednesday, January 09, 2013

Virginia's Gas Tax: Ending A "Dinosaur Tax"

I don't know if the Speaker of Virginia's House of Delegates intended a double entendre when he referred to the state gasoline tax that Governor Bob McDonnell (R) just proposed eliminating as a "dinosaur tax".  He was certainly correct that this tax is rapidly becoming outmoded as its capacity to keep pace with necessary infrastructure investment fades with every EV, hybrid, or other efficient car that's sold.   In the Governor's remarks, he referred to the gas tax as a "stagnant revenue source." In a low-tax state like the Commonwealth, shifting the tax burden for transportation away from fuel taxes and toward registration fees and a higher general sales tax represents an innovative, though also controversial answer to a challenge that has concerned me for some time. 

The scope of the underlying problem should be uncontroversial: Like most states, Virginia's $0.175 per gallon gasoline tax is a holdover from an era in which fuel sales grew in tandem with road use, and both expanded steadily year after year.  I can personally vouch for Northern Virginia's traffic congestion, cited in this morning's Washington Post story on this issue. As in most states, Virginia's gasoline sales have been flat to declining since the recession that began in 2008, while the value of the fixed fuel tax has been further eroded by inflation.  These trends seem likely to continue for years, with recent new-car fuel economy improving sharply. The gas tax simply can't cover the cost of repairing and extending Virginia's highways without a large increase now, followed by periodic increases as future fuel sales fall. 

A key aspect of Governor McDonnell's proposal that appeals to me is that it doesn't rely on high-tech monitoring or low-tech inspections of actual miles driven, like many of the other solutions I've examined.  Instead of trying to fix the fuel-tied tax, he would eliminate it entirely and shift revenue generation to a combination of higher annual fees, especially for alternative fuel vehicles that currently pay little or no road tax, and an increase in the Commonwealth's 5% sales tax to 5.8%.  0.5% of the current sales tax is already dedicated to transportation.  The proposed shift exchanges one regressive tax for another, in a manner that recognizes that all Virginians stand to benefit from improved transportation networks, whether they personally use them or not. 

The current Virginia gas tax costs an average motorist around $100 per year, based on 12,000 miles of annual driving.  The rise in the sales tax would generate comparable revenue from $12,000 of annual spending subject to the sales tax.  That likely equates to little or no tax increase for low-income drivers, and an increase of up to a few hundred dollars a year for the better-off, while still leaving Virginia's sales tax slightly lower than those in Maryland and the District of Columbia. Motorists would continue to pay the federal gasoline tax, currently set at $0.184/gal.

I can envision various objections to the Governor's proposal, including concerns that cutting the gas tax might increase gasoline demand--and emissions--and reduce the incentives for higher fuel efficiency.  That seems unlikely in the current context for at least two reasons.  First, eliminating the Virginia gas tax involves a reduction in pump prices of less than 5% of last year's average price in the region, and more importantly represents less than a quarter of the total range of gas-price volatility we experienced in 2012. Moreover, fuel economy improvements are already mandated under the new federal Corporate Average Fuel Economy regulations that will increase fleet-average miles per gallon to 54.5 mpg by 2025.  Cars will continue to become more efficient, no matter what gasoline costs.

It will be interesting to watch how this proposal fares in Richmond.  The Governor's party may control the House of Delegates and effectively the Senate, by virtue of a tie-breaking Lieutenant Governor, but 2013 is an election year, and Mr. McDonnell is barred by term limits from seeking reelection. I wish him luck with this idea, even though its enactment would probably result in a small net tax increase for my household. I'm sure other states will be watching, too.

Wednesday, January 02, 2013

A Late Christmas Gift for Renewable Energy

The US Senate's "fiscal cliff" package wasn't exactly eight maids a-milking--the traditional gift for the eighth day of Christmas--though it did apparently resolve the impending "milk cliff".  Of greater relevance, the "tax extender" portion of the American Taxpayer Relief Act of 2012 passed by both the Senate and House of Representatives represented a gift to renewable energy producers and developers worth around $18 billion.  Two-thirds of that is attributable to the extension and modification of the Production Tax Credit (PTC) for wind and other renewable electricity projects. Renewable energy technologies have gained another year of generous support from US taxpayers.  What remains to be seen is whether this win represents a last hurrah for the current US approach to renewable energy subsidies as lawmakers focus on shrinking an increasingly unsustainable federal budget deficit.

Based on the analysis of the bill provided in the Wall St. Journal, other energy-related beneficiaries  included producers of cellulosic and algae-based biofuels, blenders of conventional biodiesel and other alternative fuels, purchasers of 2- and 3-wheeled electric vehicles, as well as various energy efficiency investments including efficient homes and appliances.  Renewables should also benefit from other provisions of the bill, including a one-year extension of 50% bonus depreciation on project investments and a two-year extension of the 20% R&D tax credit. 

Of course the problem with all of this is that it sets up additional cliffs at the end of 2013 and 2014, and thus perpetuates the expiration-anxiety roller-coaster that has confounded both manufacturers and investors in these technologies. Part of the blame for that rests with the process by which the Congress drafts and enacts such legislation.  However, it's also a function of the unwillingness of current beneficiaries to shift their lobbying efforts to support realistic and predictable phaseouts of these subsidies, in light of renewables' improving competitiveness with conventional energy and the magnitude of future US fiscal problems.  Considering that the current PTC for wind power is worth the equivalent of about 90% of today's futures price for natural gas, a proposal by the wind trade association for a six-year phaseout ending at 60% strikes me as too much like St. Augustine's plea for chastity.

The high-pressure negotiations to avert the fiscal cliff provided a poor venue for producing genuine tax reform, while giving supporters of the status quo a golden opportunity to attach measures such as these "extenders" that couldn't be amended before the expiration of the current Congress.  The non-partisan Congressional Budget Office estimated that this bill actually increased federal spending by a net $330 billion over 10 years and added nearly $4 trillion to the deficit, compared to going over the cliff.  It's not clear that the even higher-stakes debt-ceiling debate slated for early in the new Congress will be any more conducive to solving these challenges. But whether then or later in the session, it's going to become harder to avoid some form of tax reform and spending discipline that considers all energy subsidies in the context of their direct costs and indirect revenues. I'll be surprised if the current subsidies for renewables can escape again without major adjustments to reduce their high effective cost per unit of energy produced and increase their long-term bang for the buck.