The image that will stick with me from yesterday's failed attempt by Senator Mary Landrieu of Louisiana to avoid a filibuster on her bill to approve the Keystone XL pipeline is that of her Senate colleague, Barbara Boxer (D-CA) standing next to a blown-up photo of choking smog, presumably in China. Inconveniently, the greenhouse gases at the heart of this debate are invisible and global in effect, rather than local like the pollution from unscrubbed coal plants half a world away. Senator Boxer's smog ploy epitomizes the confusion and misinformation surrounding this project.
That extends to the White House, where the President's recent arguments against the pipeline reflect beliefs, rather than facts, and stand in contrast to the findings of his own administration on the economic and environmental impact of the pipeline, or of oil exports, should some of Keystone's oil be sold into the global market from the Gulf Coast.
Yesterday's defeat is likely to be more final for Senator Landrieu than for the pipeline. She goes into next month's runoff election as a distinct underdog, based on recent polling. The pipeline, however, will likely get another opportunity in the new Congress early next year, when supporters are expected to have an easier time coming up with the 60 votes necessary to bring a bill to the Senate floor for an up-or-down vote. The project may even benefit from having avoided a Presidential veto now, since the fig-leaf of letting the review process run its course would have been more transparent this time than when the President rejected the pipeline in 2012.
Showing posts with label pipelines. Show all posts
Showing posts with label pipelines. Show all posts
Wednesday, November 19, 2014
Tuesday, March 04, 2014
Energy Risks of the Ukraine Crisis
- Russia's intervention in the Crimean Peninsula poses few risks to Europe's energy supplies, but escalation or Western sanctions could change that assessment.
- If the crisis expanded to mainland Ukraine, the integrity of that country's pipelines and the natural gas they carry to EU members would be the most immediate energy concern.
It's always dicey commenting on an unfolding event of this magnitude, which various observers have nominated as the most serious geopolitical crisis in post-Cold War Europe. I've spent the last few days following developments, listening to conference calls, and speaking with a Russia expert of my acquaintance. Dismissing the current events as out of tune with the 21st century ignores the complex history of a region that has seen multiple episodes of great-power conflict, just as trying to impose a Western mindset on President Putin's intentions is likely to come up short.
His latest reported comments suggest that he may have achieved his initial goals, at least insofar as giving him, rather than the new government in Kiev, control over Russia's access to the strategic Black Sea naval installations. Any broader goals are unclear at this point, and as a military expert highlighted in a media call hosted by the Council on Foreign Relations, the current confrontation in Crimea runs the risk of "unintended escalation." Wars have started this way.
So what's at stake, in energy terms? An infographic from Business Insider puts the gas situation in perspective. Russia's share of Europe's gas supply has fallen to 22% as EU members diversified their sources of supply in the aftermath of past interruptions in Russian gas deliveries. Still, roughly two-thirds of Russian gas sent to the EU passes through Ukraine's territory, and the pipelines that transit Belarus and the Baltic Sea lack sufficient capacity to reroute the entire volume should Ukraine's pipelines be disrupted.
Whether that occurred as an intentional reaction by Russia to steps that the US and EU are considering in response to its intervention in Crimea, or as a result of armed conflict in mainland Ukraine, natural gas prices in Europe would spike, even with ample gas in storage after a relatively warm winter. That would adversely affect EU economies still recovering from recession and the EU's financial crisis.
European natural gas prices are already much higher than those in the US, and any further increase would ratchet up the pressure on the EU's manufacturing sector. Nor is there nearly as much LNG available globally to make up any shortfall as there will be in just a few years, once US exports gear up and several large Australian LNG projects come onstream. Ironically, Ukraine is building its own LNG import facility to diversity its supplies--luckily not sited in Crimea.
The threat to oil deliveries seems less acute, short of an embargo that would hurt Russia as much as its customers. In 2012 Russia exported around 6 million barrels per day of oil and condensate to European refineries by various routes, including the southern leg of the Druzhba pipeline that crosses Ukraine on its way to the Czech Republic, Hungary and Slovakia. While a disruption of this flow could force refiners in those countries to scramble for alternative supplies, Russian oil would probably still find its way to world markets via other routes, including to the Baltic ports. Ensuing world oil price increases would likelier reflect an overall risk premium than a more localized physical shortfall.
Even if the situation doesn't progress beyond its current state, longer-term energy impacts could still follow. These include a recognition of heightened political risk for investments in Russia and its "near abroad" neighbors, along with the results of any financial sanctions that might be imposed.
If Mr. Putin is satisfied to engineer greater Crimean autonomy or independence from a more EU-oriented government in Kiev, and if the EU/US response is limited to financial measures to prop up that government, then the consequences--similar to those for Russia's ongoing occupation of part of Georgia--could be minimal. The EU can't go any farther than Germany will support, and thanks to the Nordstream gas pipeline led by its former Chancellor, Germany has less at stake in Ukraine than some of its neighbors. It has already distanced itself from suggestions of evicting Russia from the G8 group of nations. In that context, the US administration seems unlikely to sustain a harder line than Brussels.
Thursday, December 12, 2013
The LPG Echo of the Shale Gas Boom
- Increased US production of LPG and natural gas liquids is an outgrowth of the shale gas revolution and a key ingredient for translating its benefits into industrial growth.
- The infrastructure investments, export opportunities and price relationships for these liquids represent a microcosm of the similar issues for shale gas and LNG.
Like most Americans--except for those in the roughly 5% of US homes heated with it-- I normally think about LPG only when I have to change the tank on my barbecue grill. That wasn't always the case; early in my career I traded LPGs for Texaco's west coast refining system. I'm happy to see that some of my former colleagues from that period are still involved and frequently quoted as experts on it. Although the LPG market is obscure to many, it represents a microcosm of the issues of reindustrialization and product exports arising from the recent turnaround in US energy output trends.
In order to follow these developments, we first need to clarify some confusingly similar acronyms, starting with LPG. Although often used synonymously with propane, it actually stands for "liquefied petroleum gas" and covers mainly propane and butane, though some in the industry include ethane in this category. The term reflects the oil refinery source of much of their supply, both historically and to an important extent today. LPG overlaps with natural gas liquid (NGL)--ethane, propane, butane, isobutane and "natural gasoline"-- that has been separated from "wet" ( liquids-rich) natural gas during processing. NGLs are entirely distinct from the anagrammatical LNG, or liquefied natural gas, which consists mainly of methane that has been chilled until it becomes a liquid. By contrast, NGLs and LPG are typically stored at or near ambient temperature but under pressure to keep them in the liquid state.
LPG and NGLs make up a distinct segment of US and global energy markets, falling between the markets for natural gas and refined petroleum products. They are also linked to these larger markets, both logistically and economically. For example, gas marketers vary the amount of liquids they leave in "dry gas" to meet pipeline natural gas specifications based on price and other factors, and oil refiners blend varying quantities of butane into gasoline, depending on seasonal requirements. Propane and butane are mainly used as fuels, while ethane and isobutane are chiefly chemical feedstocks.
The development of shale gas in the US and Canada has affected the supply of NGLs and LPG in several important ways. First, starting around 2007 increasing shale gas output helped to halt and then reverse the decline in US natural gas production from which US NGLs are sourced. Then, following the financial crisis, diverging natural gas and crude oil/liquids prices pushed shale drillers toward the liquids-rich portions of shale basins like the Eagle Ford in Texas, in order to maximize their revenue. The resulting surge of US NGL production in late 2009 reinforced the decline of US LPG imports that began with the recession. According to US Energy Information Administration data, the US became a fairly consistent net exporter of LPG in 2011.
The current US LPG surplus is around 100,000 bbl/day, out of total production of around 2.7 million bbl/day. That surplus and its expected growth provides the basis for a number of announced LPG export projects, as well as the anticipated development of new domestic chemical facilities such as ethylene crackers that would consume substantial portions of new supply, particularly of ethane.
The success of those projects depends on significant investments in new infrastructure, including gas processing, NGL fractionators to split the raw NGL into its components, and pipelines to deliver NGL to fractionators and LPG to markets. This is particularly true for the Marcellus and Utica shale gas in the Northeast, from which little or no ethane has been extracted due to limited local demand. Not only is that a missed manufacturing opportunity, but it constitutes a potential constraint on further liquids-rich gas development, since leaving too much ethane in the marketed gas would cause it to exceed pipeline BTU specifications.
In the meantime we're left with a situation that's analogous to the growth of tight oil production from the Bakken shale. New sources of production have come on-stream faster than the infrastructure necessary to deliver them efficiently to where they can be processed or consumed. That puts a growing US surplus of propane and other NGLs in tension with tight regional markets for these fuels in the Midwest and Northeast, where residential propane prices are running well ahead of last year's at this time. The resolution of this apparent paradox will depend on which infrastructure and demand projects are eventually completed, and how soon.
A different version of this posting was previously published on the website of Pacific Energy Development Corporation.
Friday, September 13, 2013
Energy Projects Seem Less Urgent in A Post-Energy-Crisis World
- Rather than being another component of an ongoing energy crisis, opposition to various energy projects points to the alleviation of a decades-long string of US energy crises.
- The audience for concerns about pipelines and fracking would be much smaller if oil were still at $145 per barrel and natural gas over $10 per million BTUs.
The alleviation of what seemed to many a permanent energy crisis might not be obvious, because it has crept up on us. But consider a few of the big-picture elements that have changed:
In crisis mode, US energy security was focused on steadily rising oil and later natural gas imports, while "energy independence" was a goal embraced by politicians but rarely energy experts. Cars offering better fuel economy were available but entailed trade-offs in size and performance. Today, oil imports are falling, the US is a net exporter of refined petroleum products, and public concern about Peak Oil is waning, as measured by internet search activity. Ethanol from corn supplies 10% of US gasoline demand, while other forms of renewable energy are growing rapidly, from a small base. The big question for the federal government this summer is how many natural gas export facilities to allow. Meanwhile, the threshold for fuel-efficient cars has shifted from 30 mpg to 40 mpg, offered in numerous attractive models.
Another way to gauge the success of technologies like hydraulic fracturing, or "fracking", in shifting our energy landscape is to remind ourselves how bad we thought today's situation would be, just a few years ago. In 2005 the official US annual energy forecast projected oil imports to increase from 11 million barrels per day (MBD) in 2003 to nearly 15 MBD by this year, due to rising demand and domestic production that was expected to remain flat, at best (see below chart.)
The Energy Information Agency (EIA) also expected US natural gas imports to increase steadily, reaching 3.5 trillion cubic feet (TCF) of LNG imports this year, on their way to 6 TCF per year by 2022. As a consequence, in 2005 the EIA forecast that coal would still generate 48% of US electricity by 2013.
Now imagine energy prices in that alternative 2013. With US natural gas suppliers importing an average of 90 LNG tankers per month, would the wellhead price of gas still be under $4 per million BTUs, or closer to the $16 price paid in some international markets? And with US refiners importing up to twice as much crude oil as they are actually on track to do this year, in the context of sanctions on Iran and turmoil in North Africa, how likely does it seem that oil would be at $105-110/bbl, instead of much higher? $100 oil is a drag on the economy, but US consumers have adjusted to gasoline priced around $3.50-3.75/gal., on average. Every $1 per gallon above that would take another $130 billion per year away from other purchases, with adverse effects on the US economy.
More to the point, in such an environment how much tolerance would there be for opposition to oil pipelines or gas drilling that had the potential to lower energy prices, or at least reduce imports and enhance energy security? If oil were above its 2008 high of $145/bbl, and gasoline flirting with $5 per gallon, it would surely be much harder for elected officials to delay approving projects like the Keystone XL pipeline, or to sustain gas drilling moratoria. Ironically then, the successful large-scale application of shale drilling techniques, which has resulted in a 29% increase in US natural gas production and 33% rise in oil production since 2004, helped make it possible for opponents of Keystone or fracking to be heard, rather than dismissed out of hand.
I was recently struck by a reported remark by a pipeline executive. "Shale is everywhere," he said, but it won't be produced everywhere because "people make choices." I agree with that insight, while recognizing that such choices are available mainly because altered economic conditions and the same technologies to which some now object have enabled us to shed an energy crisis mindset. This situation might have future parallels for other technologies that have escaped much pushback, so far.
Monday, April 08, 2013
Crude Oil Rides the Rails
Last month's publication of the State Department's latest environmental impact report on the Keystone XL pipeline project has sparked great interest in the logistics of shipping crude oil by rail. As described in a long article in the Washington Post, the availability of a rail option for oil sands crude could prove to be a crucial element in determining whether the pending decision to permit the pipeline to cross the US border would actually affect Canada's oil sands output, and thus its greenhouse gas emissions. As the article makes clear, however, oil's rail trend is already well underway , thanks to the surge of "tight oil" production from shale formations. Moving crude oil by train is experiencing a "Back to the Future" moment.
Oil shipments in rail cars are nothing new; the practice dates back to the earliest days of the oil industry. In fact, control of key railroad routes for oil and petroleum products was an important aspect of the US government's anti-trust case against the original Standard Oil a century ago. My first exposure to crude-by-rail was in the 1980s, when significant quantities of heavy crude from California's San Joaquin valley were routinely transported to Los Angeles refineries by dedicated "unit trains", because there wasn't sufficient pipeline capacity available.
The same dynamic applies today, with the rapid expansion of tight oil production in North Dakota's Bakken fields quickly outstripping the capacity of the state's few existing pipelines to transport the oil to market. A tank car loading rack requires much less time and money to build than a new pipeline or pipeline expansion. US railroads are also eager for the traffic, since coal deliveries, which accounted for 45% of US rail traffic in 2011, fell by nearly 11% last year as natural gas eroded coal's share of power generation. Meanwhile oil shipments by rail grew by 46% in 2012.
Precise data on just how much crude oil is currently moving by rail are hard to find. The American Association of Railroads doesn't differentiate between crude oil and refined petroleum products, which until recently accounted for most oil-related rail shipments. The US Energy Information Agency (EIA) reported last summer that crude oil had grown to roughly 30% of total petroleum rail deliveries, which would equate to around 300,000 barrels per day (bpd) on average for 2012. Yet EIA's analysis of recent trends suggested that crude-by-rail increased by nearly 250,000 bpd last year alone. The CEO of the Burlington Northern Santa Fe recently indicated that his railroad's total oil-related shipments alone could expand to around 1 million bpd, roughly double today's level.
It would be easy to conclude that all this growth reflects a temporary expedient, until North American pipeline capacity can be expanded and realigned to match rising output and the reversal of long-standing import trends. That view is clearly not shared by oil companies and traders who are lining up to purchase or lease new tank cars for this service. Perhaps that's because rail provides a degree of flexibility that would be nearly impossible to match by pipeline. For example, it creates an opportunity to supply domestic crude to East Coast refineries like Delta Airlines' Trainer, Pennsylvania facility, which had previously become uneconomical to operate on a diet of imported crude cargoes. Similarly, even if a pipeline from North Dakota to the San Francisco Bay Area could be justified economically, it would likely never receive the necessary permits. Yet Valero's Benicia refinery might soon receive up to 70,000 barrels per day of Bakken crude by rail.
Railroads are also surprisingly efficient. At an industry average of 480 ton-miles per gallon, my analysis indicates that shipping a barrel of crude from North Dakota to a refinery in either Houston or Philadelphia consumes a quantity of diesel fuel equivalent to just 1% of the energy content of the oil, while adding slightly over 1% to the typical well-to-wheels emissions for gasoline refined from it. That's higher than for pipelines, but not by enough to render the option unattractive.
Pipelines remain the preferred option for moving high volumes of oil safely over long distances and, when capacity exists, are usually cheaper for shippers. However, rapidly shifting sources of production and the high capital costs of new pipelines, combined with an increasingly challenging regulatory environment, could provide a durable opportunity for oil-by-rail, just as it has for moving petroleum products and ethanol by train.
A slightly different version of this posting was previously published on the website of Pacific Energy Development Corporation.
Oil shipments in rail cars are nothing new; the practice dates back to the earliest days of the oil industry. In fact, control of key railroad routes for oil and petroleum products was an important aspect of the US government's anti-trust case against the original Standard Oil a century ago. My first exposure to crude-by-rail was in the 1980s, when significant quantities of heavy crude from California's San Joaquin valley were routinely transported to Los Angeles refineries by dedicated "unit trains", because there wasn't sufficient pipeline capacity available.
The same dynamic applies today, with the rapid expansion of tight oil production in North Dakota's Bakken fields quickly outstripping the capacity of the state's few existing pipelines to transport the oil to market. A tank car loading rack requires much less time and money to build than a new pipeline or pipeline expansion. US railroads are also eager for the traffic, since coal deliveries, which accounted for 45% of US rail traffic in 2011, fell by nearly 11% last year as natural gas eroded coal's share of power generation. Meanwhile oil shipments by rail grew by 46% in 2012.
Precise data on just how much crude oil is currently moving by rail are hard to find. The American Association of Railroads doesn't differentiate between crude oil and refined petroleum products, which until recently accounted for most oil-related rail shipments. The US Energy Information Agency (EIA) reported last summer that crude oil had grown to roughly 30% of total petroleum rail deliveries, which would equate to around 300,000 barrels per day (bpd) on average for 2012. Yet EIA's analysis of recent trends suggested that crude-by-rail increased by nearly 250,000 bpd last year alone. The CEO of the Burlington Northern Santa Fe recently indicated that his railroad's total oil-related shipments alone could expand to around 1 million bpd, roughly double today's level.
It would be easy to conclude that all this growth reflects a temporary expedient, until North American pipeline capacity can be expanded and realigned to match rising output and the reversal of long-standing import trends. That view is clearly not shared by oil companies and traders who are lining up to purchase or lease new tank cars for this service. Perhaps that's because rail provides a degree of flexibility that would be nearly impossible to match by pipeline. For example, it creates an opportunity to supply domestic crude to East Coast refineries like Delta Airlines' Trainer, Pennsylvania facility, which had previously become uneconomical to operate on a diet of imported crude cargoes. Similarly, even if a pipeline from North Dakota to the San Francisco Bay Area could be justified economically, it would likely never receive the necessary permits. Yet Valero's Benicia refinery might soon receive up to 70,000 barrels per day of Bakken crude by rail.
Railroads are also surprisingly efficient. At an industry average of 480 ton-miles per gallon, my analysis indicates that shipping a barrel of crude from North Dakota to a refinery in either Houston or Philadelphia consumes a quantity of diesel fuel equivalent to just 1% of the energy content of the oil, while adding slightly over 1% to the typical well-to-wheels emissions for gasoline refined from it. That's higher than for pipelines, but not by enough to render the option unattractive.
Pipelines remain the preferred option for moving high volumes of oil safely over long distances and, when capacity exists, are usually cheaper for shippers. However, rapidly shifting sources of production and the high capital costs of new pipelines, combined with an increasingly challenging regulatory environment, could provide a durable opportunity for oil-by-rail, just as it has for moving petroleum products and ethanol by train.
A slightly different version of this posting was previously published on the website of Pacific Energy Development Corporation.
Thursday, February 21, 2013
The Keystone XL Pipeline: Pyrrhic Victory Ahead?
Last weekend thousands came to Washington, DC to protest against the Keystone XL pipeline project, just a few days after a smaller protest in front of the White House resulted in a batch of arrested celebrities. The State Department's decision on the cross-border permit is expected within a few months. However, unless the President devises an unexpectedly Solomonic solution, one side or the other will come up short. That much is obvious, but I'd suggest that it's also worth considering the possible unintended consequences for the winning side. Keystone could prove a Pyrrhic victory for either environmentalists or the energy industry.
That assessment starts with the fact that both sides have contributed to exaggerating the stakes out of all proportion, especially on the part of those concerned about the climate impacts of a new pipeline to carry crude derived from Canada's oil sands, or "tar sands." With Nebraska having signed off on a new route avoiding the Sand Hills, the entire question now hinges on its global greenhouse gas (GHG) emissions, which would be far less than some claim. Without belaboring this point--not the aim of this posting--you needn't take the word of Transcanada, the pipeline's owner on this. It's straightforward to demonstrate that any expansion of oil sands production would still account for a small share of Canada's GHG emissions, which are in turn a thin sliver of global emissions. Such facts are easily overshadowed by pronouncements such as the oft-cited "game over" assertion from NASA's James Hansen, reminding us that even Ph.D.'s should be cautious when straying so far beyond their expertise.
Likewise, supporters of the pipeline have made numerous expansive claims about its potential economic and employment benefits. Even if those are accurate, they're a lot less relevant at this stage of the debate than they were a year or two ago. This issue has grown far beyond an argument about the facts, or even about a pipeline. It has become a battle over a symbol, and the responsibility for that development rests with the administration, which declined multiple opportunities to issue a simple up-or-down decision, even when the Congress attempted to force the President's hand in late 2011. Blame it on the election cycle, or unwillingness to disappoint one or another important constituency. But extended this long, indecision turned the project into a giant version of Schrödinger's Cat, existing in a sort of limbo that compels attention.
When the pipeline's fate is finally revealed, the consequences could match its inflated, symbolic stature, rather than its actual importance as an energy project. The possible blowback is probably easier to imagine if the pipeline were approved. Outraged environmentalists would be unlikely simply to pack up their signs and go home. Aside from seeking new ways to impede the project, they might turn their attention to other energy projects that are currently uncontroversial, or at least less so than Keystone XL. They might also choose to vent their anger on an administration they were counting on to see this argument their way. The resulting fallout in lost voter enthusiasm might hinder Democratic candidates in the 2014 mid-term elections.
Now imagine what might happen if the pipeline were rejected. As I understand the process, that would require the new Secretary of State to rule that the project is not in the US national interest. That would constitute a serious snub to our largest trading partner and largest source of imported crude oil. Canada won't cut us off, but its government and industry would certainly intensify their efforts to diversify their oil export destinations, by means of other options headed either west or east, by pipeline or by rail. The oil would still get through, but the relationship between the US and Canada would suffer, and environmentalists would be seen as responsible. In any case, what won't happen is the shutdown of oil sands development. If anything, making this oil harder to bring to market could lend further support to high oil prices, and paradoxically preserve the incentive to produce more of it or gain access to these supplies.
The outcome that should worry environmentalists most about that scenario is the prospect of up to 800,000 barrels per day of crude oil loaded onto rail cars--roughly 1,000 a day of them--and moving all over North America. Aside from the increased emissions associated with that mode of transport, compared to pipelines, the risks of a serious accident or spill would multiply. If such an event occurred, it would attract significant attention from media that wouldn't be shy about reminding viewers why this oil was in rail cars in the first place. But even without an accident, opponents of the pipeline are placing an implicit bet that oil prices will stay flat or decline if the pipeline isn't built. If they go up instead, they stand to bear part of the blame, whether accurately or not.
Stopping the Keystone XL pipeline won't result in appreciably lower US or global oil consumption, or a material change in global GHG emissions. The key to oil's emissions lies on the consumption side, where most of them occur, and thus in focusing on the hundreds of billions of dollars per year spent by developing and transitional countries on sheltering their industries and consumers from the price of oil, along with countries that still generate significant amounts of electricity from oil. Nor would approving the pipeline restore the US economy to its pre-financial-crisis growth rate. The energy security benefits that it would bring, like the climate benefits opponents seek, are more about reducing risk. Yet whether or not you agree with the editors of Bloomberg that keeping "Canadian oil flowing to U.S. refineries in the most efficient way, within the bounds of safety" is the principle that should guide Secretary of State Kerry, no one has benefited from dragging the decision out this long. The winners might end up regretting that as much as the losers.
That assessment starts with the fact that both sides have contributed to exaggerating the stakes out of all proportion, especially on the part of those concerned about the climate impacts of a new pipeline to carry crude derived from Canada's oil sands, or "tar sands." With Nebraska having signed off on a new route avoiding the Sand Hills, the entire question now hinges on its global greenhouse gas (GHG) emissions, which would be far less than some claim. Without belaboring this point--not the aim of this posting--you needn't take the word of Transcanada, the pipeline's owner on this. It's straightforward to demonstrate that any expansion of oil sands production would still account for a small share of Canada's GHG emissions, which are in turn a thin sliver of global emissions. Such facts are easily overshadowed by pronouncements such as the oft-cited "game over" assertion from NASA's James Hansen, reminding us that even Ph.D.'s should be cautious when straying so far beyond their expertise.
Likewise, supporters of the pipeline have made numerous expansive claims about its potential economic and employment benefits. Even if those are accurate, they're a lot less relevant at this stage of the debate than they were a year or two ago. This issue has grown far beyond an argument about the facts, or even about a pipeline. It has become a battle over a symbol, and the responsibility for that development rests with the administration, which declined multiple opportunities to issue a simple up-or-down decision, even when the Congress attempted to force the President's hand in late 2011. Blame it on the election cycle, or unwillingness to disappoint one or another important constituency. But extended this long, indecision turned the project into a giant version of Schrödinger's Cat, existing in a sort of limbo that compels attention.
When the pipeline's fate is finally revealed, the consequences could match its inflated, symbolic stature, rather than its actual importance as an energy project. The possible blowback is probably easier to imagine if the pipeline were approved. Outraged environmentalists would be unlikely simply to pack up their signs and go home. Aside from seeking new ways to impede the project, they might turn their attention to other energy projects that are currently uncontroversial, or at least less so than Keystone XL. They might also choose to vent their anger on an administration they were counting on to see this argument their way. The resulting fallout in lost voter enthusiasm might hinder Democratic candidates in the 2014 mid-term elections.
Now imagine what might happen if the pipeline were rejected. As I understand the process, that would require the new Secretary of State to rule that the project is not in the US national interest. That would constitute a serious snub to our largest trading partner and largest source of imported crude oil. Canada won't cut us off, but its government and industry would certainly intensify their efforts to diversify their oil export destinations, by means of other options headed either west or east, by pipeline or by rail. The oil would still get through, but the relationship between the US and Canada would suffer, and environmentalists would be seen as responsible. In any case, what won't happen is the shutdown of oil sands development. If anything, making this oil harder to bring to market could lend further support to high oil prices, and paradoxically preserve the incentive to produce more of it or gain access to these supplies.
The outcome that should worry environmentalists most about that scenario is the prospect of up to 800,000 barrels per day of crude oil loaded onto rail cars--roughly 1,000 a day of them--and moving all over North America. Aside from the increased emissions associated with that mode of transport, compared to pipelines, the risks of a serious accident or spill would multiply. If such an event occurred, it would attract significant attention from media that wouldn't be shy about reminding viewers why this oil was in rail cars in the first place. But even without an accident, opponents of the pipeline are placing an implicit bet that oil prices will stay flat or decline if the pipeline isn't built. If they go up instead, they stand to bear part of the blame, whether accurately or not.
Stopping the Keystone XL pipeline won't result in appreciably lower US or global oil consumption, or a material change in global GHG emissions. The key to oil's emissions lies on the consumption side, where most of them occur, and thus in focusing on the hundreds of billions of dollars per year spent by developing and transitional countries on sheltering their industries and consumers from the price of oil, along with countries that still generate significant amounts of electricity from oil. Nor would approving the pipeline restore the US economy to its pre-financial-crisis growth rate. The energy security benefits that it would bring, like the climate benefits opponents seek, are more about reducing risk. Yet whether or not you agree with the editors of Bloomberg that keeping "Canadian oil flowing to U.S. refineries in the most efficient way, within the bounds of safety" is the principle that should guide Secretary of State Kerry, no one has benefited from dragging the decision out this long. The winners might end up regretting that as much as the losers.
Wednesday, December 12, 2012
Should Alaska Export More LNG to Asia?
The Governor of Alaska reportedly met
this week with officials from the South Korean national gas company to
discuss exports of liquefied natural gas (LNG). Ever since crude oil production on Alaska's North Slope ramped
up in the 1980s, industry observers have speculated about the ultimate
disposition of the significant associated natural gas reserves found with the
oil. In a letter filed with the state of Alaska, BP, ConocoPhillips and ExxonMobil, the three main North Slope
producers, together with pipeline company Transcanada, recently confirmed their
plans for a potential liquefied natural gas (LNG) project, instead of the
long-mooted pipeline to deliver the gas to America's lower-48 states. The
contemplated megaproject would validate both the scale of Asia's future LNG
market and the long-term nature of the US shale gas revolution.
Alaska's North Slope has already yielded 15 billion barrels of oil. Production peaked at over 2 million barrels per day in 1988 and subsequently declined to less than 600,000 barrels per day last year. With around 6 billion barrels of remaining reserves, it's still a very significant field but well past its prime. While the public has focused on its oil output, the producers and the state have long had their eyes on how best to harvest the value of the 35 trillion cubic feet (TCF) of gas dissolved in the oil. In fact, the North Slope complex has produced several TCF per year of gas for years, ranking it among the largest gas fields in the world, but almost all of that gas has been reinjected into the formation to aid oil recovery--and for lack of a market in an isolated and sparsely-populated state.
For decades the default assumption was that a pipeline would eventually be built across Alaska and Canada to link this gas to the existing network feeding the contiguous US. That idea gained traction when US marketed gas production stalled around 2000 and then began to decline. The economics of an Alaskan gas pipeline compared poorly with gas produced along the Gulf Coast, but competing with rising LNG imports looked much more feasible. Then along came unconventional gas, starting with coal-bed methane and culminating with the surge of shale production since 2005. The US gas market now has enough domestic supply to shrink coal's contribution to US power generation by 7% since 2008 and revive gas-intensive industries.
If shale gas were only a short-term phenomenon, as some have suggested, it would be of little relevance to the plans of the North Slope producers. All they'd need to do would be to delay their pipeline for a few more years, and the market would come to them. However, estimates put US shale gas resources at between 482 and 686 TCF--a 60-90 year supply at current shale production rates. And the fact that all three of the main North Slope producers have invested in significant acreage positions and production in US shale basins surely gives them insights into the longevity of those resources.
Nor is time on the side of the Alaskan producers. As oil production declines the economics of the North Slope operation will deteriorate, while keeping the Trans Alaska Pipeline full becomes more problematic. Finding an attractive outlet for the North Slope "gas cap" wouldn't just provide a new revenue source; it could keep oil production going for additional decades.
The LNG option offers several advantages, despite its estimated $45-65 billion price tag and technical complexity. For starters, it cuts roughly 1,000 miles of difficult terrain off the distance that the gas must be pipelined, in this case to a site on the southern Alaskan coast. That location is much closer to Asia, the world's largest LNG market, than export projects intended to ship LNG from the US Gulf Coast. The Asian market is also growing, thanks in part to Japan's post-Fukushima reassessment of nuclear power. The Japanese government has backed away, at least for now, from plans for a firm nuclear phase-out, but it seeks to diversify its energy sources. Among other steps taken in the aftermath of the Sendai quake and nuclear disaster, it has instituted the world's most attractive solar power incentives. Yet Japan's solar resources provide just a few hours of peak output per day, on average, requiring substantial fossil fuel generation to fill in the gaps. Power plants burning LNG are well-suited to that task.
China presents a more complex picture, with its own significant shale gas potential and an energy market expected to add as much natural gas demand by 2035 as all the world's developed countries put together. Considering the scale of eventual demand and the infrastructure necessary to bring China's shale gas to market, it seems likely that the growth of the market in the interim must depend heavily on LNG imports.
Assuming that the state of Alaska presents no obstacles and that US export permits would be forthcoming, because Alaskan LNG exports wouldn't impact US natural gas prices, the main questions that will determine the future of this project can't be answered definitively today. Among these are whether the numerous competing LNG projects being planned and built around the Pacific Rim and elsewhere will saturate the global market in the meantime, and whether the market will provide an attractive price for Alaskan LNG, influenced more by crude oil prices than by US shale gas. The North Slope producers are already immersed in these issues via their other activities, including ConocoPhillips' small LNG plant in Kenai, Alaska, which has been shipping LNG to Asia for more than 40 years. The project timeline provided to the state includes at least three go/no-go decisions along the way as the answers to these questions unfold.
A slightly different version of this posting was previously published on the website of Pacific Energy Development Corporation.
Alaska's North Slope has already yielded 15 billion barrels of oil. Production peaked at over 2 million barrels per day in 1988 and subsequently declined to less than 600,000 barrels per day last year. With around 6 billion barrels of remaining reserves, it's still a very significant field but well past its prime. While the public has focused on its oil output, the producers and the state have long had their eyes on how best to harvest the value of the 35 trillion cubic feet (TCF) of gas dissolved in the oil. In fact, the North Slope complex has produced several TCF per year of gas for years, ranking it among the largest gas fields in the world, but almost all of that gas has been reinjected into the formation to aid oil recovery--and for lack of a market in an isolated and sparsely-populated state.
For decades the default assumption was that a pipeline would eventually be built across Alaska and Canada to link this gas to the existing network feeding the contiguous US. That idea gained traction when US marketed gas production stalled around 2000 and then began to decline. The economics of an Alaskan gas pipeline compared poorly with gas produced along the Gulf Coast, but competing with rising LNG imports looked much more feasible. Then along came unconventional gas, starting with coal-bed methane and culminating with the surge of shale production since 2005. The US gas market now has enough domestic supply to shrink coal's contribution to US power generation by 7% since 2008 and revive gas-intensive industries.
If shale gas were only a short-term phenomenon, as some have suggested, it would be of little relevance to the plans of the North Slope producers. All they'd need to do would be to delay their pipeline for a few more years, and the market would come to them. However, estimates put US shale gas resources at between 482 and 686 TCF--a 60-90 year supply at current shale production rates. And the fact that all three of the main North Slope producers have invested in significant acreage positions and production in US shale basins surely gives them insights into the longevity of those resources.
Nor is time on the side of the Alaskan producers. As oil production declines the economics of the North Slope operation will deteriorate, while keeping the Trans Alaska Pipeline full becomes more problematic. Finding an attractive outlet for the North Slope "gas cap" wouldn't just provide a new revenue source; it could keep oil production going for additional decades.
The LNG option offers several advantages, despite its estimated $45-65 billion price tag and technical complexity. For starters, it cuts roughly 1,000 miles of difficult terrain off the distance that the gas must be pipelined, in this case to a site on the southern Alaskan coast. That location is much closer to Asia, the world's largest LNG market, than export projects intended to ship LNG from the US Gulf Coast. The Asian market is also growing, thanks in part to Japan's post-Fukushima reassessment of nuclear power. The Japanese government has backed away, at least for now, from plans for a firm nuclear phase-out, but it seeks to diversify its energy sources. Among other steps taken in the aftermath of the Sendai quake and nuclear disaster, it has instituted the world's most attractive solar power incentives. Yet Japan's solar resources provide just a few hours of peak output per day, on average, requiring substantial fossil fuel generation to fill in the gaps. Power plants burning LNG are well-suited to that task.
China presents a more complex picture, with its own significant shale gas potential and an energy market expected to add as much natural gas demand by 2035 as all the world's developed countries put together. Considering the scale of eventual demand and the infrastructure necessary to bring China's shale gas to market, it seems likely that the growth of the market in the interim must depend heavily on LNG imports.
Assuming that the state of Alaska presents no obstacles and that US export permits would be forthcoming, because Alaskan LNG exports wouldn't impact US natural gas prices, the main questions that will determine the future of this project can't be answered definitively today. Among these are whether the numerous competing LNG projects being planned and built around the Pacific Rim and elsewhere will saturate the global market in the meantime, and whether the market will provide an attractive price for Alaskan LNG, influenced more by crude oil prices than by US shale gas. The North Slope producers are already immersed in these issues via their other activities, including ConocoPhillips' small LNG plant in Kenai, Alaska, which has been shipping LNG to Asia for more than 40 years. The project timeline provided to the state includes at least three go/no-go decisions along the way as the answers to these questions unfold.
A slightly different version of this posting was previously published on the website of Pacific Energy Development Corporation.
Tuesday, April 12, 2011
What's the Alternative to Oil Sands?
I can recall when technologies like oil sands and coal gasification were commonly referred to as alternative energy, with the same high-tech aura now attached to solar power and advanced biofuels. Much has changed since then, not least our perspective on climate change and the greenhouse gases that contribute to it. It's no longer possible to consider Canada's oil sands production and the means of transporting it without a serious examination of the environmental consequences, both at the source and along its journey to market. However, while I understand that perspective, the reaction to the proposed Keystone XL pipeline seems disconnected from the reality that crucial supplies of Middle Eastern oil suddenly look much riskier than they did. We should certainly weigh the costs and benefits of oil sands carefully, but the missing element from this conversation is the question of what the alternative would be if we ruled out more oil sands imports.
This train of thought began with a sobering analysis of the energy implications of the unrest in the Middle East by Amy Myers Jaffe of the Baker Institute at Rice University in Houston. The challenge she highlights is much subtler than the risk of exports from countries like Libya being disrupted for a few months or even a few years. Existing spare capacity in other producing countries can cope with some of that, although a portion of that capacity is in other countries that could be just another domino or two down the road, while the rest is in Saudi Arabia, which might not be immune, either. Yet if the worst case is the disruption of exports, we have a substantial Strategic Petroleum Reserve to fall back on. Prices might rise significantly, but the prospect of no fuel at your local gas station at any price remains remote for now.
However, as Ms. Jaffe demonstrates, much of the incremental oil production capacity on which forecasters have been relying to meet additional oil demand over the next two decades, and to backstop declining production in non-OPEC countries, must come from the same region that is now in turmoil. And as the charts in her presentation show, revolutions--democratic or otherwise--rarely result in higher oil output. If new governments or chastened existing governments don't invest in developing that extra capacity, then Peak Oil won't just be a theoretical construct in geology; it will be a very real outcome in geopolitics, and one that strategic inventories like the SPR would be unable to mitigate.
We have had a tendency to view Canada as the Saudi Arabia of the north. Considering that we now receive more oil from there than from all the countries of the Persian Gulf combined, and that our NAFTA partner's proved reserves of 178 billion barrels are second only to those of the Kingdom, that's not unreasonable. As recently as 2002, though, Canada's oil reserves were under 6 billion barrels, before the oil sands could be booked as reserves in large quantities. Without its oil sands, Canada would be just another mature oil province with declining conventional output. The question of how rapidly to develop those resources, and whether to export their output outside North America to any significant degree, is currently a hot topic in Canadian politics. The pipeline to transport this oil to Kitimat, British Columbia for export to Asia seems to be subject to a similar debate to the one we're having in this country concerning the Keystone XL line from Alberta to the Gulf Coast. But what if these projects didn't go forward? A world without oil sands might have a little less in the way of greenhouse gas emissions, but it would also have much higher oil prices, and those prices would be more volatile.
So what are the alternatives to these "dirty tar sands", as environmentalists now invariably refer to them? Well, if you're been reading my blog for a while, you know that wind and solar power don't enter into this discussion, because very little electricity is used for transportation and very little oil is used for generating electricity, outside of the developing world and now post-Tohoku Quake Japan. If we don't have access to oil sands imports, then the only other near-to-medium term options for reducing our oil imports from less stable suppliers involve more domestic oil production, more efficient vehicles, and more biofuels production.
Unfortunately the latest Department of Energy forecast incorporating all of those options still leaves us importing nearly 9 million barrels per day of oil in 2025. Without a significant portion of it coming from Canadian oil sands, we will still be forced to rely on imports from places like Venezuela and the Middle East, some of which aren't much more environmentally sound than the oil sands production. And that assumes that all the domestic production in these plans actually materializes. Turning up our noses at both offshore drilling and oil sands is pretty much mutually exclusive. (Or for that matter, shale gas and oil sands, even though these are different forms of energy.)
As for biofuels, we've already got just about as much corn ethanol as we can handle for many reasons, and the more advanced variety has not been especially cooperative in turning up on schedule. Replacing the oil sands capacity that the proposed Keystone XL pipeline could deliver would require more than 23 billion additional gallons per year of ethanol, or 180% of last year's US ethanol output. That figure exceeds the entire 2022 cellulosic and advanced biofuel target under the federal Renewable Fuels Standard. Biofuels are an important part of our energy mix, but the time when they could make oil sands crude unnecessary is still a long way off.
Americans are conflicted. We complain about $4 gasoline, and we're uneasy about another military intervention in the oil patch of the Middle East and North Africa, but then we throw obstacle after obstacle in the path of one of the few options that can provide us with a larger supply of reliable fuel from North America. No matter how sympathetic I am with communities that don't want the new pipeline to pass through or near them, or with concerns about the 17% increase in lifecycle greenhouse gas emissions that oil sands represent, compared to conventional oil, closing our border to additional imports of oil sands crude can only undermine US energy security, at the worst possible time.
This train of thought began with a sobering analysis of the energy implications of the unrest in the Middle East by Amy Myers Jaffe of the Baker Institute at Rice University in Houston. The challenge she highlights is much subtler than the risk of exports from countries like Libya being disrupted for a few months or even a few years. Existing spare capacity in other producing countries can cope with some of that, although a portion of that capacity is in other countries that could be just another domino or two down the road, while the rest is in Saudi Arabia, which might not be immune, either. Yet if the worst case is the disruption of exports, we have a substantial Strategic Petroleum Reserve to fall back on. Prices might rise significantly, but the prospect of no fuel at your local gas station at any price remains remote for now.
However, as Ms. Jaffe demonstrates, much of the incremental oil production capacity on which forecasters have been relying to meet additional oil demand over the next two decades, and to backstop declining production in non-OPEC countries, must come from the same region that is now in turmoil. And as the charts in her presentation show, revolutions--democratic or otherwise--rarely result in higher oil output. If new governments or chastened existing governments don't invest in developing that extra capacity, then Peak Oil won't just be a theoretical construct in geology; it will be a very real outcome in geopolitics, and one that strategic inventories like the SPR would be unable to mitigate.
We have had a tendency to view Canada as the Saudi Arabia of the north. Considering that we now receive more oil from there than from all the countries of the Persian Gulf combined, and that our NAFTA partner's proved reserves of 178 billion barrels are second only to those of the Kingdom, that's not unreasonable. As recently as 2002, though, Canada's oil reserves were under 6 billion barrels, before the oil sands could be booked as reserves in large quantities. Without its oil sands, Canada would be just another mature oil province with declining conventional output. The question of how rapidly to develop those resources, and whether to export their output outside North America to any significant degree, is currently a hot topic in Canadian politics. The pipeline to transport this oil to Kitimat, British Columbia for export to Asia seems to be subject to a similar debate to the one we're having in this country concerning the Keystone XL line from Alberta to the Gulf Coast. But what if these projects didn't go forward? A world without oil sands might have a little less in the way of greenhouse gas emissions, but it would also have much higher oil prices, and those prices would be more volatile.
So what are the alternatives to these "dirty tar sands", as environmentalists now invariably refer to them? Well, if you're been reading my blog for a while, you know that wind and solar power don't enter into this discussion, because very little electricity is used for transportation and very little oil is used for generating electricity, outside of the developing world and now post-Tohoku Quake Japan. If we don't have access to oil sands imports, then the only other near-to-medium term options for reducing our oil imports from less stable suppliers involve more domestic oil production, more efficient vehicles, and more biofuels production.
Unfortunately the latest Department of Energy forecast incorporating all of those options still leaves us importing nearly 9 million barrels per day of oil in 2025. Without a significant portion of it coming from Canadian oil sands, we will still be forced to rely on imports from places like Venezuela and the Middle East, some of which aren't much more environmentally sound than the oil sands production. And that assumes that all the domestic production in these plans actually materializes. Turning up our noses at both offshore drilling and oil sands is pretty much mutually exclusive. (Or for that matter, shale gas and oil sands, even though these are different forms of energy.)
As for biofuels, we've already got just about as much corn ethanol as we can handle for many reasons, and the more advanced variety has not been especially cooperative in turning up on schedule. Replacing the oil sands capacity that the proposed Keystone XL pipeline could deliver would require more than 23 billion additional gallons per year of ethanol, or 180% of last year's US ethanol output. That figure exceeds the entire 2022 cellulosic and advanced biofuel target under the federal Renewable Fuels Standard. Biofuels are an important part of our energy mix, but the time when they could make oil sands crude unnecessary is still a long way off.
Americans are conflicted. We complain about $4 gasoline, and we're uneasy about another military intervention in the oil patch of the Middle East and North Africa, but then we throw obstacle after obstacle in the path of one of the few options that can provide us with a larger supply of reliable fuel from North America. No matter how sympathetic I am with communities that don't want the new pipeline to pass through or near them, or with concerns about the 17% increase in lifecycle greenhouse gas emissions that oil sands represent, compared to conventional oil, closing our border to additional imports of oil sands crude can only undermine US energy security, at the worst possible time.
Friday, August 21, 2009
Climate vs. Security?
In the last few years I've watched perceptions of US energy security and climate change, the two main drivers of energy policy, converge gradually toward a general sense that smart climate policy will be good for energy security, and vice versa. There's even a growing understanding that a stable climate contributes to national security, distinct from any energy considerations. However, there are still cases with strongly divergent energy security and climate change implications, and a new pipeline that will deliver crude extracted from Canadian oil sands is a prime example. The US State Department's approval of this project looks entirely appropriate and sensible, even if it conflicts with the administration's emphasis on reducing greenhouse gas emissions. Like it or not--and largely because of past decisions concerning our own off-limits oil resources--Canadian oil sands have become an essential pillar of US energy security.
The "Alberta Clipper" pipeline of Enbridge, Inc. could eventually bring up to 800,000 barrels per day of Canadian crude oil to refineries in the US Midwest, as oil sands production in Alberta Province continues to grow. This oil would displace imports from the Middle East and West Africa, which absent oil sands are likely to grow, in spite of increasing biofuel production and higher fuel economy standards for new cars. That's because output from Mexico, our other main local supplier, is dropping sharply, while higher production from Brazil may only offset declines in Venezuela, which has grossly mismanaged its oil sector. Oil sands are already compensating for the steady decline in conventional Canadian oil production, and without them our imports from our largest oil supplier couldn't be sustained at their current level of roughly 10% of US oil consumption--equating to about five times the energy content of current US ethanol production. There is simply no realistic energy scenario for the next 20 years in which we could forgo imports of Canadian crude produced from oil sands, without a corresponding increase in imports from the Middle East.
The main concern cited about oil sands relates to its higher emissions of greenhouse gases, compared to conventional oil production. This is indisputable, though it's important to put those higher emissions into perspective, while also recognizing that technology and an increased Canadian emphasis on these emissions should reduce this disparity over time. The most recent study I've seen on the subject indicates that although the processes for producing useful liquids from Canadian oil sands result in roughly three times the upstream greenhouse gas emissions of the average barrel of US supply, the well-to-wheels lifecycle emissions are only 17% higher than average. In either case, most of the emissions from oil occur when it is burned in vehicles or other end-uses, not during production. While not insignificant, the excess emissions from oil sands can be offset less expensively elsewhere in our energy economy, particularly if the ultimate US climate legislation gives the utility sector the right incentives to cut its CO2 emissions, which are roughly a fifth larger than those from oil consumed in transportation.
Greenhouse gas emissions aren't the only environmental impact associated with oil sands, but we lack any reasonable or consistent way to assess the trade-off between the others and the potential impacts--physical or aesthetic--of increasing our own oil production from the significant resources we have placed off-limits to exploitation, including the Arctic National Wildlife Refuge and the outer continental shelves of California and other states. In effect, American policy makers and consumers have implicitly chosen to ramp up oil output in Alberta to spare other areas of greater concern to American voters. Such decisions have left us reliant on this Canadian energy resource, the incremental greenhouse gas consequences of which can be offset elsewhere. The State Department appears to have reached a similar conclusion.
The "Alberta Clipper" pipeline of Enbridge, Inc. could eventually bring up to 800,000 barrels per day of Canadian crude oil to refineries in the US Midwest, as oil sands production in Alberta Province continues to grow. This oil would displace imports from the Middle East and West Africa, which absent oil sands are likely to grow, in spite of increasing biofuel production and higher fuel economy standards for new cars. That's because output from Mexico, our other main local supplier, is dropping sharply, while higher production from Brazil may only offset declines in Venezuela, which has grossly mismanaged its oil sector. Oil sands are already compensating for the steady decline in conventional Canadian oil production, and without them our imports from our largest oil supplier couldn't be sustained at their current level of roughly 10% of US oil consumption--equating to about five times the energy content of current US ethanol production. There is simply no realistic energy scenario for the next 20 years in which we could forgo imports of Canadian crude produced from oil sands, without a corresponding increase in imports from the Middle East.
The main concern cited about oil sands relates to its higher emissions of greenhouse gases, compared to conventional oil production. This is indisputable, though it's important to put those higher emissions into perspective, while also recognizing that technology and an increased Canadian emphasis on these emissions should reduce this disparity over time. The most recent study I've seen on the subject indicates that although the processes for producing useful liquids from Canadian oil sands result in roughly three times the upstream greenhouse gas emissions of the average barrel of US supply, the well-to-wheels lifecycle emissions are only 17% higher than average. In either case, most of the emissions from oil occur when it is burned in vehicles or other end-uses, not during production. While not insignificant, the excess emissions from oil sands can be offset less expensively elsewhere in our energy economy, particularly if the ultimate US climate legislation gives the utility sector the right incentives to cut its CO2 emissions, which are roughly a fifth larger than those from oil consumed in transportation.
Greenhouse gas emissions aren't the only environmental impact associated with oil sands, but we lack any reasonable or consistent way to assess the trade-off between the others and the potential impacts--physical or aesthetic--of increasing our own oil production from the significant resources we have placed off-limits to exploitation, including the Arctic National Wildlife Refuge and the outer continental shelves of California and other states. In effect, American policy makers and consumers have implicitly chosen to ramp up oil output in Alberta to spare other areas of greater concern to American voters. Such decisions have left us reliant on this Canadian energy resource, the incremental greenhouse gas consequences of which can be offset elsewhere. The State Department appears to have reached a similar conclusion.
Thursday, February 01, 2007
Ethanol Supply Chain
Because of the problems involved in transporting ethanol in petroleum product pipelines, the key piece of infrastructure for our chosen fuel of the future is the railroad. Who would have guessed that the 21st century would owe such a debt to the 19th? Today's Wall Street Journal includes two articles describing the transportation hurdles and import barriers that ethanol will have to overcome to expand to the extent contemplated by the White House and Congress. High energy prices and environmental concerns are providing rail companies with wonderful new opportunities, but I hope their strategic planners are thinking carefully about where this could lead. Somewhere along the road to 35 billion gallons per year, the conventional wisdom about ethanol and pipelines will be challenged, perhaps in ways no one expects.
In some respects the development of ethanol is recapitulating the growth of petroleum a century ago. Although pipelines came along fairly early in the history of the oil industry, rail transport was a key supply chain link from its start in Pennsylvania, and it never went away. My first assignment after joining Texaco's Supply and Distribution department in the early 1980s involved trading LPG in tank car lots, and later I dealt with unit-trains of crude oil going from Bakersfield to Los Angeles. As interesting as all this was, I quickly discovered that trains are a lot more expensive and less reliable than pipelines, and I'm sure the ethanol industry is learning the same lessons. The incentives to shift from rail to pipeline will only grow, as ethanol volumes increase.
Besides its well-known incompatibility problems, ethanol faces other hurdles in shifting to pipelines. As crude oil production in the key ethanol producing region, including states like Illinois, Indiana, Kansas and Nebraska, declined from a million barrels per day in 1980s to less than half that today, existing oil pipelines were reversed and new ones built to supply the region's refineries with imported oil from Canada or the Gulf Coast ports. And the main petroleum product pipelines in the mid-continent flow north from the Gulf. That means that most of pipeline capacity between the Midwest, where ethanol is produced, and the Gulf Coast, where a third of America's gasoline is made, is going the wrong direction to help ethanol producers. As long as ethanol accounts for less than 2% of the country's liquid fuel supply, it can't win that battle.
As it grows, however, this impediment will turn into an opportunity, and some clever entrepreneurs will figure out that ethanol pipelines can share a right-of-way with crude and products lines going the other way. How big is the incentive? Ignoring transshipment costs and tank car rental fees, shipping ethanol from St. Louis to Houston by rail costs about 12 cents/gallon. Shipping gasoline from Houston to St. Louis on the Explorer Pipeline costs 3.5 cents. 8.5 cents per gallon would pay for a lot of pipe. And with ethanol being totally biodegradable, they might even be able to use cheaper materials to build their pipelines and the gathering systems needed to collect the ethanol from its widely dispersed sources. In any case, ethanol pipelines would face a significantly easier permitting process than anything involving oil or its refined products. If I were running a railroad, I'd enjoy those tariffs while I could, and start thinking hard about laying dedicated ethanol pipe.
In some respects the development of ethanol is recapitulating the growth of petroleum a century ago. Although pipelines came along fairly early in the history of the oil industry, rail transport was a key supply chain link from its start in Pennsylvania, and it never went away. My first assignment after joining Texaco's Supply and Distribution department in the early 1980s involved trading LPG in tank car lots, and later I dealt with unit-trains of crude oil going from Bakersfield to Los Angeles. As interesting as all this was, I quickly discovered that trains are a lot more expensive and less reliable than pipelines, and I'm sure the ethanol industry is learning the same lessons. The incentives to shift from rail to pipeline will only grow, as ethanol volumes increase.
Besides its well-known incompatibility problems, ethanol faces other hurdles in shifting to pipelines. As crude oil production in the key ethanol producing region, including states like Illinois, Indiana, Kansas and Nebraska, declined from a million barrels per day in 1980s to less than half that today, existing oil pipelines were reversed and new ones built to supply the region's refineries with imported oil from Canada or the Gulf Coast ports. And the main petroleum product pipelines in the mid-continent flow north from the Gulf. That means that most of pipeline capacity between the Midwest, where ethanol is produced, and the Gulf Coast, where a third of America's gasoline is made, is going the wrong direction to help ethanol producers. As long as ethanol accounts for less than 2% of the country's liquid fuel supply, it can't win that battle.
As it grows, however, this impediment will turn into an opportunity, and some clever entrepreneurs will figure out that ethanol pipelines can share a right-of-way with crude and products lines going the other way. How big is the incentive? Ignoring transshipment costs and tank car rental fees, shipping ethanol from St. Louis to Houston by rail costs about 12 cents/gallon. Shipping gasoline from Houston to St. Louis on the Explorer Pipeline costs 3.5 cents. 8.5 cents per gallon would pay for a lot of pipe. And with ethanol being totally biodegradable, they might even be able to use cheaper materials to build their pipelines and the gathering systems needed to collect the ethanol from its widely dispersed sources. In any case, ethanol pipelines would face a significantly easier permitting process than anything involving oil or its refined products. If I were running a railroad, I'd enjoy those tariffs while I could, and start thinking hard about laying dedicated ethanol pipe.
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