Recently, across the US, there has an outpouring of hate for fracing.  From movies, such as Gasland and Promised Land, to local communities banning tight oil and gas operations, the issue of fracing has become a cornerstone of the environmental movement. There are people claiming that “Big Oil” is out there to pollute the water of America and destroy the earth. Of course, the reality is far from that. It has always been interesting that anything that is “big” in America is automatically considered bad as if the people that work in these companies are inherently trying to do something evil because they work for a successful business someone built. No one I have ever worked with in the oil industry has ever told me that they got into the business of energy production to engage in a Machiavellian scheme to destroy the earth. With that stated, it is important to look at the facts around fracing and to understand what the true risk factors are without all of the hyperbole surrounding it.

Last week the International Energy Agency (IEA) reported that the amount of carbon dioxide emitted for each unit of global energy use was essentially unchanged between 1990 and 2010, despite the implementation of global climate agreements and the expenditure of hundreds of billions of dollars for renewable energy projects and incentives.  Just a few days earlier, the US Environmental Protection Agency released its annual inventory of US greenhouse gas (GHG) emissions, showing a 1.6% reduction from 2010 to 2011.  US emissions were up 8% since 1990 but have fallen 5% since 2000 and nearly 8% from their pre-recession peak in 2007.  Much of the US's recent divergence from the global trend is attributable to the displacement of coal from the power sector by shale gas.   

As unwelcome as the IEA's finding was, it is unlikely to  have shocked anyone who understands the scale of global energy systems and the continued reliance of many developed and developing countries on coal for power generation.  The transition to lower-carbon energy systems is underway, as reflected in the details of the IEA report.  However, it will take additional decades to reach targets consistent with limiting the projected global temperature increase to 2° C, which the IEA indicates would require a 60% reduction in the carbon intensity of energy by 2050 from current levels.  That implies that energy companies still need to develop additional oil and gas resources in the interim, in order to support the economic activity that--among other things--will be necessary to fund the recommended investments in cleaner energy and energy efficiency. 

At first glance that might seem paradoxical.  After all, oil and gas account for 55% of US GHG emissions and around 40% of global emissions today.  However, when gas displaces a higher-emitting fuel like coal, global emissions fall.  This has been a matter of some controversy, due to uncertainty about the contribution of fugitive methane emissions from shale gas wells. Yet the estimates in the EPA inventory indicate that methane emissions from US natural gas systems actually fell by 9% between 2005 and 2011, even though US natural gas production grew by 27% over that interval, with shale gas output increasing by 950%.  A new analysis from ExxonMobil indicates that on a lifecycle basis, replacing coal with shale gas in power generation reduces GHG emissions by an average of 53%, while also reducing overall freshwater consumption by half.

Assessing the role of oil in the decarbonization of global energy is more complicated.  Oil exploration and development must continue, even in a static or eventually shrinking market, because reserves that have been produced must be replaced, by either new discoveries or further development of existing fields. Simply allowing today's oil fields to decline and hoping to make up their energy contribution from other sources would be very risky, particularly for the transportation sector with its extremely high reliance on oil. Moreover, four-fifths of the emissions from petroleum occur during end-use combustion.  That means that most emission reductions from petroleum must come about through reduced demand, via some combination of increased fuel efficiency, fuel substitution--particularly in those markets where oil is still used in electricity generation--and/or reductions in transportation metrics such as vehicle miles traveled.  

In a recent Bloomberg op-ed, Michael Levy of the Council on Foreign Relations considered the impact of increasing US oil production from the standpoint of both the "social cost of carbon" and its incremental contribution to global emissions.  He concluded that even at a high estimated environmental cost, the climate impact of an extra barrel of US oil would come in under $10 per barrel, well below its economic value.  He also concluded that significantly higher US oil production would add little to global emissions.  Its impact would be even smaller if OPEC producers reduced output to try to preserve high oil prices.  Mr. Levy addressed that scenario in an earlier op-ed.

Last week's IEA report concluded that the world is not yet on track to reduce emissions by enough to limit future temperature increases to 2° C, and more must be done.  Yet even if we were on track, the IEA forecasts upon which the report was based suggest that combined oil and gas consumption in 2035 would still be about 2% higher in 2035 than in 2010, with a bit of a shift from oil to gas.  On today's trajectory, both oil and gas will grow, even as renewable energy and energy efficiency expand significantly.  On either basis, an all-of-the-above approach to energy encompassing oil and gas, along with renewables, carbon sequestration, nuclear power and efficiency is fully consistent with addressing climate change.

The latest threats from North Korea don't appear to have rattled global markets very much.  The North has a track record of empty bluster, though it also has a history of unexpected provocations, such as the 2010 sinking of a South Korean patrol vessel and subsequent artillery barrage on South Korean territory, and stretching back to its seizure of the USS Pueblo in 1968.  Yet while experts attribute recent warnings of "thermonuclear war" to a state functioning as a "protection racket", the consequences for energy markets of a miscalculation resulting in armed conflict could be significant.

The current episode includes much of the standard, alternate-reality rhetoric from Pyongyang, along with new elements such as its declaration that the armistice ending the Korean War in 1953 is invalid, and threats to shut the Kaesong Industrial Complex.  The latter jointly operated enterprise zone in North Korea was an outgrowth of North/South cooperation during a previous thaw.  However, at least one expert sees the main difference this time in the reaction of the US, which has responded to pressure from Kim Jong Un, grandson of North Korea's founder Kim Il Sung, by demonstrating its capability to deploy a wide range of advanced offensive and defensive weaponry to the region.

 The risks to energy markets from all this saber rattling might seem remote.  Conflict is usually bullish for oil, but neither South or North Korea is a major producer or exporter of oil or gas.  In fact, South Korea ranks among the world's top oil importers, consuming around 2.5 million barrels per day while producing less than 100,000 barrels per day, itself.  However, South Korea's refineries are an important element in regional refined products supply chains; three are ranked among the 10 largest refineries in the world.  According to Platts, refined petroleum product exports accounted for over 40% of the country's refinery output and became South Korea's largest exports by value last year.  That's remarkable, considering the country's exports of consumer electronics, cars and appliances.

Nor is it a coincidence that the South's three largest refineries were built as far as possible from the border with North Korea, with two located within the historic "Pusan Perimeter"--the portion of South Korea that was not overrun in the 1950 invasion by the North--and another nearby.  That places the bulk of South Korean refining capacity well beyond the range of the artillery that threatens Seoul , though not outside the range of the North's ballistic missiles.  SK Energy's smaller, under-utilized Incheon refinery, roughly the same distance from the border as Seoul, looks most vulnerable, at least on proximity.

South Korea's  refineries are generally less complex than similar US refineries, but what they lack in upgrading capacity they make up for in overall throughput.  Conversion hardware for producing transportation fuels account for half or less of downstream capacity per barrel of crude processed, compared to the average US refinery.  In general these facilities must run significantly more crude oil, or lighter crudes, to yield the same volume of gasoline, diesel and jet fuel.  In the process they make large quantities of other products, such as petrochemical feedstocks and fuel oil for further processing or export.  And they always seem to be engaged in various expansion projects, as I learned first-hand when I was involved in Caltex's investments in its Korean affiliate, now called GS Caltex.

In the event of an actual military crisis on the Korean peninsula , whether intentional or due to miscalculation, global and regional energy markets could be affected in two principal ways.  Large quantities of crude oil and LNG bound for Korean ports would likely have to be diverted on short notice to other destinations, raising uncertainty about subsequent shipments. That should put downward pressure on both markets, at least in the near term.  At the same time, refined product exports from South Korea might be curtailed, even if the country's refineries had not been attacked directly.  That would result in a scramble for products in the region, including in China, which along with Japan and Singapore is a major export destination for Korean refiners.  An analysis from 2010 saw the possibility of inflationary pressures and reduced economic output in China in such a scenario. 

Another Korean conflict would certainly feed energy market volatility, while the North's nuclear weapons, however crude they might be, add a significant dimension of risk and unpredictability to an already dangerous situation.

Recent comments by Saudi Arabia's oil minister, Ali Al-Naimi, indicated that Saudi Aramco would soon begin exploring the country's shale gas resources.  As another means of reducing oil consumption in the Kingdom's electricity sector, in order to preserve oil exports, this appears to make both practical and economic sense.  However, as noted by the Wall St. Journal, compared to the US Saudi Arabia has much less water available for the hydraulic fracturing of shale and tight gas reservoirs.  Absent a reallocation of its substantial conventional gas production, Saudi shale gas could become a key factor in global energy security.  However, the techniques employed to extract it might be different from those that currently dominate the US shale gas scene.

It must seem odd that Saudi Arabia would even be interested in shale gas, a resource that wasn't exploited in the US until conventional gas production was declining steadily.  Saudi Arabia might still be the world's largest oil producer, at least for now, but it is not the "Saudi Arabia of natural gas".  Although the country has proved gas reserves comparable to those of the US, it apparently didn't win nature's gas lottery on the Arabian Peninsula.  Saudi gas reserves and production amount to only about 10% and 19%, respectively, of the Middle East's gas totals.  Iran and Qatar are far ahead.  And while Saudi gas production has doubled since 2000, output in neighboring Qatar has expanded by a factor of six in the same interval. 

Much of the Kingdom's conventional gas reserves are associated with oil production and are often required to be reinjected to maintain reservoir pressure and oil output.  Available Saudi gas has been preferentially allocated to industrial projects, such as petrochemicals expansion.  As a result, little new gas was supplied for power generation, so  the Saudi electricity sector has been burning large and increasing quantities of oil that could otherwise be exported.  The need for additional gas has become acute, but exploration in the vast Empty Quarter has not yielded the expected gas bonanza, while the internal price of natural gas has been constrained at levels well below even recent low US natural gas prices--too low to make most new production attractive on its own merits.

As if the economics of shale gas development weren't challenging enough in such an environment, the key ingredient that has fueled the US shale revolution, water, is in short supply in Saudi Arabia.  The needs of cities and industry in this arid country exceed the water supply from aquifers to such an extent as to require 27 desalination facilities, delivering nearly 300 billion gallons annually.  At several million gallons of water per hydraulically fractured shale gas well, the logic of burning oil to desalinate water to produce gas looks questionable.  Fortunately, there are multiple emerging pathways for reducing or eliminating net water consumption in "fracking". 

For starters, many US producers now routinely recycle the 10-30% of injected water that typically flows back from the well after hydraulic fracturing, for use in subsequent wells.  Recycling has become the standard in places like Pennsylvania's portion of the Marcellus shale, reducing the call on fresh water for fracking. The oil services industry offers various techniques for cleaning "flowback" water, and new ones are under development, including the use of algae. 

Drillers can further reduce freshwater consumption through the use of nitrogen in foam or other forms.  ERDA, a precursor of the US Department of Energy, conducted research on that technique in the 1970s, and it has been refined since then.  Nitrogen is readily available from air separation plants and does not depend on water, though it does require energy.

Another approach for waterless fracking has been field-tested in Canada, using gelled propane.  A blog post in Scientific American described some of the pros and cons of this method, which is more expensive where water is cheap but might fit the bill in dry regions where LPG is readily available.  For that matter, it might make sense in New Mexico if the Mancos Shale of the San Juan Basin turns out to be another viable tight oil play. 

The upshot is that a shortage of fresh water shouldn't constitute an insurmountable obstacle to exploiting Saudi Arabia's unconventional gas resources, which Mr. Al-Naimi cited at 600 trillion cubic feet.  However, it remains to be seen whether shale gas development is the best answer to a problem that has been created by selling natural gas to industry for as little as $0.75 per million BTUs, while burning $100 oil ($17 per million BTU) to generate electricity.  Whether the ultimate solution is shale gas or something else, resolving this gap in Saudi industrial policy could have a significant impact on future oil prices.  

The 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 the nation's 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. 

It's ironic that "Argo", a film set against the backdrop of the 1979 Iranian Revolution, should win this year's Academy Award for Best Picture just two days before the start of a new round of nuclear talks involving the inheritors of that revolution.  The pressure from UN sanctions on Iran and the potential for armed conflict if the current stalemate breaks down continue to burden global energy markets, contributing to the current high price of UK Brent crude, the global oil benchmark.  Resolving these tensions will require proving a negative with regard to Iran's intentions and overcoming three-plus decades of mutual distrust and suspicion. That's a tall order for the latest set of negotiations being held this week in Kazakhstan.  

Assessing the likelihood of a diplomatic breakthrough depends on the answers to two fundamental questions.  The first concerns the true purpose of Iran's nuclear program, which encompasses the entire fuel cycle from enrichment and fuel fabrication to civilian research and power reactors.  If all the regime has in mind is adding capacity to its domestic energy mix, the nuclear route represents an extraordinary choice for a country so rich in hydrocarbons. 

Recently, the price and availability of natural gas and renewable energy have impaired the economics of new nuclear power in the US and Europe, but this is old news in Iran.  With 16% of the world's natural gas reserves, Iran produces just 4.6% of world gas output--a distant fourth behind the US, Russia and Canada. So Iran's easiest  and least controversial energy option would be to ramp up its gas industry.  Combined-cycle gas turbines are highly efficient, and their cost per megawatt of capacity is a fraction of nuclear's.  Factoring in the external constraints that the country's nuclear efforts have also attracted, it's hard to see why any government would pursue this choice so relentlessly if it didn't also intend to create at least the option for building nuclear weapons in the future. The cost of those constraints has grown in the last several years. 

Tighter international sanctions have limited Iran's oil exports and its access to the global financial system.  In its January Oil Market Report, the International Energy Agency reported that Iran's oil production fell by 650,000 barrels per day (bdp) last year and is now a million bpd below recent capacity. Iran lost around $40 billion in export revenue last year, at official selling prices, equating to 8% of the country's economy at official exchange rates.  If sustained, sanctions could shrink Iran's long-term oil production capacity.

Despite these costs Iran has taken a relatively hard line going into the talks in Almaty. Its actions beforehand sent mixed signals, including the deployment of a new generation of uranium-concentrating centrifuges and the selection of up to 16 new nuclear reactor sites.  This was tempered by a move to convert part of its concentrated uranium stock into fuel for its research reactor.  Meanwhile, Iran has dragged out discussions with the International Atomic Energy Agency, the UN's nuclear watchdog, aimed at resolving suspicions about past clandestine nuclear weapons work. 

The other basic question underlying these talks concerns the resolve of the "P5 + 1" group--the US, UK, France, Germany, Russia and China--to maintain pressure on Iran over this issue.  This has multiple dimensions.  On the economic front, sanctions on Iran have cut world oil supplies by around a million bpd, while outages in Sudan, China and elsewhere are contributing another million bpd of lost output.  As a result, oil prices have remained persistently high, despite weak demand in the US and EU and the dramatic resurgence of US oil production, which has grown by a million bpd since 2009.  If Iran sanctions and the risk of conflict there have added $10 per barrel to the global price of oil, then the impact on the US and Europe would be on the order of $70 billion per year.  That's less of a burden to these economies than $40 billion of lost revenue is to Iran, but it's still an unwelcome drag at a time of general economic weakness. 

From a security perspective, none of the P5 + 1 would be eager to see another war in the Middle East, let alone to prosecute one.  Secretary of State Kerry warned of "terrible consequences" if negotiations eventually failed, but the Pentagon faces sharp budget cuts, and European participants seem prepared to negotiate indefinitely, regardless of the outcome.  Moreover, throughout the confrontation with Iran, critics have argued that a nuclear-armed Iran could be contained and deterred in much the same way the Soviet Union was.  This rationale comes from think tanks across the political spectrum. If it were more widely accepted, it would undermine the case for the military option that represents the ultimate backstop of carrot-and-stick diplomacy with Iran.

There are few paths out of this maze that don't lead to "red lines."  If Iran wants only nuclear power, it can yield; if it wants nuclear weapons, it can't.  Otherwise, if the current talks or the inevitable next round lead to an easing of sanctions--and potentially lower oil prices--it would likely be because the rest of the world has grown as tired as Iran of the pain of perpetual sanctions.  Time is now on Iran's side. 

by Geoffrey Styles, Managing Director of GSW Strategy Group

The spread between the US and international crude markets has grown very wide.  West Texas Intermediate crude currently sells at about a $21 per barrel discount to UK Brent crude--an extraordinary markdown for a grade of oil that was the world standard just a few years ago. In a post last December I discussed the influence of pipeline bottlenecks, particularly in the middle of the US, on this relationship.  This week I read an interview with an oil investment analyst questioning the notion that relieving those bottlenecks would bring US crude back into alignment with the global market.  His argument hinges on the capability of US Gulf Coast refineries to adapt to a diet of lighter, sweeter crude oil, compared to the heavy grades they've been accustomed to running.   Although his point serves as a useful reminder of the complexities affecting oil prices, I can't help wondering if it underestimates the flexibility of the US refining system.

I doubt there's a generic answer to the question Mr. Schaefer of the Oil & Gas Investment Bulletin poses.  It's not just a matter of whether it might be more profitable for these refineries to process heavy oil and export light, as I've suggested in the past, but if refineries that have been modified for a heavy crude slate can still revert to running the lighter crudes coming out of the Bakken and Eagle Ford shales, which seem broadly similar to those for which many of them were originally designed.

To a large extent that would depend on the specific configuration of each refinery, along with the market it serves.  Understanding why requires at least a cursory understanding of how refineries work.  If you look at even a simple refinery flow schematic, you'll notice numerous interconnections between the various process units.  Unfinished products flow from one unit to the next until blended finished products come out the other end, but those aren't the only important flows.  What makes today's refineries around 90% efficient is clever recycling of heat and byproducts like hydrogen and fuel gas.  In order for the whole facility to operate smoothly, all its units must remain in balance with each other.  If you feed the atmospheric distillation column, or "crude unit" at the front end with very light crude oils that, when distilled into their components, overwhelm some downstream units and starve others, that careful integration will break down. 

This seems to be the essence of Mr. Shaefer's point: that the Bakken and Eagle Ford crude streams are too light, yielding abundant LPG, gasoline and diesel but insufficient "gas oil" and residue to keep the fluid cat cracker--the gasoline-making heart of a modern refinery--and other downstream units running properly.  For some facilities in some locations that could be an important insight and limitation.  Certainly the California refinery where I once worked as a process engineer would have choked on 47 gravity Eagle Ford or 43 gravity North Dakota Sweet, having been designed for an average API gravity (a measure of crude oil density) of around 20.  However, it's worth recalling that no significant new oil refinery has been built in the US since the 1970s, although many have been upgraded substantially since then. That means that most of today's Gulf Coast refineries have cores that were built at a time when domestic light sweet crude was still abundant.

Refinery engineers and the supply departments that work with them can also be quite resourceful. I recall that when I was a trader for Texaco's US West Coast operations in the 1980s, we routinely purchased intermediate feedstocks from other refiners, to keep our refineries' cat crackers and cokers running during crude unit maintenance or when their current crude slates didn't naturally provide enough.  Between shifts in the mix of other crude oils run in conjunction with light oil, and supplementing with feedstock purchases, Gulf Coast refiners might have more flexibility to maximize purchases of shale oil, or "tight oil" than Mr. Shaefer's argument credits.

Ultimately this issue factors into a larger debate concerning how to extract the greatest benefit from the new oil bounty that shale production techniques are providing.  Are we better off with constrained pipelines that force some producers to discount their output so it can still reach market by rail or truck, and incidentally provide some refineries with a cheap source of crude?  Does the maximum advantage accrue from ensuring that all US crude production is processed in US refineries, even if they increasingly export their products internationally, in light of weak US demand?  Or should we suspend outdated crude oil export restrictions and allow both producers and refiners to compete in the same global market that already sets most US refined product prices?  That's a worthwhile debate, and I'd be surprised if it were settled based on the physical constraints of the sophisticated refineries of the US Gulf Coast.

by Geoffrey Styles, Managing Director  of GSW Strategy Group

The sudden abundance of natural gas in the US triggered a startling divergence of crude oil and natural gas prices that, in turn, has energized the advocates of using more gas in transportation.  Yet despite the availability of wholesale natural gas at less than $0.60 per gasoline gallon equivalent (GGE), and with retail compressed natural gas (CNG) prices under $2.00/GGE in many locations, natural gas accounted for less than 3% of US transportation energy consumption in 2011--most of it attributable to pipeline compressors.  The picture is very different in countries like Italy and Pakistan, where CNG has a significant market share in motor fuels.  As the US looks ahead to greater reliance on secure domestic gas for road transport, it's worth considering why other countries have such a big head start.

The obstacles to greater market penetration by natural gas in transportation are well known.  CNG and LNG (liquefied natural gas) require new infrastructure.  Many more retail gas facilities would be needed to assure motorists of convenient access  at service stations. CNG takes a separate dispenser and compressor, while LNG requires both a new pump and insulated storage.  Where pipeline gas is unavailable, such as in parts of the northeast, additional investments in the local "gas grid" may also be necessary.  

Vehicle conversion costs represent another significant barrier. Engine modifications and crash-resistant fuel tanks add significant costs for both new vehicles and retrofits.  Even with gas priced well below gasoline or diesel fuel, the payback for these costs can be lengthy.  That's one reason that gas has made greater strides in bus, truck and delivery fleets in the US than for personal cars, since the more intensive use of such vehicles substantially shortens the resulting payout periods.  Countries with high gas-vehicle penetration typically have government policies and incentives in place to promote the use of gas by mitigating these obstacles.

Italy leads the EU in CNG vehicle adoption, with more than 11% of new passenger cars equipped for natural gas last year.  That compares to 0.01% for the US in 2012, where only one CNG model, a Honda, was sold.  The Italian government promotes natural gas use in vehicles both directly and indirectly.  The country provides a subsidy of €700 ($945) to purchasers of CNG automobiles, while manufacturers like Fiat offer discounts to expand their market for CNG cars.  Incentives were even larger a few years ago. The government also makes retail petroleum products extraordinarily expensive with high taxes. So even though Italy is a large net importer of natural gas, CNG is much cheaper than gasoline or diesel at the pump.

Fuel availability may also have something to do with the disparity in adoption rates. Despite having an 83% smaller overall vehicle population , Italy has over 40% more CNG or "Autogas" refueling stations than the entire US, at around 900.  This is due in part to state-level incentives, with 50-70% of the cost of a new CNG filling station reimbursed by regions such as Liguria, Lombardy, and Piemonte.

In terms of market penetration, Pakistan, which is self-sufficient in gas, leads the world in natural gas vehicles, at 80%.  That translates into over 2 million CNG vehicles, the result of a determined effort on the part of the government to reduce imports of petroleum by shifting to domestic fuels, with gas as its best option.  This is a common theme in the non-oil-exporting developing world, where oil imports impose a large drag on national trade balances.  CNG use in Iran is even higher than in Pakistan, as an unintended consequence of protracted international sanctions. 

For the US, where oil production is increasing and oil imports declining, a shift to natural gas for transportation is likely to remain an opportunity, rather than a matter of necessity.  The "NATGAS Act", a bill proposing incentives for CNG and LNG along the lines of the Italian model has languished in the US Congress for several years.  It remains to be seen whether this will become a higher priority in the newly elected Congress, which has shown early signs of interest in breaking the recent logjam on energy legislation. 

In the meantime, adoption of natural gas vehicles in the US will proceed based on market forces, supported by a small advantage in the way CNG cars are counted in manufacturers' fleets under the stringent federal fuel economy regulations issued last summer.  That could lead to natural gas fueling 3% of US vehicles --mostly trucks--by 2020, based on the analysis of a partner at McKinsey & Co.  Much like the case for energy efficiency investments, the available savings indicate a much larger potential, but funds for CNG/LNG transport must compete with other priorities.

by Geoffrey Styles, Managing Director  of GSW Strategy Group

2012 was a remarkable year for energy in the US, with domestic output of oil, gas, wind and solar energy all advancing strongly.  This was the result of an unfolding revolution in unconventional oil and gas, along with federal, state and local incentives and regulations promoting renewable energy.  Yet despite extensive media coverage and vocal constituencies for each of these energy sources, I haven't seen any recent efforts to compare their respective contributions to US energy supplies. 

That may be due in part to the confusing array of energy units involved. It's daunting to match up oil in 42-gallon barrels (bbl), gas in cubic feet or British Thermal Units (BTUs), and wind and solar in kilowatts (kW) or Megawatts (MW) of capacity, or kilowatt-hours (kWh) or Megawatt-hours (MWh) of actual generation.  Conversion factors among these various units are easy to find on the internet.  However,  meaningful comparisons are complicated by important distinctions between liquid or gaseous fuels and grid electricity, and the fact that these energy sources compete with each other only in specific situations. 

For purposes of comparison, since wind and solar routinely compete with gas-fired generation, let's assume that the output of wind turbines and solar panels can be equated to the power from a natural gas turbine with an effective heat rate of 7,000 BTU/kWh.  That recognizes the efficiency losses in fossil generation and the premium value of electricity to end users.  Gas and gas-equivalent renewables can be further equated to oil using the standard conversion factor of 5.8 million BTU/bbl.  So even though wind and solar rarely compete with oil in the real world, because less than 0.6% of US electricity is now generated from petroleum products or byproducts, we can still assess their relative contributions to America's energy economy in familiar terms.  Please note that Energy Information Agency (EIA) data on production and generation for the full year won't be available for a few months, so the figures below are based on published data for the most recent 12-month periods.

Natural gas posted the biggest gain last year, with "marketed gas production", including gas liquids like ethane, propane and butane, growing by 1.57 trillion cubic feet for the 12 months ending in October 2012, compared to the same period a year earlier.  That's equivalent to adding at least 750,000 bbl/day of oil.  US gas production appears to have set an all-time record last October.

Oil production also grew rapidly in 2012, as noted several times in the presidential campaign and debates. Thanks to surging tight oil (shale oil) production in North Dakota, Texas, and elsewhere, US crude oil output increased by 710,000 bbl/day on a November-October basis.  In fact, October's production of 6.82 million bbl/day was the highest for any month since December 1993.  Recent production looks even higher.

Although final installation data aren't in yet, wind power also had a banner year, with developers on track to install between 11,000 and 12,000 MW of new capacity in the US.   Much of this growth was attributable to companies accelerating projects in anticipation of the scheduled December 31, 2012 expiration of the federal Production Tax Credit, or PTC, the main US tax incentive for wind energy. As it turned out, the Congress extended the PTC for another year as part of the recent "fiscal cliff" deal. On the basis of the most recent 12-month comparisons from the EIA, US wind farms generated 21.6 million MWh more last year than the previous year.  That equates to 150 billion cubic feet (BCF) of natural gas, or around 71,000 bbl/day of oil.

That brings us to solar, which was on pace to set a record of around 3,200 MW of new installations in the US in 2012.  On a November-October basis new solar panels added roughly 2.3 million MWh of reported generation last year, equivalent to 16 BCF of gas or 7,600 bbl/day of oil. This probably doesn't capture the contribution of all grid-independent installations, but it's unlikely to be off by more than a factor of 2.

Although the above chart shows that wind and solar power have a long way to go, both have earned credibility by advancing to the point of being measurable on the same scale as oil and gas.  Both contribute to reducing emissions. At the same time, the significance of developments in US unconventional hydrocarbons leaps off the page.  In just the last year, for the second year in a row, shale gas has added domestic energy production equivalent to the entire current output of all US non-hydro renewable electricity generation: wind, solar, geothermal, biomass and waste power. Tight oil added a like amount in 2012.  We're clearly in the midst of an energy transformation, but it doesn't much resemble the one that was anticipated just a few years ago.   

Lately, I have been receiving a large number of articles denying that peak oil will ever occur. The two topics that are almost always cited are the prevalence of shale oil and that oil is abiogenically sourced. These topics are actually diametrically opposed to each other which make for an interesting discussion topic. The first theory allows for human ingenuity to overcome a decade’s long problem of decreasing US oil production. The second theory claims that the world will never run out of oil due to oil not being produced through biological means and that the Earth will naturally recharge all the oil we use.

 The New York Times recently reported that the US will become the top oil producer in the world by 2017 and will even be a net energy exporter in 2030. There is no doubt that US shale oil production has been a game changer. Note in the chart below provided by the EIA how dramatic US oil production has increased over the last two years, reversing a decline present over the last 20 years.  The question is will shale oil solve all of our world petroleum problems for years to come? The first issue is to understand the differences in how shale oil vs. abiogenic oil works.

The theory of shale oil production is that petroleum is derived from ancient organic materials, such as algae, that were preserved in anoxic conditions where bacteria couldn’t destroy them. These organic materials were then buried deep into the Earth over tens of millions of years along with sedimentary rock debris. As a result of increased pressure and temperature, the organic material was converted into oil, gas, and coal. These organic rich sedimentary rock beds became the “source rock” for almost all of the migrated oil and gas into conventional oil and gas fields discovered over the last 100 years. Shale oil production came into play when someone made the decision that it would be an intelligent idea to drill the source beds which sourced all of the conventional fields and put massive hydraulic fractures on them, realizing that a lot of the oil in them had never escaped. Clearly, this idea has functioned pretty well. The chief reason why the chart above looks like it does is because of this theory of petroleum production. It has also been shown that you can generate oil from algae to make bio diesel. This is one of the most exciting newest forms of alternative energy.

Abiogenic oil proposes that oil and gas is produced from natural non biological processes from the center of the Earth and its mantle. This theory was developed chiefly by scientists in the Soviet Union. The articles I have recently read that have led to a resurgence of this theory are related to the discovery of lakes of liquid methane and methane rain on Titan (a moon of Saturn where the temperature is -180 degrees Celsius). Most of the hydrocarbons found seem to be simple ones such as ethane and methane and not complex hydrocarbons such as the ones found in oil. Although this does lead some credence to the theory that oil can be produced abiogenically, it does not account for the bulk of oil and gas deposits on Earth. Additionally, there have yet to be any significant discoveries of fields drilled based on this theory nor have there been examples of significant recharging of any oil reservoirs in the world. Even if the Earth was generating hydrocarbons, the mechanism would be very slow and wouldn’t have an appreciable effect compared to the rate we withdraw oil from the Earth currently. More importantly, if this was a main mechanism for hydrocarbon generation, we would not have such unbelievable success in drilling shale oil source beds.

Given that oil reservoirs aren’t replenishing anytime soon and we don’t have to deal with “methane rain” here on Earth, will shale oil resolve peak oil? There is no doubt that there are vast reserves throughout the world to tap of this resource. Currently, only the US and Canada have the technology to commercially exploit this resource to the degree needed to change the natural decline profile of the last 20 years.  However, there is no reason why other countries can’t learn from the US and start producing their own source rocks. The question is at what price point will oil become too expensive for oil production to keep growing? The marginal cost of adding additional oil production in the US to replace and increase our current supply is now over $70 a barrel with some sources even saying up to $92 a barrel.  This number is going to continue to increase since drilling horizontal wells is expensive and cheaper sources of oil are going to deplete over time.  As we replace cheaper OPEC oil with more expensive and technologically driven oil production, global commodity prices will have to respond by increasing the base price of oil. So in conclusion, the real issue isn’t peak oil. I think we have plenty of oil for years to come. The question is what is the peak price of oil before some alternative is cheaper?