Unconventional sources brighten the U.S. supply outlook.
Henry R. Linden is Max McGraw Professor of Energy and Power and Engineering and Management Director, Energy + Power Center. The author gratefully acknowledges the assistance of Ivan Coutinho, a chemical engineering graduate student at Illinois Institute of Technology (IIT) in this study, and the financial support of IIT’s Chemical and Biological Department.
The future of natural gas supplies in the United States looks promising due to rising projections of recoverable resources, including unconventional production. A strong supply outlook bodes well for using natural gas as a low-emission transportation fuel.
This article deals with the vastly improved outlook for U.S. natural gas supply as a result of sharp increases in recent projections of the total of proved reserves and unproved technically recoverable resources, as well as of unconventional naural gas production. On this basis, the article’s original draft concluded that natural gas prices would remain in the $7.00 to $7.50/million Btu range. In fact, New York Mercantile Exchange natural gas futures dropped into the $5.00 to $6.00/million Btu range in mid-November 2008 and remained in this range throughout December 2008 and the first half of January 2009, while the two benchmark crude oil prices—West Texas Intermediate and North Sea Brent—dropped to roughly $37 to $46 per barrel, their lowest level in the past four years.
On Aug. 11, 2008 the American Clean Skies Foundation (ACSF), a little known organization, released a study that concluded the United States has 2,247 trillion cubic feet (Tcf) of natural gas proved reserves and unproved technically recoverable resources equivalent to 118 years at current production levels. This would be equivalent to 19.04 Tcf/year, which is less than the actual production of 19.278 Tcf/year in 2007, according to the Energy Information Administration (EIA), including major contributions from unconventional resources.1 Unconventional natural gas consists of gas from tight sands, coal-bed methane and especially from Devonian shale.2 The 2,247 Tcf greatly exceeds the Dec. 31, 2006 value published by the Potential Gas Committee of the Potential Gas Agency of 1,320.950 Tcf, which includes 166.141 Tcf of coal-bed methane.3 Adding the Dec. 31, 2006 proved reserves in the lower 48 states of 200.840 Tcf and 10.245 Tcf in Alaska for a total of 211.085 Tcf,4 the grand total Potential Gas Committee estimate is 1,532.035 Tcf. For some reason, the Potential Gas Committee used a value of only 204 Tcf for proved reserves, which the author corrected in an article published in the Feb. 4, 2008 edition of the Oil & Gas Journal.5
It is well known that unconventional natural gas has contributed a rapidly increasing share of U.S. natural gas production, but never before has this contribution been projected at such a high level—currently 50 percent of total dry gas production according to a recent article in the Oil & Gas Journal.6 This new assessment clearly changes the outlook for U.S. natural gas use in the U.S. energy system and appears to have already contributed to a sharp decrease in New York Mercantile Exchange (NYMEX) natural gas futures ranging from somewhat less than $8.00/million Btu to about $8.20/million Btu in the second half of August 2008. This decline is in spite of relatively low seasonal storage levels at that time. 7 More surprisingly, natural gas futures dropped to about $7.30/million Btu on Sept. 2, 2008, after assessments showed that Hurricane Gustav caused relatively minor damage to Gulf of Mexico oil and gas production platforms and coastal refineries, which are the major source of U.S. liquid fuels and natural gas supplies. This was accompanied by a drop in NYMEX crude oil futures to about $107/barrel for West Texas Intermediate and $106/barrel for North Sea Brent. By Sept. 9, 2008, NYMEX crude oil futures had decreased further to about $105/barrel and North Sea Brent futures to about $102/barrel, in spite of the projected pathway of Hurricane Ike into the Gulf of Mexico, and natural gas futures held at $7.30/million Btu. Since then, oil prices dropped to as low as $92/barrel even after the damage caused by Hurricane Ike to Gulf of Mexico production and refining facilities, and then rose again to above $100/barrel, but natural gas futures through early October 2008 remained below $7.50/million Btu. During the turbulent days for the U.S. and global equity markets from October 1 to October 9, oil prices dropped temporarily to below $90/barrel, while natural gas NYMEX futures fell to somewhat less than $7.00/million Btu. In fact, on the morning of Oct. 9, 2008, NYMEX West Texas intermediate futures dropped to about $89/barrel and North Sea Brent futures to $85/barrel, while natural gas futures declined to $6.85/million Btu. Then, following the meltdown of the Dow Jones Industrial Average by 733 points on Oct. 15, 2008, NYMEX West Texas intermediate futures dropped to $72/barrel and North Sea Brent futures to $69/barrel, while natural gas futures dropped to $6.50/million Btu. These oil-price fluctuations with minimal corresponding changes of natural gas prices in the $6.50-$7.00/million Btu range were likely to continue for the foreseeable future prior to the election of Illinois Senator Barack Obama to be the 44th President of the United States on Nov. 4, 2008. This earlier view was confirmed by the drop in the futures of the two benchmark crudes to $71/barrel and $69/barrel on Oct. 21, 2008, in the midst of continuing turmoil in the U.S. equity markets, while natural gas futures held at $6.75/million Btu. On Oct. 23, 2008, the two benchmark crudes futures dropped further to $68/barrel and $66/barrel, while natural gas futures dropped to $6.55/million Btu. Then on Oct. 28, 2008, the benchmark crudes dropped again to $65/barrel and $63/barrel and natural gas futures to their lowest level in recent years—approximately $6.20/million Btu. There was, however, a recovery in the benchmark crude oil futures to $68 and $65/barrel, respectively, on Oct. 30, 2008, but natural gas futures held at $6.90/million Btu. Since then, President-elect Barack Obama has outlined his plans for U.S. energy policy, which include a hold on new nuclear capacity until there is proof of the safety of nuclear waste disposal in the repository at Yucca Mountain in Nevada and, as a result, there is an increase in expected natural gas demand for combined-cycle plants. This was reflected in the futures market on Nov. 6, 2008. Although the two benchmark crudes dropped further to $64 and $61/barrel, natural gas futures rose to $7.29/million Btu. However, this trend reversed sharply in December 2008 and continued through the first half of January 2009 when natural gas futures dropped into the $5.00 to $6.00/million Btu range as the two benchmark crude prices dropped to their lowest levels in four years—about $37 to $46 a barrel. It is therefore reasonable to expect that even under the Obama regime, natural gas prices will remain in the $5.00 to $6.00/million Btu range, making natural gas a least-cost energy source for a variety of reasons.
It also should be noted that Natural Gas Week published a review of the American Clean Skies Foundation projection of 2,247 Tcf of natural gas reserves and potential resources in its Aug. 4, 2008 issue.7 This review noted that the contributions of shale gas had increased from less than 1 billion cu.ft./day in 1998 to about 5 billion cu.ft/ day today. U.S. natural gas production in 2007 was about 52.81 Bcf/day according to the above-noted Energy Information Administration (EIA) estimate of 19.278 Tcf/year dated June 30, 2008. EIA also reported that onshore shale gas production in the Lower 48 States increased by 9 percent between the first quarter of 2007 and the first quarter of 2008, and that one-half of this increase was attributed to the Burnett shale in Texas, thanks to advances in gas production technologies such as horizontal drilling. U.S. proved natural gas reserves also have increased annually since 1996 thanks to an increase in total discoveries in excess of production.
Natural Gas Vehicles
It is evident that this greatly improved U.S. natural gas supply outlook will have major impacts on the use of gas not only in stationary applications, but also as a low-emission transportation fuel in compressed natural gas vehicles (NGVs), which have been advocated for many years, especially for fleet use because of the relatively lower complexity of refueling systems. Unfortunately, only moderate commercialization for fleet use has resulted. Most recently, the legendary oil man T. Boone Pickens, the BP Capital founder, proposed in a television campaign that over the next 10 years, 38 percent of petroleum use in vehicles should be replaced by compressed natural gas stored on board in spite of the higher cost of natural gas vehicles and their dependence on expensive home or fleet refueling stations. But because of the uncertain outlook for petroleum supplies and prices, as well as the growing limitations on greenhouse gas emissions (primarily carbon dioxide), a revival of this initiative is likely.
NGVs are less efficient than vehicles powered with gasoline or diesel fuel, but still have substantially lower greenhouse gas emissions. NGVs also require parasitic energy use for compression of on-board storage tanks to 3,500 psig. However, progress is being made on improving NGV efficiency and possibly lowering compression levels.8 There also is increasing Congressional support for legislation promoting NGV use and mandating the availability of public refueling stations by Rep. Rahm Emanuel (D-Ill.), who was chairman of the House Democratic Caucus, and chosen for White House Chief of Staff, and Sen. James Inhofe (R-Okla.).9 This legislation would expand current tax credits for NGVs to both natural-gas-fueled vehicles and bi-fuel vehicles to ensure that by 2018, 10 percent of new vehicles would be NGVs. The latter requirement is the objective of the New Alternative Transportation to Give Americans Solutions Act, introduced by Rep. Rahm Emanuel and Rep. Dan Boren (D-Okla.).
The Emanuel Bill also would double the tax credit for installing home refueling stations from $1,000 to $2,000. Moreover, it would require that service stations owned by major oil companies must install natural gas fuel pumps by 2018 or face an annual fine of $100,000 per station. However, the Emanuel Bill includes an increase in the refueling property tax credit for the installation of natural gas fuel pumps and $2.6 billion of Energy Security Tax Credit Bonds to provide low or no-interest loans to service stations up to $200,000 per station.
In view of the growing constraints on CO2 emissions from power generation, it is vitally important that the least-cost solution be used, which is replacement of inefficient (30-32 percent) coal-fired steam-electric plants. These still supply more than one-half of U.S. power demand and emitted about one-third of U.S. carbon emissions in the form of CO2 of 1,607 million metric tons (mmt) in 2006.10 This least-cost solution is replacement of the existing 311 gigawatts of coal-fired steam-electric capacity with efficient natural-gas-fired combined-cycle plants that emit only one-third as much carbon in the form of CO2 at a heat rate of about 6,300 Btu/kWh, which is equivalent to a lower heating value efficiency of about 60 percent. According to a December 2000 interim report on a study sponsored by the U.S. Department of Energy and the Electric Power Research Institute, the investment cost of natural-gas-fired combined-cycle plants was only $496/kW11 and is undoubtedly somewhat higher by now, but still by far the least-cost source of low-emission power, especially at natural gas prices in the $5.00 to $6.00/million Btu range and $500/KW investment cost. This would make the busbar cost—at a 70 percent annual operating factor—about 4.9 to 5.5 cents/kW-hour. This is substantially less than the estimated busbar cost of new nuclear (but totally emission-free) capacity, or of the modified Integrated Coal Gasification Combined Cycle (IGCC) process in which an intermediate catalytic water gas shift step (CO+H2O -> CO2 + H2) converts the entire product of pressurized steam-oxygen coal gasification into essentially pure hydrogen after removal of the CO2 and its sequestration in suitable underground formations. The investment cost of modified IGCC, excluding the cost of CO2 sequestration, is now estimated to be well in excess of $2,000/kW. In an article by the author entitled “Coal No More: What If?”12 it is estimated that just the conversion of the existing 311 GW of coal-fired steam-electric capacity to natural-gas-fired combined-cycle capacity at a 70 percent annual operating factor would require 11.7 Tcf/year of natural gas. Adding the increase in gas requirements for the projected gas-fired combined-cycle power generation of 4.6 Tcf/year to the 11.7 Tcf/year for conversion of coal-fired steam-electric capacity, less the already projected increase in gas-fired power generation of 3.0 Tcf/year, would add 13.3 Tcf to 2025 projected gas requirements of 31.33 Tcf, or a total of 44.6 Tcf, an unrealizable level at the current outlook. This is based on the 2004 reference case of the Annual Energy Outlook. Using similar calculations for the 2005 and 2006 Annual Energy Outlook gives values of gas requirements of 41.8 Tcf in 2025 and 39.3 Tcf in 2030, respectively, again not realizable at current projections for gas supply. In these projections it is puzzling why the EIA in its 2004, 2005, 2006, 2007 and 2008 Annual Energy Outlooks projects no significant increases in dry natural gas production levels by 2025 (and 2030 for the 2007 and 2008 Outlooks) in spite of all recent evidence that unconventional natural gas supply prospects are likely to result in substantial increases. Thus, top priorities for U.S. energy policy should be to improve EIA’s forecasting techniques, to provide incentives for increasing domestic natural gas production to at least 25 Tcf/year by 2025-2030, to reduce the many barriers to increasing the importation of pipeline gas from Canada and Mexico and of LNG, and to accelerate the construction of the Alaska pipeline to the lower 48 States.
1. World Dry Natural Gas Production, Most Recent Annual Estimates, 1980-2007 (Trillion Cubic Feet), Energy Information Administration, June 30, 2008.
2. “Unconventional Natural Gas Resources Boost U.S. Reserves to 118 Years Worth at Current Levels,” American Clean Skies Foundation, conducted by Navigant Consulting, Inc., Free Republic, LLC, P.O. Box 9771, Fresno, CA 93794, Posted on Internet, Aug. 12, 2008.
3. Potential Supply of Natural Gas in the United States, Report of the Potential Gas Committee, Potential Gas Agency, Colorado School of Mines, Dec. 31, 2006, Table 2, page 6 and Table 5, page 8.
4. U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves, 2006 Annual Report, Advance Summary, Energy Information Administration, Office of Oil and Gas, U.S. Department of Energy.
5. Linden, Henry R., “Outlook for U.S. gas supply improves if production efforts are stepped up,” Oil & Gas Journal, Feb. 4, 2008, pp. 36-40.
6. “SPE: Industry cites unconventional resources potential,” Oil and Gas Journal, Oct. 6, 2008, pp. 34-35.
7. “Report claims U.S. NatGas Reserves Could Stretch into 22nd Century,” Natural Gas Week, Aug. 4, 2008, pp. 1, 18-19.
8. “Natural Gas Vehicles Gaining on Diesel in the Well-to Wheels Test,” Natural Gas Week, Aug. 11, 2008, pp. 1, 14-15.
9. “NGVs Pick Up Bi-Partisan Support in Congress; Bills Before Committee,” Natural Gas Week, Aug. 18, 2008, pp. 1,14-15.
10. Annual Energy Outlook 2008 With Projections to 2030, Energy Information Administration, Office of Integrated Analysis and Forecasting, U.S. Department of Energy, June 2008, Table A18, p. 145.
11. Evaluation of Innovative Fossil Fuel Power Plants with CO2 Removal, U.S. Department of Energy – Office of Fossil Energy and Electric Power Research Institute, Prepared by Parsons Energy & Chemical Inc., Table 1, p. VIII, Interim Report, December 2000.
12. Linden, Henry R., “Coal No More: What If?” Public Utilities Fortnightly, September 2006, pp. 62-66.