US Energy Under Trump

• President-Elect Trump and his appointees plan a major policy and regulatory shift for energy, focusing more on economic benefits and less on environmental impacts.
• Obama-era regulations most at risk of roll-back are those justified mainly on climate concerns not shared by Mr. Trump and his team.
• Emissions are still likely to fall in the next four years as shale and renewable energy output grow. 

Next week's presidential inauguration will trigger the biggest policy and regulatory shift for the US energy industry in at least ten years. That's how long it has been since energy policy was set by a Republican president and Congress. Donald Trump is a different kind of Republican, though, and his goal does not seem to be a return to scarcity and high energy prices. What should we expect, instead?

To gauge how sharply the energy polices of the incoming Trump administration will diverge from those of the last eight years, we need to understand what motivates both leaders. The Obama administration's approach was driven by a deep, shared conviction that climate change is the most important challenge the US--and world--faces. The cost of energy and its impact on the economy became secondary concerns, subordinated by the belief that the added cost of climate policies would be offset in whole or part by the benefits of the green investment they unleashed--remember "green jobs"?

We saw this in President Obama's first year in office. Amid a deep recession he worked with Congress to attempt to limit greenhouse gas emissions by means of an economy-wide cap-and-trade system, on which he had campaigned. The House of Representatives passed the Waxman-Markey bill (HR.2454), a veritable dog's breakfast of economic distortions. Yet despite a filibuster-proof majority in the Senate in 2009, Waxman-Markey and every subsequent cap-and-trade bill died there.

That failure set in motion the agenda that the Obama administration has pursued ever since, to achieve via regulations the emissions reductions it could not deliver through comprehensive climate legislation. Last year's publication of the EPA's final Clean Power Plan was a key component of an effort that seems set to continue until just before Inauguration Day.

The transformation of energy regulations under President Obama was dramatic enough that a transition to any Republican administration would be a big change. The transition now in prospect will be even more jarring. Mr. Trump's rhetoric and his choices for key administration positions point to a concerted effort to unravel as many of the Obama-era regulations affecting energy as possible. That isn't just based on philosophical differences over regulation and markets. For President-Elect Trump the economy and jobs are paramount, so the Obama energy regulations must look like an unjustifiable threat to the fossil fuel supplies that still meet 81% of the nation's energy needs.

Despite that, it is unlikely the new administration will go out of its way to target renewable energy or the tax credits that have driven its growth to date. Renewables are becoming increasingly popular with conservatives. However, because Mr. Trump sees climate change as, at best, a secondary issue that may not be amenable to human intervention, his administration's won't put renewables on a pedestal as the Obama administration has done.

The biggest challenge for renewable energy may come from tax reform intended to make US companies and factories more competitive globally and shrink the incentive for them to relocate to lower-tax countries. This appears to be a high priority for the new White House and Congress, and one on which they broadly agree. If corporate tax rates drop, the value of the tax credits renewables enjoy is likely to fall, too, making wind, solar and other such projects less attractive and less competitive.

It remains to be seen how many of the Obama energy regulations can be rolled back. The most recent regulations might be averted through legislation like the Midnight Rules Relief Act, or the REINS Act, both of which would update the Congressional Review Act, a rarely used 1990s law intended to limit what presidents could impose by last-minute executive actions. Other regulations may eventually stand or fall as the courts rule. The stakes are high, particularly for regulations affecting the production of oil and gas from shale by means of hydraulic fracturing and horizontal drilling.

Energy independence was a touchstone of Mr. Trump's candidacy. Despite his campaign's focus on coal, it is fracking, as hydraulic fracturing is more commonly known, that holds the key to achieving that goal in the foreseeable future. It has been the main driver of the growth in US energy production since 2010.

The latest long-term forecast from the US Energy Information Administration (EIA) puts energy independence within reach--in the sense of the US becoming a net exporter of energy--by 2026 or sooner. However, the recent flurry of regulations affecting such things as drilling on federal land, and putting large portions of US waters off-limits for offshore drilling would not have been part of that projection. As EIA Administrator Adam Sieminski remarked at a briefing on the forecast, "If you had policy that changed relative to hydraulic fracturing, it would make a big, big difference to everything that's in here."

That's a key point, because most past notions of energy independence assumed that energy prices would have to be very high to promote lots of efficiency and conservation and stimulate large amounts of expensive new supply. The shale revolution changed that.

However, the global context is also changing. OPEC is attempting to reassert its control over the oil market, with help from non-OPEC countries like Russia. Two years of low oil prices shrank global oil and gas investment budgets by around a trillion dollars, and the International Energy Agency has warned of coming oil price spikes as a result. Forestalling tighter US regulations on fracking and offshore drilling increases the chances that US supplies could grow by enough to balance shortfalls elsewhere and avert much higher prices at the gas pump.

Energy infrastructure is likely to be another focus of the new administration, because the economic and competitive benefits of abundant energy will be diluted if, for example, Marcellus and Utica shale gas or Bakken and Permian Basin shale oil have to be exported because domestic customers don't have access to them.

That suggests an early effort to reverse decisions by the current administration to block the construction of various pipelines, starting with the Keystone XL pipeline and more recently the Dakota Access Pipeline. That will force new confrontations with activists and environmental organizations that have raised their game to a new level in the last eight years.

Such opposition would likely intensify if the new administration sought to withdraw the US from the Paris climate agreement, which recently went into effect, or submitted it for review by the US Senate as a treaty. But it's not clear that a big change in direction would require leaving Paris.

The US commitments at Paris, like those of the other signatories, were voluntary and non-binding. For that matter, recent shifts in US energy consumption and especially electricity generation have put the US in a good position to meet its initial Paris goals with little or no additional effort, as noted by outgoing Energy Secretary Moniz. The Paris Agreement will only become a major point of contention if President Trump chooses to make it one.

In his list of the top energy stories of 2016, fellow blogger Robert Rapier rated the election of Donald Trump ahead of the OPEC deal and many other important events of the year, based on its likely impact on "every segment of the US energy industry." In retrospect that was equally true of Barack Obama's election in 2008. The shift we are about to experience on energy will be that much sharper, because President Obama and President-Elect Trump both set out to make big changes to the status quo for energy, in opposite directions. We shouldn't miss one important difference, however.

The course that Barack Obama's administration followed on energy was largely predictable from the start, because it was based on openly and deeply held beliefs about energy and the environment. Donald Trump's well-known preference for deals over dogma sets up the prospect of some big surprises, in addition to what we can already anticipate.

Condensate Pries Open the Oil Export Lid

•  A US ruling to allow limited exports of condensate, a light hydrocarbon mix similar to light crude oil, has implications for both producers and refiners, though not consumers.

• Whether or not it leads to wider US exports of condensate and crude, it signals just how much the US energy situation has changed since the oil export ban was first imposed.

Last month we learned that the US Commerce Department gave two US companies permission to export condensate that would otherwise be trapped here under a 1970s-vintage ban on US oil exports. This validates the view, as described in a white paper from the office of Senator Lisa Murkowski (R-AK) earlier this year, that the administration has the statutory authority necessary to allow such exports. An entire session at this week's annual EIA Energy Conference was devoted to the details of this ruling, and whether it paves the way for broader exports of a growing US surplus of condensate and light sweet crude oil.

Over the past several decades US refineries invested an estimated $100 billion to enable them to process the increasingly heavy and sour crude oil types available for import. As a result, most US refineries, particularly on the Gulf and west coasts, are no longer equipped to run large volumes of the extremely light condensates and oils now coming from onshore shale deposits. Allowing producers to achieve world-market prices for their output should boost the economy and raise tax receipts, yet is unlikely to harm consumers.

Condensates are a class of hydrocarbons distinct from crude oil, though they share enough oil-like characteristics frequently to be lumped in with the latter, as in US export regulations. The technical definition of condensates encompasses both the “natural gasoline” extracted during the processing of natural gas produced from oil fields (“associated gas”,) as well as the heaviest liquids separated from “non-associated” gas, i.e. from gas fields, rather than oil fields.

The condensate being exported in this case comes mainly from liquids-rich shale deposits like the Eagle Ford in Texas, which produces varying proportions of dry gas, “wet” gas containing NGLs and condensate, and crude oil, depending on well location. Condensate apparently accounts for around 20-40% of Eagle Ford “tight oil” output.

Condensate mainly consists of natural gas liquids like ethane, propane and butane, along with substantial quantities of naphtha, a low-octane mix of hydrocarbons that boils in the gasoline range, plus much smaller proportions of diesel and heavier “gas oils” than would be typical of crude oil. The naphtha in condensate can sometimes be blended into gasoline, depending on its specific qualities, or processed in a refinery to yield higher-quality gasoline components.

Subsequent to the phase-out of tetraethyl lead, most gasoline from US refineries has been a blend of higher-octane naphtha produced by catalytic cracking units and the “reformate” from catalytic reforming units, with provision for further blending during distribution with up to 10% ethanol. Last month US refineries set an all-time record for gasoline production, at over 10 million barrels per day. They are unlikely to miss the naphtha exported in condensate.

Historically, the global market for condensate has had important distinctions from the broader crude oil market, based on the inherent characteristics of these liquids and the end-users seeking them. Refiners running mainly heavy oils sometimes buy condensate for blending, to lighten their average inputs and fill gaps in their processing capacities.

With the Gulf Coast now drowning in light “tight oil” from shale, this is becoming too much of a good thing, as refiners increasingly have more light material in their feedstock than their facilities can easily handle. One presenter at the EIA conference described the situation as building toward a "day of reckoning", when the discounts required to induce US refiners to process excess light crude instead of imported heavier crude would reach the level at which producers must throttle back oil production. Another expert with whom I spoke was adamant that that day of reckoning has already arrived. One result is investment in new facilities to provide minimal processing–really just distillation–for condensate.

By contrast, petrochemical producers, particularly in Asia, are expected to import growing volumes of condensate for use in the production of olefins like ethylene and propylene, and aromatics like toluene and benzene, from which to make plastics, solvents and other petrochemicals. In that market, US condensate will compete with condensate from other gas producing nations, and with exports of refinery naphtha from Europe and elsewhere. This looks like a good opportunity for US producers.

Some advocates of lifting the ban on crude oil exports see the Commerce Department’s ruling as a precedent for allowing exports of all types of oil, or at least a good first step. However, other reports have focused on this ruling as an end-run around the export rules by redefining minimally processed condensates as a petroleum product, and thus exempt from the ban. In that view, the resulting precedent from condensates for exports of true crude oil may be weaker than that from ongoing, permitted oil exports to Canada.

Either way, allowing condensate exports is a smart move that, if continued, should ease crude congestion on the Gulf Coast and reduce the discounts that could make domestic oil less economical to produce, to the benefit of foreign suppliers. It might even push the problem beyond the current election year and enable Congress to consider normalizing all oil exports without the inhibiting effect of populist pressures at the polls. In the meantime, you can bet these condensate exports will be closely scrutinized for any noticeable effects, good or bad.

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

Energy Security Four Decades After the Arab Oil Embargo

• The Arab Oil Embargo of 1973-74 focused our attention on energy security and set in motion drastic changes in the way we produce, trade and consume energy.
• With US energy output approaching or exceeding 1970s levels, some experts now advocate prioritizing competition from non-petroleum fuels over reducing oil imports.

Forty years ago this month the United States and other Western countries experienced a new phenomenon as an embargo on oil deliveries from a group of the world’s largest oil exporters took effect. The embargo was a response to the military support that the US and some of its allies were providing to Israel during the Yom Kippur War then underway in the Middle East. A recent session hosted by the US Energy Security Council commemorating these events included a fascinating conversation between Ted Koppel and Dr. James Schlesinger, US Secretary of Defense at the time of the embargo and later the first US Energy Secretary.

The other, related purpose of the meeting was a presentation and discussion on the proposition that fuel competition provides a surer means of achieving energy security than our pursuit of energy independence for the next four decades following the Arab Oil Embargo. This idea warrants serious consideration, since energy independence, at least in the sense of no net imports from outside North America, is finally beginning to appear achievable.

The 1973-74 embargo was the first oil shock of a tumultuous decade, and it triggered a true crisis. The US had relied on oil costing around $3 per barrel (bbl), not just to fuel our transportation system, but also for 17% of our electricity generation and numerous other uses. The US was then one of the world’s largest oil producers but required imports comprising about one-third of supply to balance our growing demand. With the sudden loss of over a million barrels per day of oil imports from the Middle East, and lacking the sort of strategic petroleum reserve that was established a few years later, an economy already battling inflation was tipped into recession.

The embargo rattled more than the US economy; it challenged basic assumptions of American life, including our sense of entitlement to cheap and plentiful gasoline. Before the oil crisis, gasoline prices hovered around the mid-30-cent mark, with occasional local “gas wars” taking the price down to the high-20s--the inflation-adjusted equivalent of $1.60 per gallon now. Of course with average fuel economy around 13 miles per gallon, the effective real cost per mile wasn’t necessarily lower than today’s.

Within a year gas was over 50¢ at the pump, and by the end of the decade it passed $1.00/gal. for the first time. The gas lines that resulted from the unexpected supply shortfall and the federal government’s efforts to limit the ensuing increase in prices were an affront to drivers, a category that encompassed most of the over-16 population.

That first oil crisis and the subsequent energy crisis resulting from the Iranian Revolution in 1979 set in motion a number of important changes, including a sharply increased focus on energy efficiency, a deliberate effort to diversify our sources of imported oil, a pronounced shift away from oil in power generation — to the point that it now makes up less than 1% of US power plant fuel — and the beginnings of our search for affordable, renewable alternatives to oil.

The US Energy Security Council is an impressive group that includes many former government officials and captains of industry. They’ve clearly spent a lot of time studying this issue, and their report is worth reading. As I understand their conclusions and recommendations, they regard high oil prices as a bigger risk to the US economy than oil imports, per se, because of the impact of oil prices on consumer spending and the balance of trade. They have concluded that the most effective way to apply downward pressure on prices is not simply to reduce US oil imports, but to introduce meaningful fuel competition into transportation markets, where oil remains dominant with a share of around 93%.

The group doesn’t dismiss the benefits of increasing US oil production from sources such as the Bakken, Eagle Ford and other shale formations, but because these are relatively high-cost supplies, they have concluded that their leverage on global oil prices is limited. That means that higher US oil output couldn’t provide a path back to the price levels that prevailed before the Iraq War, when West Texas Intermediate crude averaged $26/bbl in 2002 and gasoline retailed for $1.35/gal.

This is a reasonable argument, though it’s worth considering that a return to $75/bbl might be feasible, if US production kept rising. That could yield US retail gasoline prices around $2.75/gal., equating to $2.15 in 2002 dollars. This isn’t as far-fetched as it might seem, because the global oil price is determined not by the entire 90 million bbl/day of world supply and demand, but by the last few million bbl/day of incremental supply, demand, and inventory changes.

The Council’s view also appears to emphasize the direct impact of oil prices on consumer spending without recognizing that rising production and falling imports shield the economy as a whole from the worst effects of high oil prices. With oil’s contribution to the trade deficit shrinking steadily, the main impact of higher oil prices is to divert money from consumers to shareholders of oil companies — of which I should disclose I am one. While exacerbating income inequality, that should at least result in a smaller impact on GDP and employment than the combination of rising oil prices and rising imports.

If the discussion had stopped at that point, the meeting would have been just another interesting Washington gabfest. However, the group’s analysis includes a set of actions it has identified as necessary for achieving their desired outcome: US energy security extending beyond the current US oil boom, underpinned by an expanding unconventional gas revolution that is widely expected to last for decades.

Their recommendations include giving fuels like methanol derived mainly from natural gas the chance to compete with gasoline made from oil, and with biofuels.They would start with revisions to the current US Corporate Average Fuel Economy standards to give carmakers incentives — not cash subsidies or mandates — to make at least half of all new vehicles fully fuel-flexible, capable of tolerating a wide range of blends of methanol, ethanol and gasoline. That seems like a no-regrets approach that could be achieved at a very low incremental cost per car. Even if you never bought a gallon of E85, M85, or M15, it could pay for itself by protecting your car from the damage that might result if you inadvertently filled up with gasoline containing more than the 10% of ethanol that carmakers believe is safe for non-flex-fuel cars. Other recommendations include easing regulations for retrofitting existing cars for flex-fuel and forming an alcohol-fuels alliance with China and Brazil.

Yet while I repeatedly heard that the group wasn’t promoting any single fuel, talk of methanol dominated the conversation. The moderator, Ann Korin, even joked that the session sounded like an “alcohol party.” As I later pointed out to her, there wasn’t a single mention of drop-in fuels — gasoline and diesel lookalikes derived from natural gas or biomass. I regard that as a crucial omission, because such fuels would be fully compatible with the billion cars already on the road, rather than just the 60 million or so new cars produced each year. They could provide greater leverage on oil prices by producing pipeline-ready products with which consumers are already familiar, from sources other than crude oil.

Part of the appeal of methanol seemed to be the potential for producing it from shale gas at a cost well below the cost of gasoline, even on an energy-equivalent basis — an important caveat, because a gallon of methanol contains half the energy of a gallon of gasoline. I hear the same argument in support of various pathways for producing jet fuel from non-oil sources, and it subscribes to the same fallacy: that market prices are set by manufacturing costs rather than supply and demand.

Fuel is a volume game. For a non-oil gasoline substitute to drive down oil prices –and thus motor fuel prices– as far as the Council apparently envisions, it would take at least several million barrels per day, on an oil-equivalent basis. Producing six million bbl/day of methanol from natural gas would consume 20 billion cubic feet per day of it. That’s 30% of last year’s US dry natural gas production, requiring 100% of the Energy Information Administration’s forecasted growth of US natural gas production through 2034. A number of other entities have their eyes on that same gas for other applications.

As many of the speakers at the Energy Security Council event reminded us, the world is a very different place than it was in 1973. Among other changes, US energy trends are headed in the right direction, with oil demand flat or declining, production rising and imports falling. That alone makes us more energy secure than we were, either five years ago or in 1972. Future oil supply disruptions are also unlikely to look much like the Arab Oil Embargo.

The Council is certainly correct that our unexpected shale gas bonanza, producing large quantities of new energy at a price equivalent to oil at $25 or less per barrel, provides a unique opportunity to weaken OPEC’s influence on oil prices. In pursuing that goal, however, it’s essential to remain flexible concerning the best pathways for gas to compete in transportation fuel markets, whether as CNG or LNG, or through conversion to electricity, methanol, or petroleum-product lookalikes. Consumer acceptance could prove to be the biggest uncertainty governing the ultimate outcome.

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

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.

Administration's Tax Proposals Would Hamper US Energy Output

The Obama administration is proposing significant changes in US corporate taxes, as reported in today's Wall St. Journal. If enacted, the corporate tax rate would fall from 35% of income to 28%, although the elimination of numerous tax incentives would subject many companies, including most in the energy sector, to higher taxes overall. On the surface, this looks like the kind of tax reform that has been long overdue; however, as always with such efforts, the details matter enormously. In this case, the details would create an even less-level playing field for US energy producers, while doubling down on the expensive tax benefits currently provided to favored sectors and technologies. It's ironic that this is being proposed just when rising gasoline prices have put the administration on the defensive concerning its energy policies. It will do the President little good to point to increasing US oil production--demonstrably the result of energy prices and policies in previous administrations--if he simultaneously jeopardizes that recovery in output by making it less attractive to produce oil and gas here.

The basic principle of cutting marginal corporate tax rates in exchange for the elimination of "tax expenditures", or loopholes, in common parlance, is consistent with the much broader tax reform proposed by the fiscal commission established by the White House in 2010, even if the administration has opted for the upper end of the range of tax rates suggested by Simpson-Bowles. In general, US oil and gas companies wouldn't be worse off for losing the various deductions and tax credits in the current tax code, if the marginal tax rate were reduced sufficiently and if the administration weren't proposing to raise royalty rates on US onshore production by 50% at the same time. However, the combination of the proposed changes, including subjecting part of their non-US income to US taxation, would not only make US oil and gas projects less attractive, relative to projects in other countries; they would also make it less attractive to be a US oil and gas company, instead of a non-US company that operates here. For an administration that is concerned about US competitiveness, this is perverse logic, indeed.

It doesn't take a crystal ball to predict that the combination of higher corporate taxes on energy companies, higher royalties, and the more complex permitting processes instituted by the administration even before the Deepwater Horizon accident will make it much harder to sustain the recent recovery in US oil output beyond the completion of projects that were initiated during the previous administration. New oil and gas production would probably still be profitable here after these changes, particularly if oil prices remain as high as they are now, but company portfolios would begin to shift back towards non-US projects that look more rewarding by comparison, and US companies would lose some of their edge to non-US competitors. None of that would be good for US energy consumers, considering that the oil and gas industry accounts for 62% of the energy we use, including 49% of all energy produced domestically.

Of course, the administration's tax proposals reach well beyond oil and gas. Among other things, they would extend the Production Tax Credit for wind energy by another year, through 2013, as well as extending for another year the Treasury renewable energy cash grants that expired at the end of last year. After 2012, the cash grants would be replaced by refundable tax credits, which essentially means you'd get a check from the IRS, rather than from the Treasury, if the credit were larger than the taxes your firm owes. The net effect of the latter would perpetuate a costly system of renewable energy subsidies that reward the deployment of renewable energy hardware, rather than the actual generation of renewable energy. (That distinction is important whenever the hardware is installed somewhere lacking in good wind, sun, or other renewable resources.)

Then there's the proposal to boost the electric vehicle tax credit to a maximum of $10,000 per car, and to shift the recipient from the purchaser to the seller. That circumvents the problem that under the current $7,500 credit you'd have to earn enough income to be paying at least that much in federal income taxes, in order to enjoy the full benefit of the credit. However, it also makes it much likelier that manufacturers and dealers would pocket a significant slice of the higher credit, instead of consumers. Since it was nearly impossible to justify the $7,500 per car credit on the basis of actual oil or emissions savings, the higher credit looks even less justifiable, other than as a means of raising the odds of achieving the President's arbitrary target of putting a million EVs on the road by 2015--another near impossibility. The pluses I see here include an automatic phaseout based on time, rather than sales volume, and a broadening of the credit to cover other efficient vehicle technologies such as natural gas, though it's not clear whether it would also cover advanced diesels. Still, if the President has his way, we'll be spending more than $10 billion to put vehicles on the road that will save less than 35,000 barrels per day of oil, or about 0.4% of our total gasoline consumption, along with greenhouse gas emissions worth less than $1 billion at market prices--even European market prices.

The proposals include other provisions that would affect the energy sector, including tax benefits for advanced energy manufacturing such as wind turbines, solar panels, advanced batteries, electric vehicles, and an array of other equipment. I'd be much happier with those incentives if they were provided as an alternative to origin-blind deployment incentives, instead of alongside them. And although oil and gas companies would lose the manufacturing tax deduction on their US production, it appears they might get to keep that deduction on US refining, which has been hurt by higher oil prices. That would be small consolation to independent refining companies that have been forced to close several large east coast refineries or that are barely breaking even.

If President Obama is serious about tax reform, the current proposals--flawed as they are--would have carried a lot more weight had they been introduced a year ago, in the immediate aftermath of the Simpson-Bowles report and various other tax reform suggestions, rather than in an election year. And if he is truly serious about the"all-out, all-of-the-above strategy" for energy that he referenced in this year's State of the Union address, the current proposals look like an extremely odd way to execute that, favoring as heavily as they do sources that account for less than 2% of US energy production, while penalizing those that contribute nearly half. The good news is that this is a meal that won't be eaten hot. For now, this package serves as another plank in the reelection campaign platform. Whether it will ultimately be implemented depends not just on who occupies the White House after January 20, 2013, but also on the composition of the next Congress since it has no chance of passage in the 112th.

Do LNG Exports Threaten the Shift to Gas?

Last week US liquefied natural gas provider Cheniere signed a long-term agreement to sell BG (formerly British Gas) LNG exported from the Gulf Coast. The governor of Alaska was also recently quoted suggesting that his state's surplus natural gas might find a better market in Asia than if sent to the lower-48 via a new pipeline. Both stories indicate just how much the shale gas revolution has altered the US energy balance. They also provide further validation of its likely staying power. Coincidentally, they reminded me that time was running short to respond to my residential gas supplier's offer to lock in an annual fixed price, as I did last year. That's relevant, because even though the risk of a big spike in natural gas prices looks very low now, the prospect of future US gas exports--an unthinkable idea only a few years ago--serves notice that the shale bonanza is also stimulating new segments of demand that compete with existing ones and will tend to drive prices higher.

Cheniere's role in all this looks like a classic lemons-to-lemonade story. Their Sabine Pass LNG terminal and two others in development on the Gulf Coast were designed to import gas and feed it into the domestic pipeline system. They weren't the only ones to pursue this idea, which looked entirely reasonable when they were planned. In the first half of the last decade US gas production was in decline and LNG imports were climbing, facilitated by rising gas prices that made imports at the higher global gas price attractive, at least seasonally. The combination of a surge of shale gas output and the largest US recession in decades turned these plans on their head. Now Cheniere is redeveloping Sabine as an LNG liquefaction and export facility, with construction scheduled to begin next year.

The Wall St. Journal's Heard on the Street column had a good analysis of Cheniere's deal with BG. It closed with the observation that, "...it is natural that excess supply should seek a market." That got me thinking, not just about what I might be paying for natural gas to heat my home in a few years, but about whether exports pose a threat to ambitious notions of displacing large increments of coal-fired electricity with power from gas turbines, shifting large numbers of US cars and long-haul trucks to compressed natural gas (CNG) or LNG, and building new US chemical plants to capitalize on the abundance of shale gas. Most of these plans depend on gas remaining fairly cheap, particularly relative to oil. The current price of natural gas at its key Henry Hub trading point is the equivalent of $22.50 per barrel, a level that we haven't seen for oil since March 2002. Could gas exports drive up domestic prices to the point at which these other uses couldn't compete?

The answer depends both on how much gas would be exported and on the shape of the supply curve for shale gas. If the latter is steep--if not much extra supply can be brought on without requiring big increases in price--then exports could begin to look like a zero-sum-game at the expense of today's consumers and tomorrow's other new uses for gas. However, if large quantities of shale gas are waiting in the wings for only small increases in price, then while all these uses would be in competition with each other, they should be able to coexist at prices that leave gas considerably more attractive than oil, and competitive with both coal and the cheapest renewables. Assessing which view is likelier isn't simple, because it involves multiple shale basins and evolving federal and state regulations, but in general the data I've seen supports the more optimistic view. Many estimates suggest that most US shale plays would produce attractive returns at around $5-6 per million BTUs (MMBTU), compared to current prices around $4, which have left some producers with poor wellhead economics.

If that's correct, then even a big increase in demand from multiple sources, including a stronger economy, additional power generation, new chemical plants and LNG exports, might not boost natural gas prices by more than $1-2/MMTBU before significant additional supply came onstream. (A reality check on that is the sharp drop in the number of gas wells being drilled when prices slid below $6/MMBTU in late 2008, as the recession and financial crisis took hold.) $1/MMBTU sounds like a big jump at the wellhead, but for consumers it would represent an increase of only about 8% after transmission and distribution costs are added. For power generation in efficient combined cycle plants, it would raise costs by less than $0.01/kWh. And for vehicle use, it equates to an extra $5/bbl, or around 12.5 cents per gallon of gasoline-equivalent fuel. Although not trivial, such increases would be smaller than we've seen from market volatility over the last few years.

Putting the Cheniere/BG deal in perspective, the 3.5 million tons of LNG per year involved equate to 0.5 billion cubic feet per day of gas, or 0.8% of 2010 US "dry gas" production (natural gas with the valuable ethane, propane and butane removed.) The facility's total planned capacity of 9 million ton/y works out to 2% of US gas last year. By comparison the Department of Energy has forecasted US gas production growing by about 3.3 BCFD, or 6% in the next five years in their base case, and by up to 14% in their high-shale-resource case. These figures indicate that there's room for several of these demand sectors to expand, including both power generation and LNG exports, without putting intense pressure on prices. This issue is attracting some attention, including from the US Senate, which has scheduled a hearing next week to consider the consequences of gas exports.

Are Strategic Inventories Adequate to Handle Another Oil Crisis?

In a thought-provoking op-ed, Michael Levi of the Council on Foreign Relations has provided a very timely reminder of the role that the strategic petroleum reserves of the US and other nations would play if the turmoil in North Africa and the Middle East spawned another oil crisis. Neither additional drilling nor an accelerated effort on renewable energy would make any near-term difference if oil exports from the Middle East were disrupted. Both strategies are important for our future needs, but the only two tools we have for dealing with an immediate oil crisis are the Strategic Petroleum Reserve (SPR) and old-fashioned conservation. Unfortunately, we've wasted the last couple of years of relative oil-market stability that could have been spent bringing the SPR into the 21st century.

The US government currently has 726 million barrels of oil stored in underground caverns around the Gulf Coast, for use in emergencies. At that level, the SPR is essentially full. The stored oil notionally equates to around 80 days of supply at our current rate of net crude oil imports, though in practice it would provide 165 days of drawdown at the SPR's maximum pumping rate of 4.4 million barrels per day. That is in addition to commercial supplies of crude oil and gasoline and other petroleum products, which currently stand at the equivalent of 24 and 28 days, respectively. However, commercial stocks aren't much of a backstop, because the difference between current levels and those at which the system would start to run out in places amounts to less than a week of normal consumption.

We needn't worry about relying on the SPR if exports from Libya dry up. As I noted in Tuesday's posting, OPEC has more than enough spare capacity to make up such a shortfall, although it's of different quality and might result in some tightness in global diesel markets. But if the current unrest spread and threatened exports from the big producers on the Arabian peninsula, the only thing standing between consumers and much higher oil and product prices would be the SPR and its counterparts in other consuming countries. With combined inventories of at least 1.6 billion barrels, these reserves are in good shape to respond to a drop in exports of a few million barrels per day for several months, though not necessarily a sustained curtailment or a much larger one. And any use of these reserves should be coordinated among consuming nations, as Mr. Levi pointed out in his op-ed.

This all sounds good in principle, and I have no doubt that even the announcement of the intent of the US and others to draw promptly on these stocks if the situation deteriorates further would do a lot to calm markets. At the same time, it's important to understand how much the world has changed since the SPR was first planned and implemented, as a result of the first oil crisis in 1973-74. As I commented three years ago:

"In addition to importing much larger volumes of crude oil, our refinery capacity hasn't kept pace with demand, resulting in steadily growing imports of gasoline and gasoline blending components. And in the interim, oil production in Alaska and California has fallen into deep decline, requiring crude and product imports into a maxed-out West Coast refining system.

So instead of a strategic reserve designed to provide a back-up supply of crude oil to Gulf Coast and Mid-continent refineries serving the entire US east of the Rockies, our needs have expanded to encompass oil and refined product imports on all three coasts. These altered circumstances suggest the need for a more diverse and dispersed SPR, perhaps modeled along the lines of the federal Northeast Heating Oil Reserve. Nor do I believe that the only practical model of such a reserve entails government ownership and custody of the hydrocarbons in question. Other countries achieve the same end with a requirement for oil companies to maintain mandatory minimum inventory levels at no direct cost to taxpayers."

That's as relevant today as when I wrote it, with the addition that the SPR's potential effectiveness has been further affected by the buildup of crude in the Mid-continent as a result of increased output from Canadian oil sands projects and the rapidly growing output of the Bakken Shale. This is one of the main reasons why West Texas Intermediate is trading at roughly $100 this morning, while UK Brent crude, which is normally within $2 of WTI, has spiked over $118. I also can't resist pointing out that the market is hitting us in the face with a two-by-four concerning the potential energy security value of US natural gas, which is still trading at an oil-equivalent price under $27 per barrel for all of 2011, despite the events in the Middle East.

I don't blame the last two administrations or Congress for not having made SPR reform a higher priority in the last three years. They had a few other things on their plate. However, even if the current crisis in Libya and the Middle East resolves itself quickly and without further impact on world oil supplies, it provides another unwelcome reminder that we live in a world in which the President and other world leaders might need to call on our strategic oil inventories on very short notice to prevent a catastrophic breakdown of the economy. In that context, redesigning our 1970s-vintage SPR to be more effective in a greatly altered landscape ought to rise to a similar priority as addressing other urgent concerns such as the deficit.

Locking In Gas Prices

I recently received an offer from my household natural gas supplier, Washington Gas, to lock in my gas purchases for the next 12 months at a price of $0.699/therm. They reminded me that I had paid as much as $0.96/therm and as little as $0.68/therm over the last 12 months, before distribution charges, so on the surface this looks like a good deal. Of course the real measure of the attractiveness of this offer is not what I've paid in the past, but what I'm likely to pay in the future if I don't take advantage of it. Unsurprisingly, Washington Gas left that for me to work out. This is no simple task, even if you follow energy trends as closely as I try to do.

The price of natural gas is notoriously volatile, particularly in years when supply is tight, the economy strong, and weather extreme. Historically, gas often spiked in the winter months, as cold weather drew down stockpiles, and traders bid up the price for prompt delivery. That pattern has shifted somewhat in recent years, as seen in the chart below, not because global warming is making winters warmer--though that seems to be the case in the most general sense--but because US gas consumption patterns have shifted.

In 1997 residential users accounted for 22% of total US gas demand, commercial and industrial users took nearly 52%, and just 18% went to power generation. Last year residential use was 21%, but commercial and industrial had fallen to 40%, while the power sector took over 30%. And since power generation, for which gas turbines are often the incremental supply, typically peaks in the summer months, the annual peak of gas prices is now as likely to occur in June or July as in January or February. That's an important consideration if you're a residential customer like me. Of the roughly 1,100 therms my household consumes each year, 84% are bought between November and March.

In this context the first place to check on whether the offer from Washington Gas is fair was the futures market. Yesterday's average closing price for the one-year "strip" from November 2010 to October 2011 was $4.26/million BTUs. That's the price at the Henry Hub, a gas distribution point in Louisiana. In order to compare it to what I've been offered, I need to account for the average differential, or "basis", between that location and the supply point for Northern Virginia. The "city gate" price for Virginia over the last year averaged $2.39/MMBTU higher than Henry Hub. Even that doesn't quite get me to the Purchased Gas Price that shows up on my utility bills. Over the last 12 months I paid an additional $0.60/MMBTU, on average, because the mix Washington Gas sells me includes gas purchased under long-term contracts, as well as incorporating the results of its hedging activities. When I add all this together, the equivalent futures-based price to compare to the deal I've been offered for the next 12 months works out to about $7.25/MMBTU, or $0.73/therm. For the November-March period that will affect me most, it's around $0.71/therm.

From that I conclude that my supplier is offering me a price that's in line with the market, and that I couldn't beat it even if I did the hedging myself. However, it's important to recall that the futures market isn't a forecast; it's just the current consensus on what buyers and sellers are willing to agree on today, based on everything they know. In order to decide whether I should lock that in and give up any upside or downside, I ought to have a point of view on gas prices, based on supply, demand and inventories. The supply side is dominated by surging shale gas output, which has taken US gas production to levels we haven't seen since the 1970s. For production to drop by enough to drive up prices significantly within the next year, the shale gas bandwagon would have to slow appreciably. That's certainly possible. In several presentations at the recent IHS Herold Pacesetters Energy Conference I saw graphs indicating that a number of producers aren't covering all their costs at current prices. Some of them must continue drilling new wells in order to satisfy the terms of their leases, but others could slow down if they chose. A slowdown in drilling would translate into reduced supplies fairly quickly, because of the rapid drop-off of output from individual wells. Even bigger supply risks are inherent in the growing environmental concerns surrounding shale gas drilling, which have seen New York's state senate vote to impose a moratorium on shale drilling. Yet while it's hard to envision a big enough drop in output from any of these factors, soon enough to affect this winter's prices, it's even harder to see so much additional shale gas coming to market in the next year that it would drive prices well below current levels.

On the demand side, the weak economy dominates, particularly in the industrial sector, which despite having rebounded from last year's lows is still running well below its consumption in the early 2000s. A sizable fraction of that lost demand isn't coming back, even if the economy started growing at rates more characteristic of past post-recession expansions, because the high gas prices of the previous decade drove some fertilizer and petrochemicals producers out of business or offshore. The biggest upside demand potential comes from the power sector, which is also suffering from low demand, at the same time we see low gas prices and environmental pressures displacing coal with gas and renewables. That's a clear medium-term trend, though as with reduced shale drilling, the situation seem unlikely to change much in the next 3-6 months.

That leaves gas inventory as the last major fundamental factor to assess. As of the most recent figures, gas storage was running about 5% below the same week last year, but ahead of the previous three years. A severe cold snap might test these inventories, but they don't loom as a big upside price risk today.

On balance, then, it appears I've been offered a fixed price that is not only in line with the current futures market, but at which I would also be giving up relatively little chance of paying significantly lower prices later--barring a double-dip recession--while gaining protection from weather or supply-related surprises. If the next year looked exactly like the last one did, I'd end up saving a bit less than $100. If you've followed my logic this far, you might think this was a lot of effort in order to convince myself that what looked like a good deal really was, but then I guess that's the lot of a former commodity trader who routinely had to make decisions like this, but for much larger stakes. And perhaps I've given you some food for thought, in case you're facing a similar decision.