The American Oil & Gas Reporter
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November 1, 2011 Ernest J. Moniz, Director, MIT Energy Initiative Reproduced for the Massachusetts Institute of Technology with permission from The American Oil & Gas Reporter
CAMBRIDGE, MA.– Natural gas is finding its place at the heart of the energy discussion. The remarkable speed and scale of developing shale resource plays has heightened awareness of natural gas as a key component of U.S. energy supply, lowered prices well below recent expectations, and is leading to significant opportunities for increased gas demand.
An MIT study, The Future of Natural Gas, looks at the economics and uncertainty of supply, and the role of natural gas in the overall energy system, especially in the context of constraints on greenhouse gas emissions.
Shale gas development has increased substantially assessments of the amount of resources that can be produced in North America at relatively modest cost. Consequently, the role of natural gas is likely to continue to expand, and its relative importance is likely to increase with tighter regulatory controls on greenhouse gas emissions.
In a carbon-constrained world, a level playing field–a carbon dioxide emissions price for all fuels without subsidies or preferential policy treatment–would maximize the value of the large U.S. natural gas resource base. While there are challenges, natural gas–the least carbon-intensive fossil fuel–can play an important role as the "bridge" to a low-carbon energy future.
Although the conventional global natural gas resource base is large, it is geographically concentrated. Excluding estimates of shale resources outside North America, about 70 percent of all gas resources are located in Russia, the Middle East and North America. By some measures, this makes global gas resources even more geographically concentrated than oil. It also means that political considerations and individual country depletion policies play at least as big a role in global gas resource development as geology and economics.
The United States and Russia are the world's dominant gas producers, but other producing countries also are experiencing significant growth rates, leading to expanding gas markets and increasing global cross-border gas trading. Global gas production rose from 74 trillion cubic feet in 1990 to 105 Tcf in 2009, which is almost twice the growth rate of global oil production during the same period. Much of this growth has been driven by the rapid expansion of production in areas that were historically not major producers.
Figure 1 depicts global natural gas supply curves that quantify the price required at the point of export to enable the economic development of a given volume of gas. Much of the global gas resource can be developed at relatively low prices at the point of export. For example, the mean estimate is that 4,000 trillion cubic feet of gas can be developed at or below $2.00/MMBtu, with 9,000 Tcf available at or below $4.00/MMBtu.
Although these certainly are very large volumes of low-cost gas, a large portion is geographically isolated from major consuming markets. The cost of transporting gas using either long-haul pipelines or liquefied natural gas terminals is much higher than oil. That means gas that can be developed economically at the export point at less than $2.00/MMBtu may well require an added $3.00-5.00/MMBtu in transportation cost. These high transportation costs are a significant factor in the evolution of the global gas market, and have a material impact on the future availability and price of natural gas supply.
Global Supply Cost Curve with Uncertainty (2007 Cost Base)
The natural gas supply landscape in the United States has changed greatly over the past five years, and the driving force has been rapid production growth in shale plays (Figure 2). The proportion of total U.S. gas production from shale resources grew from less than 1 percent in 2000 to 20 percent in 2010, and is expected to reach 25 percent by the end of this year. Such growth rates would be remarkable in any context, but in the United States–the world's largest gas consuming market–it rep- resents a true paradigm shift, allowing the United States to over-take Russia as the world's largest producer.
Lower-48 Annual Gross Gas Production
The emergence of shale gas also has resulted in dramatic in- creases in the estimated size of the U.S. gas resource base. Last year the U.S. Energy Information Administration increased its estimate of the U.S. shale resource to 827 Tcf, or 36 percent of all domestic gas resources. The rapidly increasing estimated size of the shale resource has generated significant excitement, both within the industry and farther afield. However, shale gas is still a nascent industry, and estimates of the size and relative economics of shale resources are still subject to considerable uncertainty.
A supply-side analysis conducted as part of MIT's The Future of Natural Gas study explored this uncertainty in terms of resource size and relative economics. Some of the key conclusions of the analysis include:
The impact of shale gas on the scale and economics of the U.S. gas resource base is substantial. The study found that relatively small volumes of gas are available at a price below $4.00/MMBtu, reflecting the maturity of the overall resource base. However, of the gas available in a moderate price range between $4.00 and 8.00/MMBtu, more than 60 percent is shale. For the coming two decades, the MIT analysis predicts U.S. gas prices in the $6.00-8.00/MMBtu range. At these price levels, shale gas will be the lowest-cost resource in most instances.
An important characteristic of shale resource plays is intra- and interplay performance variability. An illustration of this variability is shown in Figure 3A, which plots the probability distribution of the initial production rates of more than 1,600 wells drilled in the Barnett Shale in 2009. There is a threefold variation between the IP rates of good (P20) and bad (P80) wells. While such a wide range is uncommon in conventional gas, similar variability is observed in all major shale plays now in production. Naturally, this variability impacts the economics of shale wells.
IP Rate Probability Distribution (2009 Barnett Shale Wells)
Figure 3B illustrates how the performance variation of wells drilled during 2009 in five major gas shale plays translates into per-well break-even gas prices (BEPs). For these plays, the BEPs for P50 (median performance) wells range between $4.00 and $6.50/MMBtu. However, many of the wells in each play have much higher and lower BEPs. This demonstrates that producers are not drilling only low-cost shale resources, but sampling along the entire curve.
2009 Break-Even Gas Prices in Five U.S. Shale Plays
This is not ideal, and operators obviously would prefer to develop only the lowest-cost resources. However, as long as their overall portfolio BEPs are acceptable, variability in individual well performance is acceptable. That is not to suggest that operators are not interested in reducing variability. Obviously, significant effort is being undertaken to reduce well-to-well variability through better technology and methods.
Along with gas production variability, shale play economics can be significantly influenced by NGL production. Depending on the liquid-to-gas production ratio, the BEPs of wells drilled in wet areas of shale plays often are dramatically lower than they would be if wells produced only gas. Figure 4 shows the significant impact NGLs can have on shale well economics. In this example, the BEP calculated for a theoretical well assuming a 2009 Marcellus P50 gas production rate is plotted against a varying liquid-to-gas ratio at an oil/NGL price of $80 a barrel. The BEP drops from $4.00/MMBtu to $0.00/MMBtu as the ratio rises from 0 (a dry well) to 50 (a very wet well). With appreciable NGLs production, the gas effectively becomes free.
Impact of Liquid-to-Gas Ratios on Break-Even Prices
In wet gas areas within plays, shale wells that may not appear economic at first glance based on the cost of drilling and the price of gas alone, are in fact, likely to make money because of the favorable spread between oil and gas prices.
Of course, growing production from shale plays is not without challenges. Hydraulic fracturing raises concerns about the environmental impacts of shale production. The MIT study examined these environmental issues and identified a set of primary environmental risks, including contaminating groundwater aquifers while drilling and setting casing through shallow freshwater zones, on-site surface spills of drilling and completion fluids, excessive water withdrawals for high-volume fracturing, and heavy road traffic.
The analysis concludes that all of these risks are "challenging but manageable" through uniform application of best practices regulation and oversight. The study recommends complete public disclosure of fracture fluids, eliminating toxic components, and integrated regional surface water management plans.
MIT's "Emissions Predictions and Policy Analysis" global model was used to examine the role of natural gas in a carbon-constrained world by examining the complicated interplay of economics, a range of technologies, and trade flows for 16 regions, including the United States. The analysis assumed a 50 percent reduction in CO2 emissions by developed nations to 2050 with no offsets, a 50 percent reduction in CO2 emissions by large emerging economies by 2070, and no emissions reductions from underdeveloped nations.
There are several key takeaways for the U.S. electric generation sector. Figure 5 reflects a model driven by ruthless economics in the face of stringent CO2 limits. This figure graphically illustrates the essential role natural gas would play as the bridge fuel in a carbon-constrained market. It also makes the point that the bridge must have a suitable landing point.
Energy Mix in Electric Generation under Price-Based Climate Policy (Trillion kWh)
The results indicate that there would have to be significant demand reductions to meet the emissions reduction targets, and natural gas consumption would increase dramatically because of its lower carbon characteristics. Natural gas generation would almost totally displace coal generation by 2035, with carbon capture and sequestration too expensive to make inroads for many decades. By around 2045, however, natural gas itself would become too carbon-intensive under this scenario to meet the carbon limits and consumption would start to decline.
The changing U.S. natural gas supply situation is creating new opportunities for expanding use in the electricity, industrial and transportation sectors as a substitute fuel for coal, gasoline and diesel, particularly under a scenario of tightening emissions controls.
Natural gas combined cycle (NGCC) units are highly efficient, relatively inexpensive to build, and produce significantly fewer emissions than coal plants. But while the nation has more installed nameplate gas-fired generating capacity than coal-fired capacity, gas supplies only 23 percent of total U.S. generation compared with 44 percent from coal. NGCC units averaged less than half their capacity in 2009. The study examined opportunities created by utilizing this significant unused "surplus" NGCC capacity and the subsequent impact on carbon emissions.
Natural gas plants typically have the highest marginal cost (although this is changing) and tend to get dispatched after other fuel sources for power generation. This is because the marginal cost is dominated by fuel cost. What would the carbon impact be of changing this order to dispatch surplus NGCC generation ahead of older and inefficient coal units? The study found that carbon dioxide, mercury and nitrogen oxide emissions from power generation would be reduced nationwide by 20, 33 and 32 percent, respectively, each year, and an incremental 4 Tcf of natural gas would be consumed annually.
Industrial consumers represent 35 percent of U.S. gas demand, with 85 percent of that demand in the manufacturing sector. Within the sector, 36 percent of demand is for industrial boilers. Almost 70 percent of large industrial boilers are coal fired. Natural gas boilers are much cleaner than coal. In fact, "superboilers" are capable of operating at 94-95 percent efficiency. Replacing large coal boilers with natural gas superboilers would consume slightly less than 1 Tcf of incremental gas each year while reducing CO2 emissions by 52,000-57,000 tons per boiler per year, with a negative emissions charge of $5/ton.
Another sizeable demand growth opportunity exists in the transportation market. Although the U.S. natural gas vehicle market is small, there are 11 million natural gas vehicles on the road around the world, 99.9 percent of which use compressed natural gas. CNG is cheaper than gasoline on an energy equivalency basis, but there are upfront vehicle costs.
For a variety of reasons, some of which are not entirely clear, costs for both after-market conversion and factory-produced CNG vehicles are much higher in the United States than elsewhere. For example, the incremental cost for factory-produced vehicles in the United States is $7,000 compared with $3,700 in Europe. The incremental cost of after-market conversions is $10,000 in the United States while averaging only $2,500 in Singapore.
CNG offers a significant opportunity in heavy-duty vehicles used for short-range operation (buses, garbage trucks, delivery trucks, etc.) where payback times are three years or less and infrastructure issues do not impede development. CNG also can be an attractive option for light-duty fleet vehicles that travel high miles. In fact, CNG already is being utilized in both areas by governmental agencies and private corporations.
However, for light passenger vehicles, the high incremental cost of CNG vehicles creates long payback times for the average driver. Payback periods would be reduced significantly if the cost of converting from gasoline to CNG were reduced to European levels. Consequently, the United States should consider revising policies on CNG vehicles, including how after-market conversions are certified, to reduce upfront costs and facilitate bifuel CNG/gasoline capability. A CO2 emissions charge in a carbon-constrained market would favor CNG relative to gasoline vehicles and eventually lead to substantial penetration of CNG vehicles.
There may be opportunities for LNG in the rapidly expanding segment of hub-to-hub long-haul trucking operations where infrastructure and operational challenges can be overcome. However, as a result of these considerations, as well as high incremental costs, LNG does not appear at the moment to be an attractive option for general vehicle use.
Chemically converting natural gas to liquid fuels could provide a feasible alternative to CNG. Several pathways are possible, with different options yielding different outcomes in terms of total emissions and costs. Natural gas could even be converted to diesel and gasoline for use with existing infrastructure, although doing so would require more processing (and higher costs) than other chemical conversion options.
One such option is converting natural gas to liquid methanol. The United States already has large-scale industrial methanol production, and issues with using methanol as a transportation fuel are similar to those for ethanol (i.e., modest changes to engines because of its corrosive nature and building an appropriate distribution infrastructure). While methanol has emissions comparable to those of petroleum-derived fuels, it is significantly less expensive than gasoline on an energy equivalent basis. At a $4.00/MMBtu natural gas price, methanol production costs are about $1.30 for the energy equivalent of a gallon of gasoline. This is well below the gasoline production cost at today's oil prices.
Considering the importance of natural gas to the nation's economy, its ability to serve as a long-term bridge to a low-carbon energy future, and opportunities for improved utilization of gas resources, an increase is in order in the level of both public and cooperative public/private research and development funding.
Historically, public/private R&D played an important role in developing unconventional natural gas resources. Going forward, there are numerous R&D opportunities to address key objectives for natural gas supply and usage, including:
The administration and Congress should support a broad natural gas R&D program both through a renewed U.S. Department of Energy effort weighted toward basic research, and a complementary industry-led public/private program weighted toward applied R&D.
The vital role of natural gas is likely to continue to expand in most sectors of the economy under almost all circumstances. The relative importance of natural gas is likely to increase even further in a carbon-constrained market, since it is one of the most cost-effective means by which to maintain energy supplies while reducing emissions. This is particularly true in electricity generation, where natural gas sets the cost benchmark against which all other clean power sources will have to compete to remove marginal CO2 emissions.