The ongoing displacement of coal by natural gas in the US electric generating sector was neatly illustrated in two articles published this week.  The Washington Post examined it from the perspective of utilities faced with expensive decisions about which fuel to bet on for the future, while the Wall St. Journal looked at the resource and tax implications of this trend for states.   The intensity of competition between coal and gas would have been hard to imagine just a few years ago, when the price and energy security advantages of the former seemed insurmountable.  The shale gas revolution continues to upend conventional wisdom on energy.

It's worth recalling that coal was once a widely-distributed fuel, powering homes, businesses, trains and factories, as well as power plants.  Most of its decentralized applications yielded to competition from the post-World War II oil boom, resulting in a nearly 40% decline in US coal demand between 1945 and 1960, on a BTU basis.  Coal got its second wind in response to the energy crises of the 1970s, when its promise of more than a century's worth of secure, low-cost supply trumped concerns about the environmental impacts of its extraction and consumption.  From 1972 to 2000 coal, together with nuclear power, displaced roughly two-thirds of the petroleum used in US power generation. That freed up oil for other, more valuable uses and solidified coal's energy security benefits in the minds of the public and policy makers.  In the process, coal's share of generation expanded from 44% to 53%. 

Much has changed in the last few years. From 2007 to 2011 a weak US economy and the rapid expansion of natural gas and oil production from unconventional sources shrank net US petroleum imports by nearly 30%, while increasing the country's effective energy independence--domestic production of all energy sources as a fraction of total consumption--from 70% to 80%. That lessens the salience of energy security, for which the gas and renewable energy sources perceived to be competing with coal can claim comparable benefits, along with domestic job creation.  And the gas supplies that constitute the main competition for coal are, in contrast to earlier gas booms, backed by resources with useful lives that could rival those of the nation's coal deposits. 

Based on recent gas prices, the cost of electricity produced by high-efficiency gas turbines now rivals coal-fired power from existing power plants and beats it for new capacity, and with fewer drawbacks.  Based on data from the Department of Energy for the 12 months ending this September, natural gas now commands a 30% share of the electricity market, having reduced coal's share from 43% to 37% in just the last year.

That's the context for the lengthy Washington Post article, which in the Sunday print edition was entitled, "The Coal Killer."  As an example of that premise, it highlights the impending retirement of the 745 MW coal- and oil-fired Salem Harbor, MA power plant that Footprint Power purchased from Dominion last year.  Footprint intends to shut down the remaining two operating units, demolish the facility, and replace it with a 630 MW state-of-the-art combined-cycle gas turbine plant.  The article goes on to mention several other cases of coal plants being replaced by gas units.  The quoted comments from various observers also underline the tension between views of natural gas as a bridge to a cleaner energy future and gas itself as that future. 

As Monday's Wall St. Journal article makes clear, the consequences of this trend extend upstream and downstream of the utilities and their power plant portfolios.  The surge of shale gas production since about 2006 has reduced both gas and coal prices, resulting in lower energy costs for consumers and industry.  That has led to a revival in some US manufacturing sectors, including petrochemicals and steel.  However, it has also resulted in coal mine closures and reductions in taxes derived from coal production.  This is felt most acutely in states like West Virginia and Wyoming, where both state and local budgets have been affected. 

It's premature to extrapolate the ultimate outcome of this competition.  Large uncertainties could affect its course, including environmental regulations, future demand--including gas exports--and advances in technology such as carbon sequestration. This is especially true globally, with shale gas outside the US generally at a much earlier stage of development.  Where conventional gas remains expensive, coal use is still rising.  In any case, the history of past energy transitions suggests that old energy sources never entirely fade away; coal may continue to lose market share in the US and become more of an export commodity, but it's unlikely to disappear entirely.  Meanwhile, shale gas looks like a classic disruptive innovation, the implications of which will play out over many years in ways we might not imagine today, near its start.

Earlier this week the International Energy Agency (IEA) released its annual long-term forecast, the World Energy Outlook (WEO).  Its projection that US oil output would exceed that of Saudi Arabia within five years has been featured in numerous headlines in the last few days, though some of the report's other findings look equally consequential.  That includes the continued strong growth of energy demand in China, India and other Asian countries, and the linkages between that growth and a dramatic expansion of Iraqi oil production.  The agency also set a cautionary tone concerning the increase in global greenhouse gas emissions accompanying all this growth.

In the IEA's primary "New Policies" scenario, the US overtakes Saudi  Arabia in oil production by 2017, adding 4 million barrels per day (MBD) of unconventional output, mainly from shale (tight oil) deposits such as the Bakken in North Dakota. US oil imports decline significantly, due in roughly equal measure to higher production and the implementation of strict vehicle fuel economy regulations.  As a consequence, US oil imports are expected to decline significantly, with the need for imports from the Middle East approaches zero within 10 years.  When this change is combined with the growth in oil demand in Asia, where China alone accounts for half the forecasted global growth in oil consumption in this period, the IEA envisions Asia becoming the recipient of 90% of Middle East oil exports by 2035.

The detailed assumptions behind the IEA's conclusions weren't  provided in Monday's public release.  These include crucial questions such as the assumed status of US rules barring most crude oil exports.  As noted in a Reuters op-ed, maximizing the potential of US unconventional resources may depend on allowing higher quality unconventional oil to seek global markets, while continuing to import oil from Latin America and the Middle East into Gulf Coast refineries geared to these heavier, higher-sulfur feedstocks.  The author also reminds us that the natural gas liquids included in the headline comparison with Saudi production are useful but quite different from crude oil, yielding little gasoline and diesel fuel.

The expected growth of energy demand in China remains extraordinary, even with the country's economic growth slowing from the levels seen a few years ago.  To put this in context, when Dr. Fatih Birol, Chief Economist of the IEA, presented the new WEO to the media in London on November 12th, he suggested that China's electricity demand would grow by the equivalent of "one US and one Japan of today" by 2035.  Much of that additional electricity generation is projected to come from renewables, nuclear power and domestic gas.  Nevertheless, and in spite of significant increases in China's unconventional gas production, the IEA forecasts that import dependence will grow from about 15% for gas and 50% for oil today, to 40% for gas and over 80% for oil by 2035.  That increase in imports would equate to additional hundreds of millions of dollars per year of outflows for energy.

In the view of the IEA, much of the extra oil demanded in Asia will be supplied by Iraq, which they project will increase its output from around 3 MBD today to 6.1 MBD in 2020 and 8.3 MBD in 2035, in the process becoming the world's second-largest oil exporter, after Russia.  Since the reserves to support that growth have already been identified, with much lower production costs than many other basins, the uncertainties involved are mainly political and structural.  Resolution of the current standoff with Iran over its nuclear program would provide even more Middle East oil for Asian markets.

As in its earlier "Golden Age of Gas" scenario, the IEA expects large increases in global natural gas consumption.  Unconventional sources, mainly in the US, China and Australia, would contribute around half the additional production required to meet expanded demand.  However, at the launch presentation in London Dr. Birol also stressed that unconventional oil and gas are still at an early stage, with significant uncertainties about the eventual magnitude of their resources.  This seemed to be a particular issue for the agency's post-2020 forecast of oil production in the US and gas production in China. 

Despite the rigorous analysis and level of detail involved in producing the IEA's World Energy Outlook, long-term energy forecasting should always be taken with a grain of salt.  Yet whether or not the highlighted trends mature precisely in line with these projections, the shifts that the IEA identified are significant and already becoming evident in current data for energy production, consumption and trade.  Even if North America failed to become a net oil exporter--which many equate with energy independence-- by 2030, the movement of the center of gravity of global energy trade towards Asia is essentially pre-determined: baked in by differences in economic growth rates and resource opportunities.  The economic, geopolitical and environmental consequences of that shift are just starting to take shape.

Most oil & gas companies in the US are currently focusing on producing liquid rich plays.  Given the decline in natural gas prices compared to 2008, this isn’t very shocking. As shown in the Baker Hughes rig count, it is clear that the number of rigs drilling for natural gas has been ever declining. Logically speaking, with such a precipitous decline in “gas rig” activity, one would think that natural gas storage would be decreasing year over year. However, in reality, this will be the 4th straight year that gas has hit record storage numbers. This shouldn’t be possible with gas rigs numbers decreasing from 1600 to less than 500. However, the reality shows otherwise and there lies some deeper truths.

The first thing one should note is that companies are constantly looking for “liquid rich plays.” There is a clear distinction in vocabulary that is not immediately clear. Liquid rich plays are not necessarily oil plays. They are actually gas plays that produce liquids either through natural processes (dropping from reservoir temperature & pressure to surface conditions) or artificial processes (going through a gas NGL processing plant). In actuality, the number of oil rigs in the US has been increasing, but not all of those oil rigs are actually drilling oil reservoirs. Portions of plays such as the Eagle Ford, Mississippian, Niobrara, and others have been classified as oil drilling when in reality sometimes greater than half of the production in the well is natural gas. This allows for a useful fiction in the public eye that companies are not drilling gas wells since gas is supposed to be uneconomic. However, in reality, these are gas wells, that are highly economic because they produce natural gas liquids and condensate liquids.

In example, in my previous work experience, I worked in the Eagle Ford shale drilling gas wells. However, these gas wells, also produced 60 BBL/MMCF of oil and 120 BBL/MMCF of Natural Gas Liquids after processing. The wells would have an initial production rate of over 7 MMCF/D. Doing some basic calculations, these wells were making over 850 BOPD IP rates (assuming a 2:1 price conversion on natural gas liquids). That is on top of the additional value from the natural gas. Finally, since gas wells have larger recovery factors than oil wells and drain larger areas due to mobility, these wells would have longer well lifes and shallower “oil” declines than a true oil well.

Thanks to natural gas liquids and condensate, there are numerous gas reservoirs that are profitable today and are not accounted for in most analysts’ discussions regarding US natural gas production and pricing. Since gas has become a dirty word to use, the industry decided to change the name of what they are doing to oil. However, in reality, the US continues to profitably produce natural gas reservoirs and will do so for years to come even if we have record supplies year over year. The proof is there in our 4th record year of gas storage.