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U.S. natural gas in 2011 and beyond
Journal of Natural Gas Science and Engineering 8 (2012) 2e8
Contents lists available at SciVerse ScienceDirect
Journal of Natural Gas Science and Engineering journal homepage: www.elsevier.com/locate/jngse
U.S. natural gas in 2011 and beyond Michael J. Economides*, Ronald E. Oligney, Philip E. Lewis University of Houston, Dept. of Chemical and Biomolecular Eng., 4800 Calhoun Ave., Houston, TX 77204-4004, United States
a r t i c l e i n f o
a b s t r a c t
Article history: Received 29 July 2011 Accepted 6 October 2011 Available online 17 December 2011
In January 2011 the refrain was “$5 natural gas forever,” based on the U.S. Energy Information Administration’s (EIA) annual outlook, which argued that natural gas prices will remain below $5 per million Btu until 2022. The underlying rationale was growth in the “vast” U.S. shale gas resource base. Many bloggers, bankers and bureaucrats accepted the verdict. Not to be outdone, the Paris-based International Energy Agency (IEA) issued a press release on January 20th (2011) and in the press release they claimed that “booming” shale gas production in the United States would prompt a “global rush” to explore for the “new” resource against a backdrop of natural gas prices in Europe and Asia ranging from $8 to $11 per MMBtu (Fig. 1). Ó 2011 Published by Elsevier B.V.
Keyword: Natural gas
In January 2011 the refrain was “$5 natural gas forever,” based on the U.S. Energy Information Administration’s (EIA) annual outlook, which argued that natural gas prices will remain below $5 per million Btu until 2022.1 The underlying rationale was growth in the “vast” U.S. shale gas resource base. Many bloggers, bankers and bureaucrats accepted the verdict. Not to be outdone, the Parisbased International Energy Agency (IEA) issued a press release on January 20th (2011) and in the press release they claimed that “booming” shale gas production in the United States would prompt a “global rush” to explore for the “new” resource against a backdrop of natural gas prices in Europe and Asia ranging from $8 to $11 per MMBtu (Fig. 1). The extravagant claims of EIA and IEA attracted immediate rebuttal from some of the industry’s more reasoned voices. One salutary effect of extreme claims is the prompting of more balanced analyses, such as one we performed in March 2011 (Energy Tribune, March 2011). We do not question that shale gas is a very large and important new resource, but we have grave doubts that it can sustain such a low U.S. natural gas price in the face of new external challenges to shale gas production and burgeoning demand, both domestic and abroad. In early 2011, we characterized the debate as one between $5 and $8 MMBtu natural gas (in 2020, based on 2011 dollars). During early March through early May of 2011, natural gas prices produced a surprisingly strong upside reversal, rising about 20% even during the normal springtime lull in demand. However, we
* Corresponding author. E-mail address: [email protected] (M.J. Economides). 1875-5100/$ e see front matter Ó 2011 Published by Elsevier B.V. doi:10.1016/j.jngse.2011.10.007
believe that the gas market "got ahead of itself" in that the price rise was probably an anticipation of future demand increases brought on by current low prices. The lead time for new natural gas demand is on the order of years, and some time will have to pass before the new demand actually materializes. Prices have since fallen back, which we attribute to the (also surprising) sudden slowing in the U.S. and World economies caused by the "European Debt Crisis". We expect the trend of early 2011 to gradually reassert itself as the crisis ebbs, as crises inevitably do, and as new demand begins to materialize. Our prediction: look for $6.00 natural gas in the U.S. by 2013, and $8.00 natural gas by 2015. On the world stage, natural gas demand and continued price pressures between now and 2020 will present major socioeconomic and political trade-offs, from Japan and China, to Russia and Europe, to the Eastern Mediterranean, and, ultimately the United States. We begin with a survey of important global events that color the natural gas situation, and then return for a close look at the U.S. natural gas price environment. 1. Natural gas on the world stage 1.1. Japan and China The Japanese earthquake, tsunami and resulting nuclear accident at the Fukushima power plant spawned a disaster that will be hard to remedy or forget. As usual, the events have had a number of dimensions, mostly unfortunate for that country no matter how tolerant the population may have grown from past experiences in natural or even man-made calamities.
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Fig. 1. World LNG Landed Prices in March 2011 (www.ferc.gov/market-oversight/.../lng/2011/03-2011-othr-lng-archive.pdf).
Japan’s misery becomes the opportunity of the century for natural gas-producing countries, headed by Australia. Australian natural gas is the obvious energy source to be marshaled by Japan in both the immediate and the long-term future. The Japanese reactor meltdown brought about an even bigger meltdown in public perception of nuclear power, which was barely showing some signs of life after decades following the accidents at Three Mile Island and Chernobyl. There has not been a new nuclear power plant in the United States in 30 years. Germany and other European countries, gingerly planning new nuclear reactors until the Japanese accident, have either scrapped the plans or want more “study.” China and many other countries have announced their intentions to rethink nuclear power. For Japan the situation is even starker and it will create a new reality in the entire Australasian region, affecting natural gas trade and natural gas production. Of more than 1000 billion kWh of electricity generated in Japan per year, 27 percent comes from nuclear power plants, with a total of 51 GW of installed capacity. The Fukushima reactors with a total capacity of 4.4 GW have contributed about 2.2 percent of Japanese electric power production. Natural gas on the other hand also provides about 27 percent of Japanese electric power generation. Before the accident the Japanese, ever mindful of emissions, were talking about increasing nuclear’s contribution to 37 percent before the end of the decade. Without an increase, and considering the shortfall from the Fukushima plant, Japan will need low-emission natural gas to fill an estimated 12 percent of projected electricity needs. Predictions that up to 75 percent of Japanese nuclear reactors will be shut down in the summer of 2011 present an even more dire scenario.2 Assuming the replacement fuel is LNG (rather than coal, which is consistent with the Japanese desire to reduce emissions) and that that LNG is run through old steam boilers at a 10,500 Btu/ kW heat rate, then world LNG demand would go up by 3.3 Tcf per year, which is a very big number. Japan now uses about 3.5 Tcf of natural gas annually, of which 3.3 is imported in the form of LNG. The majority of natural gas usage is in power generation. Our current estimate is that the annual LNG imports must escalate to over 4.8 Tcf to meet the new
power market share from natural gas, which we expect to climb to 39 percent. The incremental 1.5 Tcf of gas translates to an increase in LNG imports of 27 additional million metric tons per annum (MTPA) of LNG trains. That is about 44 percent of current Qatar LNG capacity, 1.35 times the current Australian capacity of a little over 20 MTPA, with plans calling for increasing the capacity to 50 by 2017. However, the Japanese opportunity for Australian gas, born in the recent misfortune, pales next to Chinese prospects. The Chinese today use about 3.3 Tcf of natural gas, of which more than 95 percent is produced domestically. This amounts to less than 4 percent of total Chinese energy demand, with coal providing more than 70 percent. This kind of energy mix, with all the resulting horrible environmental impact, has not been seen in the developed world since the nineteenth century. The Chinese government has already decreed that by 2020 the natural gas share of their energy mix should climb to 10 percent. Depending on whose estimate of total Chinese energy demand by 2020 the new share would translate to between 10.6 Tcf and 12 Tcf of natural gas annually. Such an ambitious plan, while acknowledged by the Energy Information Administration in their July 2010 International Energy Outlook, is considered just that, an ambition. Their estimate of Chinese natural gas consumption by 2020 is a more modest 6.3 Tcf. Of course, no matter which of these estimates materializes, it will amount to a huge elevation in the demand from international supply, anywhere from 3 to 9 Tcf of incremental natural gas. Other than questionable shale gas, China does not come close to having sufficient domestic resources to increase supply by this amount. Chinese needs would dwarf any Japanese demand. For good measure, the larger figure is about eight times the current Australian LNG production, which is probably already spoken for by Japanese demand. How much of this can Australia actually deliver? Does the Australian government act as if it understands the magnitude of this challenge? These are clearly critical questions, unlike that of any other country, because there is no other nation that has enough resources to actually compete credibly in this massive venture and at the same time maintain its environmentalist and regulatory
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sensibilities. To find a compromise will be the defining Australian socioeconomic and political issue of the next several decades. 1.2. Changing the geopolitics of eastern Mediterranean and beyond Energy resources have always been at the center of the ArabIsraeli conflict, creating alliances and clearly influencing the policies of many nations toward the adversaries. Israel itself had a very complex relationship with its neighbors, mainly Egypt, a supplier of energy to Israel since the Camp David Accords in 1978. In the past few years and with a stunning new announcement of the major Leviathan natural gas discovery on December 30, 2010,3 Israel’s energy situation has changed dramatically. Israel is now squarely in the energy “big leagues”. The two Israeli discoveries are perhaps the largest gas discoveries in the world in each of the last two years and are likely to greatly enhance Israel’s regional and European geopolitical role. Coupled with the fact that Israel has also emerged as a global leader in many high-tech industries with a direct expansion of energy usage, the country may become a trendsetter in wide use of compressed natural gas (CNG)-directly-fired or electrical vehicles. Gas to liquids may not be far behind. Without question, the future of Israeli energy is tied to natural gas. Starting in 2004, Noble Energy, a relatively small but capable Houston-based independent, started producing natural gas from the Mari field. This was the beginning of Israel’s shift toward natural gas, moving away from coal and even further away from fuel oils. The Noble partnership consists of Noble Energy, Delek Drilling, Avner Oil Exploration and Delek Investments. Mari was discovered by the Noble partnership in 2000 in 796 ft of water and at 6830 ft total depth. The exploration well, Mari B 1, logged 550 ft of net thickness of gas in a sandstone zone. Noble has stated that the field can produce up to the facility capacity of 600 MMscf per day (Fig. 2).
Then in early 2009 Noble announced discovery of the 7 Tcf Tamar field, 90 km off of Israel’s northwestern coast. The estimated initial gas in place was raised from 5 Tcf to 8.4 Tcf on the drilling of an appraisal well that quickly followed the exploration well. Tamar is located at a total depth of 16,000 ft in 5500 ft of water. But the best was yet to come. At the close of 2010, Noble Energy and partners announced that the Leviathan field, off the north coast of Israel, contained at least 16 Tcf of recoverable gas, which would make the field one of the largest offshore natural gas fields ever. Such a giant discovery, which may be followed by other discoveries, would certainly make Israel a prime candidate natural gas exporter. The United States Geological Survey has estimated that the Eastern Mediterranean may hold 200 Tcf of ultimately recoverable natural gas. 1.3. Economic implications and geopolitics Israel has had a tumultuous history, and its energy demand has always been in the immediate background. Since the nation’s establishment in 1948, the country has fought six wars against its neighbors. With each war, and more recently, with each act of terrorism, one would expect Israel to descend into turmoil, becoming ever more difficult to transcend. Yet Israel has continued to expand its economy and make technological advancements that revolutionized high-tech industries, agricultural products, and the defense establishment. Through a lasting peace with Egypt (1979) and Jordan (1994), as well as a commitment to peace with the Palestinians, Israel has ushered in a prosperous future. Israel’s success in the energy arena is also a game-changer in geopolitics. First, the least worrisome eventuality would be a conflict with its northern neighbor, Lebanon, which is already claiming that the Leviathan prospect extends into its waters and is planning for an exploration program off its coast. Further west, Noble already holds the only lease in Cyprus waters, which could
Fig. 2. Natural Gas Discoveries in Israeli Waters.
M.J. Economides et al. / Journal of Natural Gas Science and Engineering 8 (2012) 2e8
prove successful in the outer reaches of the Levantine Basin. Israel and Cyprus are cooperating to define the borders of the continental shelf under the rules of the UN Convention on the Law of the Sea. Natural gas may bring Israel and Cyprus (and by extension Greece) into a natural alliance, and not merely for economic benefit. In a classic example of the “enemy of my enemy is my friend,” the recent breech between Israel and Turkey brings the Greeks closer to Israel. A natural gas pipeline from the Israeli finds to Cyprus would be an obvious gesture of the rapprochement. Such a pipeline can become the vehicle for LNG liquefaction and then exports of LNG to a natural gas starving Europe that is currently suffocated by Russian natural gas imports. An alternative substantial source of natural gas to Europe can provide what the ill-fated Nabucco pipeline is unlikely to ever deliver. Two LNG trains on Cyprus, each of 7 million metric tons of LNG, would amount to about 23 percent of Russian exports to Western Europe, which were 3.3 Tcf in 2009. Israeli natural gas, as almost everything else in that part of the world, has many more dimensions than the obvious. 2. World gas reserves and potential In spite of all current challenges to gas production, we must not fail to appreciate the enormous quantity of potential recoverable gas around the globe (Fig. 3). At some price, and likely a price well below the current price of oil on an energy content basis, there are tremendous quantities of gas to be unlocked. The inescapable conclusion is that gas will continue to expand its relative importance in world energy markets. That said, we do not believe this potential can be unlocked at current prices, and especially not at EIA’s extremely low long-term price forecast. Our reasoning with respect to U.S. gas prices will be explained in the following section. 3. A reasoned U.S. natural gas price outlook In the United States, rather than specific natural gas discoveries, the debate centers on the major new category of and rising tide of “shale gas.” An over-enthusiastic response by the U.S. government suggests that it believes (or at least wants to believe) this cheap and relatively environmentally benign fuel can be the magic wand for its often irreconcilable priorities: cheap energy for consumers; sustainable economic growth; energy independence and national security; and near-zero human or environmental risk. 3.1. $5 versus $8 natural gas The various public and private analyses of U.S. natural gas prices in 2011 can be characterized as two polar opposites: the $5 MMBtu
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Table 1 Gas Price Forecast Camps and Beliefs.
E&P Profitability Externality Costs Upside Demand Catalysts Shale Production 3X-plus by 2020
$5 MMBtu “And” Camp
$8 MMBtu “Or” Camp
No No No Yes
Yes Yes Yes No
“And” camp and the $8 MMBtu “Or” camp.4 Table 1 describes several factors that may affect U.S. natural gas prices in the near- to mid-term, and the impact of these factors on the emerging price environment. To be a member of the $5 MMBtu camp, one must hold that several assumptions are all true: (1) natural gas output can continue to grow in the face of dismal profitability in the shale gas E&P sector; and (2) externality costs such as new taxes or compliance costs or curtailments related to water and air pollution will not put a negative crimp on E&P activities or natural gas profits; and (3) various identifiable “catalysts” for new U.S. natural gas demand will not materialize; and (4) U.S. shale gas production can increase 3-fold by 2020. We contend the $5 MMBtu scenario requires that all four of these assumptions be true, so we refer to this as the “And” scenario. The “And” scenario is somewhat equivalent to gas consumers correctly calling a coin flip four times in a row. Las Vegas offers much better odds. To be a member of the $8 MMBtu camp, one need only hold that either: (1) continued growth in natural gas output requires a return to at least normal profitability in the shale gas E&P sector; or (2) externality costs will negatively impact the natural gas sector; or (3) demand catalysts will lead to increased U.S. natural gas consumption; or (4) U.S. shale gas production will not be able to achieve a 3-fold increase between 2011 and 2020. A detailed examination of each condition follows. 3.2. E&P profitability To address the unsatisfactory state of profits in the shale gas sector, we compared the return on equity for companies focused on shale gas production to other otherwise comparable oil and gas companies. Fig. 4 shows the Return on Equity for selected oil and gas companies. Those companies with the greatest exposure to shale gas are producing substandard or negative returns for their stockholders. In fact, companies which are dominated by shale gas activity have returns that are likely below debt cost of capital. These companies will be very challenged to raise either debt or equity capital in their current configuration. This will necessarily restrict their growth, as well as impede the entrance of new players into the shale gas arena. 4. Externality costs
Fig. 3. World Gas Reserves and Potential.
Issues and forces that may produce costs and curtailments that negatively impact U.S. natural gas output and pricing have been gathering momentum in recent months. The term “external” connotes issues that are driven from outside the industry and therefore represent costs not currently borne by the industry. We can be agnostic toward the issues themselves, a bit like global warming, because we do not have the data needed for a quantitative analysis. At the same time, we recognize that once an issue reaches repeated newspaper-level publicitydas all of these havedthe outcome is hard to predict and can have a real business impact regardless of whether the issue is legitimate.
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Fig. 4. Return on Equity for Selected Companies.
4.1. Taxes Following the late-2000s financial crisis, the federal and state governments are in desperate search of new sources of revenue and exploration and production companies, regardless of actual profitability, present an obvious target. The IRS depletion allowance (which provides a deduction in computing federal taxable income in the case of mines, oil and gas wells, other natural deposits and timber, related to depletion) is under close scrutiny in Washington DC. Gas-producing states are considering either raising taxes on gas production, and in at least one case, creating entirely new tax regimes.5 In Texas, for example, the baseline severance tax on natural gas is 7.5 percent. In 1989, Texas created the High Cost Gas Incentive, which works as an investment tax credit to encourage producers to make large investments necessary to bring valuable new natural gas resources into production. Eliminating this incentive would increase costs about $1.233 billion per year, raising unconventional natural gas costs by $0.41 per Mcf. 4.2. Water pollution Natural gas production is exempt from the Clean Water Act under the Energy Policy Act of 2005, which has become a point of public awareness along with the expansion of drilling and “fracking” activities related to development of the domestic shale gas industry. A recent peer-reviewed paper published in the Proceedings of the National Academy of Sciences has found “systematic evidence for methane contamination of drinking water associated with shale gas extraction.”6 Newspaper reports have begun to focus on the “millions of gallons” of fluid used per frac; the volumes of fluid not recovered and remaining underground, recovered and disposed of, and the hundreds of proprietary chemicals in frac fluids, some of which may be carcinogenic. A headline in the April 18, 2011 Wall Street Journal read, “Toxins Found In Gas Drilling Fluids.” The Fracturing Responsibility and Awareness of Chemicals Act of 2009 would have required proprietary components of frac fluids be disclosed and that fracking be regulated under Clean Water Act, but this bill was effectively stalled in the House Energy and Commerce Committee. 4.3. Air pollution The 493,000 natural gas wells in the United States are also exempt from Clean Air legislation. Again, this has become a point of public scrutiny. An SMU professor (Armendariz) has recently
claimed that volatile organic compounds (VOC) emissions from Barnett shale natural gas production in the Dallas Fort Worth metroplex are greater than total emissions from the DFW transportation sector7 The Associated Press has reported that ozone levels in Wyoming reached 124 parts per million in March; that’s two-thirds higher than the EPA’s maximum healthy limit of 75 parts per billion and above the worst day in Los Angeles all last year.8 4.4. Externality results Today, once an issue makes the newspaperdnever mind the science or relative magnitudedthe move can quickly go from an unquantifiable abstraction to a concrete and possibly costly result. Consider the following headlines. “‘Fracking’ Disposal Sites Suspended, Likely Linked To Arkansas Earthquakes” e By Sarah Eddington e 03/4/11 e “Two natural gas companies agreed to suspend use of injection wells in central Arkansas where a series of hundreds of earthquakes with magnitudes as high as 4.7 have occurred over the past six months.” “Quebec Halts Shale Gas Exploration” e From Globe and Mail e 03/8/11 e “Shale gas exploration was put on hold pending a full environmental study of the “fracking” technique being used in a tail of the Marcellus shale resource that extends near populated areas along the Saint-Lawrence River.” 5. Upside demand catalysts There are several areas in which strong U.S. natural gas demand can be anticipated as consumers and regulators re-orient to take advantage of this environmentally premium fuel and the perceived long term-bargain shale gas pricing and availability: electric power, industrial/chemical, transportation and LNG export. We estimate that together, these upside demands (which are mostly excluded from current EIA natural gas forecasts) total an enormous 31.4 Bcf per day, almost half of U.S. current daily production. 5.1. Power demand We anticipate that natural gas demand related to the U.S. power sector will grow by 12.8 Bcf per day between 2011 and 2020 as U.S. power generation grows from 11.4 tWh to 13.2 tWh per day. This assumes that 100 percent of new U.S. power demand is met by natural gas. There are currently four coal-fired plants under construction, but we anticipate that new coal generation will only
M.J. Economides et al. / Journal of Natural Gas Science and Engineering 8 (2012) 2e8 Table 2 Total Upside Demand Catalysts.
2011 2013 2015 2020
Power (Bcfd)
Industrial (Bcfd)
Transport (Bcfd)
LNG (Bcfd)
Total (Bcfd)
1.2 3.6 6.2 12.8
e 0.7 2.0 5.2
e 1.6 3.5 9.1
0.1 0.4 3.7 4.3
1.3 6.3 15.4 31.4
7
delivered retail prices, diesel fuel is 4e5 times more expensive than natural gas on an energy content basis, so there is ample incentive for natural gas to invade this market. Whether or not natural gas replaces diesel demand, it is clear that natural gas will play a large role in the transportation sector, either as an alcohol feedstock or source of power generation for electric vehicles. 5.4. LNG exports
offset coal plant retirements. Renewables and nuclear energy can make only marginal contributions to power generation from 2011 to 2020. The underlying growth in U.S. power demand assumes the North American Electric Reliability Corporation (NERC) growth projection of 1.57% per year from 2011 to 2020. 5.2. Industrial natural gas demand U.S. industrial natural gas demand fell 22 percent between 1997 and 2010, from 23.3 Bcf per day to 18.1 Bcf per day as industrial gas consumers moved offshore to source cheaper stranded natural gas. However, major recent announcements by the U.S. chemical sector, which represents the largest industrial demand (35 percent), indicate a major rebound and reversal of trend. We anticipate that industrial demand will regain the lost 5.2 Bcf per day of natural gas demand from 2013 through 2020. Dow Chemical, for example, has announced plans to increase ethylene and propylene production in the United States based on ready supplies of shale gas, with the restart or startup of new U.S. facilities in 2012, 2014, 2015, 2017 and 2018. 5.3. Transportation fuel Natural gas demand in transportation has so far been fueled by on-road diesel conversions, mostly in local bus fleets and limited long-haul trucking operations. For the sake of estimating, we assume this trend continues and that 50 percent of diesel demand is ultimately met by natural gas in 2020. We assume that diesel demand grows 3% annually (the 20-yr trend is 3.7%/yr). At current
Major U.S. and Canadian LNG export projects have been announced over the last year, representing some 12.6 Bcf per day of new export capacity by 2015. Notably, Cheniere Energy received a formal okay from the U.S. Department of Energy on May 20, 2011 to export 2.2 Bcf per day of natural gas from its Gulf Coast LNG terminal.9 Assuming that current LNG imports (1.2 Bcf per day in 2010) ramp down to zero by 2020, and exports from the United States and Canada reach 50 percent of the announced capacity, also by 2020, then net LNG exports (effectively new U.S. natural gas demand) will reach 4.3 Bcf per day. The combined impact of these upside demand catalystsdpower demand, industrial natural gas demand, transportation fuel and LNG exportsdis summarized in Table 2. 6. Shale production 3X-plus by 2020 Fig. 5 provides a natural gas supply stack arranged from lowest to highest cost natural gas sources, in 2011 and 2020. The lowest cost natural gas production is “Associated-Dissolved,” which is a byproduct of oil production; next is “Conventional” gas production from high porosity and permeability reservoirs; then “Shale” gas, which is essentially production from a very low permeability and porosity mudstone; then “Coalbed Methane,” or coal seam gas, which is expensive due to water disposal requirements; then “Tight Sands” with its attendant higher development costs; and finally “LNG,” liquefied natural gas, which competes on the world market (see Fig. 1). Fig. 5 is complicated somewhat by the presence of Canadian equivalents for each category, but we agree with EIA that Canadian
80 70 60 LNG U.S.
Tight Sands Import Canada
BCF/ Day
50
Tight Sands U.S. Coalbed Methane Import Canada
Coalbed Methane U.S.
40
Shale Import Canada
Shale U.S.
30
Conventional Import Canada
Conventional U.S. Associated-Dissolved Import Canada
20
Associated-Dissolved U.S.
10 0 2011
2020 Fig. 5. U.S. Natural Gas Supply Stack.
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gas will have a dwindling influence on U.S. markets. Canadian natural gas has much higher value as an enabler of Canadian oilsands production than as an export product. Further, Canadian export gas has become less competitive since it must bear not only high transportation costs, but also a recently weakened U.S. Dollar relative to the Canadian Dollar. A market that requires new supply (either through new demand, or retirement of old supply) must do so at the marginal cost of adding production. We believe that it is clear that the U.S. must add substantially to its supply between now and 2020. This would be required simply to replace natural decline, which is in addition to the heavy demand requirements explained above. This means that cost of Tight gas will become the dominant price-setter in the marketplace. Tight gas capital and operating costs are estimated to be currently $8 per MMBtu. Domestic shale gas production is currently 14 Bcf per day, representing 22 percent of total U.S. demand. In order for relatively inexpensive shale gas to become the dominant price-setter, it must push all more expensive gas sources (Coalbed Methane þ Tight þ Tight Canada þ LNG) off the margin (i.e., displace them). This requires that shale gas production must rise to 45.4 BCF per day by 2020, more than triple current production. And this is based on EIA’s forecast of total gas demand growth of only 4 Bcf per day by 2020, compared to our estimate of potential demand growth of up to 31.4 Bcf per day. We judge the probability of shale gas tripling production by 2020 at anywhere near current prices as negligible. 7. Conclusion From the analysis provided above, we conclude simply that U.S. natural prices will rise quickly to $8 per MMBtu and that world
prices, on the back of major new resources that we have identified, will coalesce around a modest premium to the U.S. price. Natural gas conversion and transport technologies will ensure the convergence. Under this price environment, natural gas will resume its contemporary role as a premium world fuel based on environmental benefits and a long-term price advantage over oil based on energy content. Acknowledgment Portions of the analysis in this paper were performed by Papalote Ventures, LLC under contract to Zero Emission Energy Plants Ltd. Endnotes 1
EIA Annual Energy Outlook 2011: Don’t Worry, Be Happy. Petroleum Truth Report, Jan. 1, 2011. 2 35 Japanese Reactors Are Soon to be Out Of Line, NHK (Japan Broadcasting Corporation). nhk.or.jp/daily, May 13, 2011. 3 Noble Energy Announces Significant Discovery at Leviathan Offshore Israel. Offshore Energy Today, Dec. 30, 2010. 4 The authors are not authorized to provide specific proprietary price forecasts. 5 Pennsylvania Weighs Levy on Natural Gas Wells. Wall Street Journal, p. A5, May 14, 2011. 6 Osborn, Stephen, G., Methane contamination of drinking water accompanying gaswell drilling and hydraulic fracturing. Proceedings of the National Academy of Sciences, 2011 108, 8172e8176. 7 Armendariz, Al, Emissions from Natural Gas Production in the Barnett Shale Area and Opportunities for Cost-Effective Improvements. Environmental Defense Fund, Jan. 26, 2009, p. 1. 8 Gruver, Mead (AP): Gas drilling blamed for soaring ozone in Wyoming. CitizensVoice.com, March 9, 2011. 9 U.S. Approves First Natural Gas Exports. Financial Times, FT.com, May 20, 2011. 10.
Contents lists available at SciVerse ScienceDirect
Journal of Natural Gas Science and Engineering journal homepage: www.elsevier.com/locate/jngse
U.S. natural gas in 2011 and beyond Michael J. Economides*, Ronald E. Oligney, Philip E. Lewis University of Houston, Dept. of Chemical and Biomolecular Eng., 4800 Calhoun Ave., Houston, TX 77204-4004, United States
a r t i c l e i n f o
a b s t r a c t
Article history: Received 29 July 2011 Accepted 6 October 2011 Available online 17 December 2011
In January 2011 the refrain was “$5 natural gas forever,” based on the U.S. Energy Information Administration’s (EIA) annual outlook, which argued that natural gas prices will remain below $5 per million Btu until 2022. The underlying rationale was growth in the “vast” U.S. shale gas resource base. Many bloggers, bankers and bureaucrats accepted the verdict. Not to be outdone, the Paris-based International Energy Agency (IEA) issued a press release on January 20th (2011) and in the press release they claimed that “booming” shale gas production in the United States would prompt a “global rush” to explore for the “new” resource against a backdrop of natural gas prices in Europe and Asia ranging from $8 to $11 per MMBtu (Fig. 1). Ó 2011 Published by Elsevier B.V.
Keyword: Natural gas
In January 2011 the refrain was “$5 natural gas forever,” based on the U.S. Energy Information Administration’s (EIA) annual outlook, which argued that natural gas prices will remain below $5 per million Btu until 2022.1 The underlying rationale was growth in the “vast” U.S. shale gas resource base. Many bloggers, bankers and bureaucrats accepted the verdict. Not to be outdone, the Parisbased International Energy Agency (IEA) issued a press release on January 20th (2011) and in the press release they claimed that “booming” shale gas production in the United States would prompt a “global rush” to explore for the “new” resource against a backdrop of natural gas prices in Europe and Asia ranging from $8 to $11 per MMBtu (Fig. 1). The extravagant claims of EIA and IEA attracted immediate rebuttal from some of the industry’s more reasoned voices. One salutary effect of extreme claims is the prompting of more balanced analyses, such as one we performed in March 2011 (Energy Tribune, March 2011). We do not question that shale gas is a very large and important new resource, but we have grave doubts that it can sustain such a low U.S. natural gas price in the face of new external challenges to shale gas production and burgeoning demand, both domestic and abroad. In early 2011, we characterized the debate as one between $5 and $8 MMBtu natural gas (in 2020, based on 2011 dollars). During early March through early May of 2011, natural gas prices produced a surprisingly strong upside reversal, rising about 20% even during the normal springtime lull in demand. However, we
* Corresponding author. E-mail address: [email protected] (M.J. Economides). 1875-5100/$ e see front matter Ó 2011 Published by Elsevier B.V. doi:10.1016/j.jngse.2011.10.007
believe that the gas market "got ahead of itself" in that the price rise was probably an anticipation of future demand increases brought on by current low prices. The lead time for new natural gas demand is on the order of years, and some time will have to pass before the new demand actually materializes. Prices have since fallen back, which we attribute to the (also surprising) sudden slowing in the U.S. and World economies caused by the "European Debt Crisis". We expect the trend of early 2011 to gradually reassert itself as the crisis ebbs, as crises inevitably do, and as new demand begins to materialize. Our prediction: look for $6.00 natural gas in the U.S. by 2013, and $8.00 natural gas by 2015. On the world stage, natural gas demand and continued price pressures between now and 2020 will present major socioeconomic and political trade-offs, from Japan and China, to Russia and Europe, to the Eastern Mediterranean, and, ultimately the United States. We begin with a survey of important global events that color the natural gas situation, and then return for a close look at the U.S. natural gas price environment. 1. Natural gas on the world stage 1.1. Japan and China The Japanese earthquake, tsunami and resulting nuclear accident at the Fukushima power plant spawned a disaster that will be hard to remedy or forget. As usual, the events have had a number of dimensions, mostly unfortunate for that country no matter how tolerant the population may have grown from past experiences in natural or even man-made calamities.
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Fig. 1. World LNG Landed Prices in March 2011 (www.ferc.gov/market-oversight/.../lng/2011/03-2011-othr-lng-archive.pdf).
Japan’s misery becomes the opportunity of the century for natural gas-producing countries, headed by Australia. Australian natural gas is the obvious energy source to be marshaled by Japan in both the immediate and the long-term future. The Japanese reactor meltdown brought about an even bigger meltdown in public perception of nuclear power, which was barely showing some signs of life after decades following the accidents at Three Mile Island and Chernobyl. There has not been a new nuclear power plant in the United States in 30 years. Germany and other European countries, gingerly planning new nuclear reactors until the Japanese accident, have either scrapped the plans or want more “study.” China and many other countries have announced their intentions to rethink nuclear power. For Japan the situation is even starker and it will create a new reality in the entire Australasian region, affecting natural gas trade and natural gas production. Of more than 1000 billion kWh of electricity generated in Japan per year, 27 percent comes from nuclear power plants, with a total of 51 GW of installed capacity. The Fukushima reactors with a total capacity of 4.4 GW have contributed about 2.2 percent of Japanese electric power production. Natural gas on the other hand also provides about 27 percent of Japanese electric power generation. Before the accident the Japanese, ever mindful of emissions, were talking about increasing nuclear’s contribution to 37 percent before the end of the decade. Without an increase, and considering the shortfall from the Fukushima plant, Japan will need low-emission natural gas to fill an estimated 12 percent of projected electricity needs. Predictions that up to 75 percent of Japanese nuclear reactors will be shut down in the summer of 2011 present an even more dire scenario.2 Assuming the replacement fuel is LNG (rather than coal, which is consistent with the Japanese desire to reduce emissions) and that that LNG is run through old steam boilers at a 10,500 Btu/ kW heat rate, then world LNG demand would go up by 3.3 Tcf per year, which is a very big number. Japan now uses about 3.5 Tcf of natural gas annually, of which 3.3 is imported in the form of LNG. The majority of natural gas usage is in power generation. Our current estimate is that the annual LNG imports must escalate to over 4.8 Tcf to meet the new
power market share from natural gas, which we expect to climb to 39 percent. The incremental 1.5 Tcf of gas translates to an increase in LNG imports of 27 additional million metric tons per annum (MTPA) of LNG trains. That is about 44 percent of current Qatar LNG capacity, 1.35 times the current Australian capacity of a little over 20 MTPA, with plans calling for increasing the capacity to 50 by 2017. However, the Japanese opportunity for Australian gas, born in the recent misfortune, pales next to Chinese prospects. The Chinese today use about 3.3 Tcf of natural gas, of which more than 95 percent is produced domestically. This amounts to less than 4 percent of total Chinese energy demand, with coal providing more than 70 percent. This kind of energy mix, with all the resulting horrible environmental impact, has not been seen in the developed world since the nineteenth century. The Chinese government has already decreed that by 2020 the natural gas share of their energy mix should climb to 10 percent. Depending on whose estimate of total Chinese energy demand by 2020 the new share would translate to between 10.6 Tcf and 12 Tcf of natural gas annually. Such an ambitious plan, while acknowledged by the Energy Information Administration in their July 2010 International Energy Outlook, is considered just that, an ambition. Their estimate of Chinese natural gas consumption by 2020 is a more modest 6.3 Tcf. Of course, no matter which of these estimates materializes, it will amount to a huge elevation in the demand from international supply, anywhere from 3 to 9 Tcf of incremental natural gas. Other than questionable shale gas, China does not come close to having sufficient domestic resources to increase supply by this amount. Chinese needs would dwarf any Japanese demand. For good measure, the larger figure is about eight times the current Australian LNG production, which is probably already spoken for by Japanese demand. How much of this can Australia actually deliver? Does the Australian government act as if it understands the magnitude of this challenge? These are clearly critical questions, unlike that of any other country, because there is no other nation that has enough resources to actually compete credibly in this massive venture and at the same time maintain its environmentalist and regulatory
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sensibilities. To find a compromise will be the defining Australian socioeconomic and political issue of the next several decades. 1.2. Changing the geopolitics of eastern Mediterranean and beyond Energy resources have always been at the center of the ArabIsraeli conflict, creating alliances and clearly influencing the policies of many nations toward the adversaries. Israel itself had a very complex relationship with its neighbors, mainly Egypt, a supplier of energy to Israel since the Camp David Accords in 1978. In the past few years and with a stunning new announcement of the major Leviathan natural gas discovery on December 30, 2010,3 Israel’s energy situation has changed dramatically. Israel is now squarely in the energy “big leagues”. The two Israeli discoveries are perhaps the largest gas discoveries in the world in each of the last two years and are likely to greatly enhance Israel’s regional and European geopolitical role. Coupled with the fact that Israel has also emerged as a global leader in many high-tech industries with a direct expansion of energy usage, the country may become a trendsetter in wide use of compressed natural gas (CNG)-directly-fired or electrical vehicles. Gas to liquids may not be far behind. Without question, the future of Israeli energy is tied to natural gas. Starting in 2004, Noble Energy, a relatively small but capable Houston-based independent, started producing natural gas from the Mari field. This was the beginning of Israel’s shift toward natural gas, moving away from coal and even further away from fuel oils. The Noble partnership consists of Noble Energy, Delek Drilling, Avner Oil Exploration and Delek Investments. Mari was discovered by the Noble partnership in 2000 in 796 ft of water and at 6830 ft total depth. The exploration well, Mari B 1, logged 550 ft of net thickness of gas in a sandstone zone. Noble has stated that the field can produce up to the facility capacity of 600 MMscf per day (Fig. 2).
Then in early 2009 Noble announced discovery of the 7 Tcf Tamar field, 90 km off of Israel’s northwestern coast. The estimated initial gas in place was raised from 5 Tcf to 8.4 Tcf on the drilling of an appraisal well that quickly followed the exploration well. Tamar is located at a total depth of 16,000 ft in 5500 ft of water. But the best was yet to come. At the close of 2010, Noble Energy and partners announced that the Leviathan field, off the north coast of Israel, contained at least 16 Tcf of recoverable gas, which would make the field one of the largest offshore natural gas fields ever. Such a giant discovery, which may be followed by other discoveries, would certainly make Israel a prime candidate natural gas exporter. The United States Geological Survey has estimated that the Eastern Mediterranean may hold 200 Tcf of ultimately recoverable natural gas. 1.3. Economic implications and geopolitics Israel has had a tumultuous history, and its energy demand has always been in the immediate background. Since the nation’s establishment in 1948, the country has fought six wars against its neighbors. With each war, and more recently, with each act of terrorism, one would expect Israel to descend into turmoil, becoming ever more difficult to transcend. Yet Israel has continued to expand its economy and make technological advancements that revolutionized high-tech industries, agricultural products, and the defense establishment. Through a lasting peace with Egypt (1979) and Jordan (1994), as well as a commitment to peace with the Palestinians, Israel has ushered in a prosperous future. Israel’s success in the energy arena is also a game-changer in geopolitics. First, the least worrisome eventuality would be a conflict with its northern neighbor, Lebanon, which is already claiming that the Leviathan prospect extends into its waters and is planning for an exploration program off its coast. Further west, Noble already holds the only lease in Cyprus waters, which could
Fig. 2. Natural Gas Discoveries in Israeli Waters.
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prove successful in the outer reaches of the Levantine Basin. Israel and Cyprus are cooperating to define the borders of the continental shelf under the rules of the UN Convention on the Law of the Sea. Natural gas may bring Israel and Cyprus (and by extension Greece) into a natural alliance, and not merely for economic benefit. In a classic example of the “enemy of my enemy is my friend,” the recent breech between Israel and Turkey brings the Greeks closer to Israel. A natural gas pipeline from the Israeli finds to Cyprus would be an obvious gesture of the rapprochement. Such a pipeline can become the vehicle for LNG liquefaction and then exports of LNG to a natural gas starving Europe that is currently suffocated by Russian natural gas imports. An alternative substantial source of natural gas to Europe can provide what the ill-fated Nabucco pipeline is unlikely to ever deliver. Two LNG trains on Cyprus, each of 7 million metric tons of LNG, would amount to about 23 percent of Russian exports to Western Europe, which were 3.3 Tcf in 2009. Israeli natural gas, as almost everything else in that part of the world, has many more dimensions than the obvious. 2. World gas reserves and potential In spite of all current challenges to gas production, we must not fail to appreciate the enormous quantity of potential recoverable gas around the globe (Fig. 3). At some price, and likely a price well below the current price of oil on an energy content basis, there are tremendous quantities of gas to be unlocked. The inescapable conclusion is that gas will continue to expand its relative importance in world energy markets. That said, we do not believe this potential can be unlocked at current prices, and especially not at EIA’s extremely low long-term price forecast. Our reasoning with respect to U.S. gas prices will be explained in the following section. 3. A reasoned U.S. natural gas price outlook In the United States, rather than specific natural gas discoveries, the debate centers on the major new category of and rising tide of “shale gas.” An over-enthusiastic response by the U.S. government suggests that it believes (or at least wants to believe) this cheap and relatively environmentally benign fuel can be the magic wand for its often irreconcilable priorities: cheap energy for consumers; sustainable economic growth; energy independence and national security; and near-zero human or environmental risk. 3.1. $5 versus $8 natural gas The various public and private analyses of U.S. natural gas prices in 2011 can be characterized as two polar opposites: the $5 MMBtu
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Table 1 Gas Price Forecast Camps and Beliefs.
E&P Profitability Externality Costs Upside Demand Catalysts Shale Production 3X-plus by 2020
$5 MMBtu “And” Camp
$8 MMBtu “Or” Camp
No No No Yes
Yes Yes Yes No
“And” camp and the $8 MMBtu “Or” camp.4 Table 1 describes several factors that may affect U.S. natural gas prices in the near- to mid-term, and the impact of these factors on the emerging price environment. To be a member of the $5 MMBtu camp, one must hold that several assumptions are all true: (1) natural gas output can continue to grow in the face of dismal profitability in the shale gas E&P sector; and (2) externality costs such as new taxes or compliance costs or curtailments related to water and air pollution will not put a negative crimp on E&P activities or natural gas profits; and (3) various identifiable “catalysts” for new U.S. natural gas demand will not materialize; and (4) U.S. shale gas production can increase 3-fold by 2020. We contend the $5 MMBtu scenario requires that all four of these assumptions be true, so we refer to this as the “And” scenario. The “And” scenario is somewhat equivalent to gas consumers correctly calling a coin flip four times in a row. Las Vegas offers much better odds. To be a member of the $8 MMBtu camp, one need only hold that either: (1) continued growth in natural gas output requires a return to at least normal profitability in the shale gas E&P sector; or (2) externality costs will negatively impact the natural gas sector; or (3) demand catalysts will lead to increased U.S. natural gas consumption; or (4) U.S. shale gas production will not be able to achieve a 3-fold increase between 2011 and 2020. A detailed examination of each condition follows. 3.2. E&P profitability To address the unsatisfactory state of profits in the shale gas sector, we compared the return on equity for companies focused on shale gas production to other otherwise comparable oil and gas companies. Fig. 4 shows the Return on Equity for selected oil and gas companies. Those companies with the greatest exposure to shale gas are producing substandard or negative returns for their stockholders. In fact, companies which are dominated by shale gas activity have returns that are likely below debt cost of capital. These companies will be very challenged to raise either debt or equity capital in their current configuration. This will necessarily restrict their growth, as well as impede the entrance of new players into the shale gas arena. 4. Externality costs
Fig. 3. World Gas Reserves and Potential.
Issues and forces that may produce costs and curtailments that negatively impact U.S. natural gas output and pricing have been gathering momentum in recent months. The term “external” connotes issues that are driven from outside the industry and therefore represent costs not currently borne by the industry. We can be agnostic toward the issues themselves, a bit like global warming, because we do not have the data needed for a quantitative analysis. At the same time, we recognize that once an issue reaches repeated newspaper-level publicitydas all of these havedthe outcome is hard to predict and can have a real business impact regardless of whether the issue is legitimate.
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Fig. 4. Return on Equity for Selected Companies.
4.1. Taxes Following the late-2000s financial crisis, the federal and state governments are in desperate search of new sources of revenue and exploration and production companies, regardless of actual profitability, present an obvious target. The IRS depletion allowance (which provides a deduction in computing federal taxable income in the case of mines, oil and gas wells, other natural deposits and timber, related to depletion) is under close scrutiny in Washington DC. Gas-producing states are considering either raising taxes on gas production, and in at least one case, creating entirely new tax regimes.5 In Texas, for example, the baseline severance tax on natural gas is 7.5 percent. In 1989, Texas created the High Cost Gas Incentive, which works as an investment tax credit to encourage producers to make large investments necessary to bring valuable new natural gas resources into production. Eliminating this incentive would increase costs about $1.233 billion per year, raising unconventional natural gas costs by $0.41 per Mcf. 4.2. Water pollution Natural gas production is exempt from the Clean Water Act under the Energy Policy Act of 2005, which has become a point of public awareness along with the expansion of drilling and “fracking” activities related to development of the domestic shale gas industry. A recent peer-reviewed paper published in the Proceedings of the National Academy of Sciences has found “systematic evidence for methane contamination of drinking water associated with shale gas extraction.”6 Newspaper reports have begun to focus on the “millions of gallons” of fluid used per frac; the volumes of fluid not recovered and remaining underground, recovered and disposed of, and the hundreds of proprietary chemicals in frac fluids, some of which may be carcinogenic. A headline in the April 18, 2011 Wall Street Journal read, “Toxins Found In Gas Drilling Fluids.” The Fracturing Responsibility and Awareness of Chemicals Act of 2009 would have required proprietary components of frac fluids be disclosed and that fracking be regulated under Clean Water Act, but this bill was effectively stalled in the House Energy and Commerce Committee. 4.3. Air pollution The 493,000 natural gas wells in the United States are also exempt from Clean Air legislation. Again, this has become a point of public scrutiny. An SMU professor (Armendariz) has recently
claimed that volatile organic compounds (VOC) emissions from Barnett shale natural gas production in the Dallas Fort Worth metroplex are greater than total emissions from the DFW transportation sector7 The Associated Press has reported that ozone levels in Wyoming reached 124 parts per million in March; that’s two-thirds higher than the EPA’s maximum healthy limit of 75 parts per billion and above the worst day in Los Angeles all last year.8 4.4. Externality results Today, once an issue makes the newspaperdnever mind the science or relative magnitudedthe move can quickly go from an unquantifiable abstraction to a concrete and possibly costly result. Consider the following headlines. “‘Fracking’ Disposal Sites Suspended, Likely Linked To Arkansas Earthquakes” e By Sarah Eddington e 03/4/11 e “Two natural gas companies agreed to suspend use of injection wells in central Arkansas where a series of hundreds of earthquakes with magnitudes as high as 4.7 have occurred over the past six months.” “Quebec Halts Shale Gas Exploration” e From Globe and Mail e 03/8/11 e “Shale gas exploration was put on hold pending a full environmental study of the “fracking” technique being used in a tail of the Marcellus shale resource that extends near populated areas along the Saint-Lawrence River.” 5. Upside demand catalysts There are several areas in which strong U.S. natural gas demand can be anticipated as consumers and regulators re-orient to take advantage of this environmentally premium fuel and the perceived long term-bargain shale gas pricing and availability: electric power, industrial/chemical, transportation and LNG export. We estimate that together, these upside demands (which are mostly excluded from current EIA natural gas forecasts) total an enormous 31.4 Bcf per day, almost half of U.S. current daily production. 5.1. Power demand We anticipate that natural gas demand related to the U.S. power sector will grow by 12.8 Bcf per day between 2011 and 2020 as U.S. power generation grows from 11.4 tWh to 13.2 tWh per day. This assumes that 100 percent of new U.S. power demand is met by natural gas. There are currently four coal-fired plants under construction, but we anticipate that new coal generation will only
M.J. Economides et al. / Journal of Natural Gas Science and Engineering 8 (2012) 2e8 Table 2 Total Upside Demand Catalysts.
2011 2013 2015 2020
Power (Bcfd)
Industrial (Bcfd)
Transport (Bcfd)
LNG (Bcfd)
Total (Bcfd)
1.2 3.6 6.2 12.8
e 0.7 2.0 5.2
e 1.6 3.5 9.1
0.1 0.4 3.7 4.3
1.3 6.3 15.4 31.4
7
delivered retail prices, diesel fuel is 4e5 times more expensive than natural gas on an energy content basis, so there is ample incentive for natural gas to invade this market. Whether or not natural gas replaces diesel demand, it is clear that natural gas will play a large role in the transportation sector, either as an alcohol feedstock or source of power generation for electric vehicles. 5.4. LNG exports
offset coal plant retirements. Renewables and nuclear energy can make only marginal contributions to power generation from 2011 to 2020. The underlying growth in U.S. power demand assumes the North American Electric Reliability Corporation (NERC) growth projection of 1.57% per year from 2011 to 2020. 5.2. Industrial natural gas demand U.S. industrial natural gas demand fell 22 percent between 1997 and 2010, from 23.3 Bcf per day to 18.1 Bcf per day as industrial gas consumers moved offshore to source cheaper stranded natural gas. However, major recent announcements by the U.S. chemical sector, which represents the largest industrial demand (35 percent), indicate a major rebound and reversal of trend. We anticipate that industrial demand will regain the lost 5.2 Bcf per day of natural gas demand from 2013 through 2020. Dow Chemical, for example, has announced plans to increase ethylene and propylene production in the United States based on ready supplies of shale gas, with the restart or startup of new U.S. facilities in 2012, 2014, 2015, 2017 and 2018. 5.3. Transportation fuel Natural gas demand in transportation has so far been fueled by on-road diesel conversions, mostly in local bus fleets and limited long-haul trucking operations. For the sake of estimating, we assume this trend continues and that 50 percent of diesel demand is ultimately met by natural gas in 2020. We assume that diesel demand grows 3% annually (the 20-yr trend is 3.7%/yr). At current
Major U.S. and Canadian LNG export projects have been announced over the last year, representing some 12.6 Bcf per day of new export capacity by 2015. Notably, Cheniere Energy received a formal okay from the U.S. Department of Energy on May 20, 2011 to export 2.2 Bcf per day of natural gas from its Gulf Coast LNG terminal.9 Assuming that current LNG imports (1.2 Bcf per day in 2010) ramp down to zero by 2020, and exports from the United States and Canada reach 50 percent of the announced capacity, also by 2020, then net LNG exports (effectively new U.S. natural gas demand) will reach 4.3 Bcf per day. The combined impact of these upside demand catalystsdpower demand, industrial natural gas demand, transportation fuel and LNG exportsdis summarized in Table 2. 6. Shale production 3X-plus by 2020 Fig. 5 provides a natural gas supply stack arranged from lowest to highest cost natural gas sources, in 2011 and 2020. The lowest cost natural gas production is “Associated-Dissolved,” which is a byproduct of oil production; next is “Conventional” gas production from high porosity and permeability reservoirs; then “Shale” gas, which is essentially production from a very low permeability and porosity mudstone; then “Coalbed Methane,” or coal seam gas, which is expensive due to water disposal requirements; then “Tight Sands” with its attendant higher development costs; and finally “LNG,” liquefied natural gas, which competes on the world market (see Fig. 1). Fig. 5 is complicated somewhat by the presence of Canadian equivalents for each category, but we agree with EIA that Canadian
80 70 60 LNG U.S.
Tight Sands Import Canada
BCF/ Day
50
Tight Sands U.S. Coalbed Methane Import Canada
Coalbed Methane U.S.
40
Shale Import Canada
Shale U.S.
30
Conventional Import Canada
Conventional U.S. Associated-Dissolved Import Canada
20
Associated-Dissolved U.S.
10 0 2011
2020 Fig. 5. U.S. Natural Gas Supply Stack.
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gas will have a dwindling influence on U.S. markets. Canadian natural gas has much higher value as an enabler of Canadian oilsands production than as an export product. Further, Canadian export gas has become less competitive since it must bear not only high transportation costs, but also a recently weakened U.S. Dollar relative to the Canadian Dollar. A market that requires new supply (either through new demand, or retirement of old supply) must do so at the marginal cost of adding production. We believe that it is clear that the U.S. must add substantially to its supply between now and 2020. This would be required simply to replace natural decline, which is in addition to the heavy demand requirements explained above. This means that cost of Tight gas will become the dominant price-setter in the marketplace. Tight gas capital and operating costs are estimated to be currently $8 per MMBtu. Domestic shale gas production is currently 14 Bcf per day, representing 22 percent of total U.S. demand. In order for relatively inexpensive shale gas to become the dominant price-setter, it must push all more expensive gas sources (Coalbed Methane þ Tight þ Tight Canada þ LNG) off the margin (i.e., displace them). This requires that shale gas production must rise to 45.4 BCF per day by 2020, more than triple current production. And this is based on EIA’s forecast of total gas demand growth of only 4 Bcf per day by 2020, compared to our estimate of potential demand growth of up to 31.4 Bcf per day. We judge the probability of shale gas tripling production by 2020 at anywhere near current prices as negligible. 7. Conclusion From the analysis provided above, we conclude simply that U.S. natural prices will rise quickly to $8 per MMBtu and that world
prices, on the back of major new resources that we have identified, will coalesce around a modest premium to the U.S. price. Natural gas conversion and transport technologies will ensure the convergence. Under this price environment, natural gas will resume its contemporary role as a premium world fuel based on environmental benefits and a long-term price advantage over oil based on energy content. Acknowledgment Portions of the analysis in this paper were performed by Papalote Ventures, LLC under contract to Zero Emission Energy Plants Ltd. Endnotes 1
EIA Annual Energy Outlook 2011: Don’t Worry, Be Happy. Petroleum Truth Report, Jan. 1, 2011. 2 35 Japanese Reactors Are Soon to be Out Of Line, NHK (Japan Broadcasting Corporation). nhk.or.jp/daily, May 13, 2011. 3 Noble Energy Announces Significant Discovery at Leviathan Offshore Israel. Offshore Energy Today, Dec. 30, 2010. 4 The authors are not authorized to provide specific proprietary price forecasts. 5 Pennsylvania Weighs Levy on Natural Gas Wells. Wall Street Journal, p. A5, May 14, 2011. 6 Osborn, Stephen, G., Methane contamination of drinking water accompanying gaswell drilling and hydraulic fracturing. Proceedings of the National Academy of Sciences, 2011 108, 8172e8176. 7 Armendariz, Al, Emissions from Natural Gas Production in the Barnett Shale Area and Opportunities for Cost-Effective Improvements. Environmental Defense Fund, Jan. 26, 2009, p. 1. 8 Gruver, Mead (AP): Gas drilling blamed for soaring ozone in Wyoming. CitizensVoice.com, March 9, 2011. 9 U.S. Approves First Natural Gas Exports. Financial Times, FT.com, May 20, 2011. 10.