Tuesday, January 28, 2014

The Pros and Cons of Exporting US Crude Oil

  • Calls for an end to the effective ban on exporting most crude oil produced in the US are based on a growing imbalance in domestic crude quality.
  • At least recently, the ban has likely benefited refiners more than consumers. Assessing the impact of its repeal on energy security requires further study. 
Senator Lisa Murkowski (R-AK), the ranking member of the Senate Energy & Natural Resources Committee, issued a white paper earlier this month calling for an end to the current ban on US crude oil exports. Her characterization of existing regulations in this area as "antiquated" is spot on; the policy is a legacy of the 1970s Arab Oil Embargo. However, not everyone sees it the same way, either in Congress or the energy industry.

This isn't just a matter of politics, or of self-interest on the part of those benefiting from the current rules. Questions of economics and energy security must also be considered. The main reason these restrictions are still in place is that for much of the last three decades US oil production was declining. The main challenges for the US oil industry were slowing that decline while ensuring that US refineries were equipped to receive and process the increasingly heavy and "sour" (high sulfur) crudes available in the global market. The shale revolution has sharply reversed these trends in just a few years.

No one would suggest that the US has more oil than it needs. Despite the recent revival of production, the US still imported around 48% of its net crude oil requirements last year. Even when production reaches its previous high of 9.6 million barrels per day (MBD) as the Energy Information Agency now projects to occur by 2017, the country is still expected to import a net 38% of refinery inputs, or 25% of total liquid fuel supply. The US is a long way from becoming a net oil exporter.

The driving force behind the current interest in exporting US crude oil is quality, not quantity, coupled with logistics. If the shale deposits of North Dakota and Texas yielded oil of similar quality to what most US refineries have been configured to process optimally, exports would be unnecessary; US refiners would be willing to pay as much for the new production as any non-US buyer might. Instead, the new production is mainly what Senator Murkowski's report refers to as "LTO"--light tight oil. It's too good for the hardware in many US refineries to handle in large quantities, and for most that can process it, its better yield of transportation fuels doesn't justify as large a price premium as for international refineries with less complex equipment.

As a result, and with exports to most non-US destinations other than Canada or a few special exceptions effectively barred, US producers of LTO must discount it to sell it to domestic refiners. Based on recent oil prices and market differentials, producers might be able to earn as much as $5-10 per barrel more by exporting it. Meanwhile the refiners currently processing this oil are enjoying something of a buyer's market and are able to expand their margins. The export issue thus pits shale oil producers and large, integrated companies (those with both production and refining) such as ExxonMobil against independent refiners like Valero.

Producers are justified in claiming that these regulations penalize them and threaten their growth as available domestic refining capacity for LTO becomes saturated. Additional production is forced to compete mainly with other LTO production, rather than with imports and OPEC.

I believe producers are also largely correct that claims that crude exports would raise US refined product prices are mistaken. The US markets for gasoline, diesel fuel, jet fuel and other refined petroleum products have long been linked to global markets, with prices especially near the coasts generally moving in sync with global product prices, plus or minus freight costs. I participated in that trade myself in the 1980s and '90s. What's at stake here isn't so much pump prices for consumers as US refinery margins and utilization rates.

Petroleum product exports have become a major factor in US refining profitability, and refiners are reportedly investing and reconfiguring to enhance their export capabilities. This provides a hedge against tepid domestic demand. Nationally, refined products have become the largest US export sector and contributed to shrinking the US trade deficit to its lowest level in four years.  If prices for light tight oil rose to world levels US refineries might be unable to sustain their current export pace. It's up to policymakers to assess whether that risk is merely of concern to the shareholders of refining companies or a potential threat to US GDP and employment.

The quest to capture the "value added"--the difference between the value of manufactured products and raw materials--from petroleum production is not new. It helped motivate the creation of the integrated US oil companies more than a century ago and impelled national oil companies such as Saudi Aramco, Kuwait Petroleum Company, and Venezuela's PdVSA to purchase or buy into refineries in Europe, North America and Asia in the 1980s and '90s.

On the whole, OPEC's producers probably would have been better off investing in T-bills or the stock market, because the return on capital employed in refining has frequently averaged at or below the cost of capital over the last several decades. It's no accident most of the major oil companies have reduced their exposure to this sector. When today's US refiners argue that it is in the national interest to preserve the advantage that discounted LTO gives them they are swimming against the tide of oil industry history.

The energy security case for crude exports looks harder to make. An excellent article from the Associated Press quoted Michael Levi of the Council on Foreign Relations as saying, "It runs against the conventional wisdom about what oil security means. Something seems upside-down when we say energy security means producing oil and sending it somewhere else."  The argument hinges on whether allowing US crude exports would simultaneously promote more production and increase the pressure on global oil prices. That makes sense to me as a former crude oil and refined products trader, but it will be a harder sell to Senators, Members of Congress, and their constituencies back home.

The politics of exports may be easing somewhat, though, as a Senate vacancy in Montana could lead to a new Chair at Energy & Natural Resources who would be a natural partner for Senator Murkowski on this issue. (That shift may incidentally be part of a strategy to help Democrats retain control of the Senate.) Will that be enough to overcome election-year inertia and the populist arguments arrayed against it?

As for logistics, the administration could ease the pressure on producers without opening the export floodgates by exempting the oil output from the Bakken, Eagle Ford and other shale deposits from the Jones Act requirement to use only US-flag tankers between US ports. That could open up new domestic markets for today's light tight oil, while allowing Congress the time necessary to debate the complex and thorny export question.

Senator Murkowski wasn't alone in calling for an end to the oil export ban. In his annual State of American Energy speech presented the day as the Senator's remarks, Jack Gerard, CEO of the American Petroleum Institute, noted, "We should consider and review quickly the role of crude exports along with LNG exports and finished products exports, because of the advantages it creates for this country and job creation and in our balance of payments." In a similar address on Wednesday, the head of the US Chamber of Commerce stated, "I want to lift the ban. It's not going to happen overnight, but it's going to happen."  I'd wager he at least has the timing right.

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

Monday, January 20, 2014

Converting Coal to Synthetic Natural Gas in China

  •  With so much attention focused on China's shale gas potential, its growing synthetic natural gas industry is a wild card.

  • In light of China's severe air quality problems,  trading smog for higher CO2 emissions is an understandable choice, but one with global implications.

In its latest Medium-Term Coal Market Report the International Energy Agency (IEA) forecasts a slowing of coal demand growth but no retreat in its global use. That won’t surprise energy realists, but the item I wasn’t expecting was the reference in the IEA press release to growing efforts in China to convert coal into liquid fuels and especially synthetic natural gas (SNG).  It’s not hard to imagine China’s planners viewing SNG as a promising avenue for addressing the severe local air pollution in that country’s major cities, but the resulting increase in CO2 emissions could be substantial. It could also affect the economics of natural gas projects around the Pacific Rim.

Air quality in China’s cities has fallen to levels not seen in developed countries for many decades. There’s even a smartphone app to help residents and visitors avoid the worst exposures. Much of this pollution, in the form of oxides of sulfur and nitrogen and particulate matter, is the result of coal combustion in power plants. Although China is adding wind and solar power capacity at a rapid clip, after years of exporting most of their solar panel output, the scale of the country’s coal use doesn’t lend itself to easy or quick substitution by these renewables.

Natural gas offers a lower-emitting alternative to coal on a larger scale than renewables. Existing coal-fired power plants could be converted to run on gas or replaced with modern combined-cycle gas turbine power plants. Gas-fired power plants emit up to 99% fewer local, or “criteria” pollutants than coal plants, especially those with minimal exhaust scrubbing.

Unfortunately, China doesn’t have enough domestic natural gas to go around. Despite potentially world-class shale gas resources and the rapid growth of coal-bed methane and more conventional gas sources, natural gas supplies only 4% of China’s energy needs. Imported LNG can help fill the gap, but it isn’t cheap. What China has in abundance is coal. Converting some of it to SNG could boost China’s gas supply relatively quickly–perhaps faster than the country’s shale gas infrastructure and expertise can gear up.

SNG is hardly a new idea; the Great Plains Synfuels Plant has been producing it in North Dakota since the 1980s. When that facility was built, natural gas prices were volatile and rising, and greenhouse gas emissions appeared on no one’s radar. The process for making SNG from coal is straightforward, and its primary building block, the gasification unit, is off-the-shelf technology. I worked with this technology briefly in the 1980s, and my former employer, Texaco, licensed dozens of gasification units in China before the technology was eventually purchased by GE. Other vendors offer similar processes.

Gasifying coal adds a layer of complexity, compared to gasifying liquid hydrocarbons but this, too, has been demonstrated in commercial operations. Most of the output of the facilities Texaco sold to China was used to make chemicals, but the chemistry of turning syngas (hydrogen plus carbon monoxide) into pipeline-quality methane is no more challenging.

This effort is already under way in China. Last October Scientific American reported that the first of China’s SNG facilities had started shipping gas to customers, with four more plants in various stages of construction and another five approved earlier this year. The combined capacity of China’s nine identified SNG projects comes to around 3.5 billion cubic feet per day, or a bit more than the entire Barnett Shale near Dallas, Texas produced in 2007 as US shale gas production was ramping up. It’s also just over a quarter of China’s total natural gas consumption in 2012, including imported LNG.

To put that in perspective, if that quantity of SNG were converted to electricity in efficient combined cycle plants their output would be roughly double that of China’s 75,000 MW of installed wind turbines in 2012, when wind generated around 2% of the country’s electricity.

The appeal of converting millions of tons a year of dirty coal into clean-burning natural gas, in facilities located far from China’s population centers, is clear. This strategy even has some similarities to one pursued by southern California’s utilities, which for years imported power from the big coal-fired plants at Four Corners.  For that matter, the gasification process has some key advantages over the standard coal power plant technologies in the ease with which criteria pollutants can be addressed. Generating power from coal-based SNG might actually reduce total criteria pollutants, rather than just relocating them.

However, wherever these plants are built they would add around 500 million metric tons per year of CO2, or around 5% of China’s 2012 emissions, a figure that dwarfs even the most pessimistic estimates of the emissions consequences of building the Keystone XL pipeline. That’s because the lifecycle emissions for SNG-generated power have been estimated at seven times those from natural gas, and 36-82% higher than simply burning the coal for power generation.

What could possibly lead China’s government to pursue such an option, in spite of widespread concerns about climate change and China’s own commitments to reduce the emissions intensity of its economy? Having lived in Los Angeles when it was still experiencing frequent first-stage smog alerts and occasional second-stage alerts, I have some sympathy for their problem. China’s air pollution causes even more serious health and economic impacts and has been blamed for over a million premature deaths each year. By comparison the consequences of greenhouse gas emissions are more indirect, remote and uncertain. Any rational system of governance would have to put a higher priority on air pollution at China’s current levels than on CO2 emissions.

It might even turn out to be a reasonable call on emissions, if China’s planners envision carbon capture and sequestration (CCS) becoming economical within the next decade. It’s much easier to capture high-purity, sequestration-ready CO2 from a gasifier than a pulverized coal power plant. (At one time I sold the 99% pure CO2 from the gasifier at what was then Texaco’s Los Angeles refinery to companies that produced food-grade dry ice.) It should also be much easier and cheaper to retrofit a gasifier for CCS than a power plant.

In an internal context the trade-off that China is choosing in converting coal into synthetic natural gas is understandable. However, that perspective is unlikely to be shared by other countries that won’t benefit from the resulting improvement in local air quality and view China’s rising CO2 emissions with alarm. I would be surprised if the emissions from SNG were factored into anyone’s projections, and nine SNG plants could be just the camel’s nose under the tent.

In an environment that the IEA has described as a potential Golden Age of Natural Gas, large-scale production of SNG could also constitute an unexpected wild card for energy markets. When added to China’s shale gas potential, it’s another trend for LNG developers and exporters in North America and elsewhere to monitor closely.

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

Monday, January 13, 2014

Canada: From Energy Supplier to Competitor?

  • In addition to its impact on global oil and natural gas pricing and trade, the shale revolution is altering the energy relationship between the US and Canada.
  • This long-standing supplier/customer relationship is becoming more complex as producers in both countries seek new markets outside North America.
In remarks last month the Canadian Natural Resources Minister, Joe Oliver, suggested that with the continued growth of unconventional oil production in the US, "Our only customer will become a competitor." Considering plans for liquefied natural gas export facilities on both sides of the border, he might have included LNG in that comment, too. Let's take a look at the kind of competition he might have had in mind.

Canada has long been an important supplier of crude oil to US refineries, since at least the 1950s. For much of the 1980s and '90s it was in a virtual three-way tie with Mexico and Venezuela for the #2 spot on the list of top oil exporters to the US, behind Saudi Arabia. Since 2004 Canada has claimed first place on that list as its production expanded, while Mexican and Venezuelan output declined and some Saudi oil went to other markets. From 2010 to 2012 exports of Canadian crude oil to the US, including oil sands crude, increased by 23% to over 2.4 million barrels per day (bpd). This has provided Canada with a reliable outlet for its production and the US with additional supplies not exposed--except for price--to ongoing instability in the Middle East and other regions.

However, with or without the Keystone XL Pipeline, the competition to feed US refineries is becoming more intense.  Canada's growing crude exports, including significant quantities of heavy and/or sour crude oil, must displace similar crudes imported into the US from  Latin America and the Middle East without losing ground to the expanded light oil production from US shale plays such as the Bakken and Eagle Ford, and the otherwise mature Permian Basin of Texas and New Mexico. Each of these areas now yields a million bpd. These dynamics are compounded by 1970s-vintage US oil-export rules that keep domestic crude bottled up in the Gulf Coast and weaken the economics of oil production throughout much of North America. 

If it seems odd for a Canadian official to talk about competition within the US market in this way, consider that the main country exempted from current US oil export restrictions is Canada. US oil exports to eastern Canada by rail and by tanker have grown rapidly in the last two years and are likely to expand beyond the current 100,000 bpd level, if export license applications are any indication. US oil exports to Canada may be displacing non-North American crudes today, but they likely also have an adverse effect on the economics of projects intended to ship more western Canadian crude eastward. So Canada now understandably looks towards Asia, home to the world's fastest oil-demand growth, as the logical destination for at least some of its future oil production.

 Natural gas creates another, perhaps more plausible arena for export competition between Canada and the US. Canada envisions a resurgence in gas production similar to what the US has experienced, based on a combination of conventional gas discoveries, such as in the Mackenzie Delta of the Northwest Territories, as well as the shales of Alberta and British Columbia. It also stands to gain additional gas reserves if it is successful in its bid to claim more of the Arctic. As Canadian gas is displaced from its long-standing export market in the US by the shale boom in the lower-48, LNG exports from B.C. are looking more attractive. The province lists five projects in different stages of development and highlights B.C.'s advantageous shipping route to Asia.

Many more LNG export projects have been proposed for the US, with at least four having received approval to sell to countries with which the US does not have free-trade agreements. A number of these are based on existing, or at least previously permitted, LNG import facilities, giving developers a head-start on construction. The US also has a big edge in proved natural gas reserves and technically recoverable gas resources, including shale gas.

Despite these US advantages, aspiring Canadian LNG exporters won't have to contend with an enormous domestic market for their gas, in which many industries are competing to use more gas in power generation, chemicals and other manufacturing, and different paths for displacing oil from transportation, including CNG, LNG, methanol, ethanol or gas-to-liquids fuels. As a result, I suspect that a Canadian LNG plant could count on a more stable long-term cost of gas than one on the US Gulf Coast.

The protracted controversy over the Keystone XL Pipeline project has focused a great deal of public attention on a single aspect of our energy relationship with Canada, while obscuring other aspects that are beginning to shift. Adding a new competitive overlay to our long-standing energy supply chains could ultimately increase North American leverage on OPEC's pricing power, while helping to develop a deeper and more flexible global market for LNG, with resulting environmental benefits. While this might result in winners and losers at the project and company level, the overall effect should be positive for both countries.

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

Monday, January 06, 2014

Energy 2013: More Shifts Ahead?

  • 2013 was an eventful year for energy, though perhaps with fewer earth-shaking implications for the future than in other recent years.
  • Several developments concerning global oil production, when taken together, improved the odds of lower oil prices in the next several years.
Year-in-review posts have become standard fare for energy blogs; I've written my share in the past. However, while 2013 hardly lacked for interesting energy-related news and events to populate a top-ten list, most fell short of the potential to affect energy markets strongly for years to come.

For example, it is newsworthy that another year has passed without an indication of whether the White House will approve or reject the cross-border permit for the Keystone XL pipeline project. Yet the consequences of that decision are becoming less significant, at least in the reported view of Bakken shale pioneer Harold Hamm. That's due in large measure to the dramatic increase in the transportation of oil by rail, which should be on anyone's top-ten list. Nor is it clear that the EPA's proposal to scale back the Renewable Fuel Standard's (RFS) corn ethanol quota for 2014 will affect more than this year's fuel market, unlike pending Congressional legislation to reform the RFS.  California's adoption of an energy storage mandate for utilities is another notable event, but its long-term impact is contingent on the development of cost-effective storage technology and business models to enable much greater integration of renewable energy on the grid.

Instead of extending that list, I'd like to focus on three stories in which I see significant, related implications for oil markets. The first involves the temporary international agreement concerning Iran's pursuit of nuclear technology. Although relaxation of the sanctions limiting Iranian oil exports depends on a highly uncertain final agreement governing uranium enrichment, the  Arak reactor's plutonium potential, and a more intrusive inspections regime, the interim deal signals that around a million barrels per day of Iran's oil--and eventually more--could be back on the market in less than two years.

If that happens, it won't be because the Iranian government's repeated assurances of its aversion to nuclear weapons have suddenly become credible, but because most of the permanent members of the UN Security Council plus Germany--the "P5 + 1" negotiating with Iran--are tiring of the protracted confrontation and understandably have no appetite to address this in the same way that the collapsing UN sanctions regime for Iraq was resolved in 2003.

Next consider the stunning reversal of the Mexican government's 75-year-old nationalization of oil and gas. As a result of the reforms just enacted by their congress and ratified by a majority of Mexico's states, the state oil company Pemex will be run along more commercial lines, and foreign firms will be allowed to partner with Pemex in developing the country's large untapped hydrocarbon resources. If the terms prove attractive for international energy firms, the result will move North America even closer to net energy independence. Meanwhile the Transboundary Hydrocarbon Agreement between the US and Mexico that was just passed by the US Congress will simplify energy development that straddles the border.

Mexico's potential could be even more significant for oil markets than an unconstrained Iran. The former's production has declined by 24% since 2004--a loss of 900,000 bbl/day-- mainly due to limited reinvestment. Foreign investment can help to restore that output, but the upside potential is much bigger. Pemex has barely scratched the surface of its deepwater resources in the Gulf. Its proven and contingent reserves are estimated at 45 billion barrels, while US estimates put Mexico's shale oil, or "tight oil" resources at 13 billion barrels, slightly more than the country's proved conventional reserves. (Shale gas could exceed 500 trillion cubic feet.)

Mexico's oil output has grown dramatically before. In the decade following the Arab Oil Embargo of 1973 production increased from 500,000 bbl/day to around 3 million. A similar performance seems possible again from a higher starting point, but it's unlikely to happen overnight. As Dan Yergen pointed out in a recent Wall St. Journal op-ed, "exploration and development could take another five to 10 years" beyond the first bid rounds.

And that brings us to Saudi Arabia's options for dealing with a shifting market that will include projected US crude oil output of 9.6 million bbl/day by 2016, the recovery and growth of Iraqi production, possible exports from Canada to Asia, Mexico's potential, and the eventual return of full Iranian exports. Whether or not this wave of new or restored production will be sufficient to replace production declines elsewhere, it must undermine OPEC's control of pricing in this decade. In that light, it's hard to ignore reported indications that Saudi Arabia might abandon its role of swing producer, particularly when it comes to unilateral output cuts to balance new non-OPEC supplies.

Haven't we seen this movie before? After a dozen years of high prices and tight markets OPEC steadily lost market share in the 1980s as new fields in Alaska, Mexico and the North Sea came online. That trend culminated in Saudi Arabia's 1986 "netback pricing" decision, linking the price of its oil to the value of its customers' refined petroleum products. Following the price collapse that policy helped precipitate,  oil prices took 18 years to reach $30/bbl again, by which time the dollar had lost a third of its value.

I doubt we're in for anything that dramatic. Back then, most demand growth came from the developed countries of the OECD, rather than from the expanding middle classes of developing Asia and the Middle East itself. Moreover, today's new production has higher costs--up to $70-80 per barrel--ruling out a return to $20 oil. With many serious geopolitical risks still in play, an oil-price price correction or extended soft market seems likelier than another price collapse. In the meantime, if we're seeking $20 oil, we already have it in the form of US shale gas that averaged the equivalent of $21.64/bbl last year. And that's the early, odds-on favorite for the energy story of the decade.

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