North American Shale Gas Production: A Bright Dawn for the Global Energy Trade or a Gloomy Monday?

ByLes Deman, for Cornerstone

The terms “game changer” and “disruptive technology” are often reserved for Silicon Valley or the pharmaceutical industry; however, they are increasingly being applied to the development of North American shale gas and shale oil resources. At the start of the millennium, the U.S. was facing a growing gap between gas demand and production. In a government- and industry-sponsored study in 2003, the National Petroleum Council concluded that North American producing areas will only provide 75% of long-term needs and that new, large-scale resources such as LNG and Arctic gas would be necessary to meet demand.(1) Today, some studies predict that North America will soon be a net exporter of natural gas and that oil shale development has the potential to reduce imports to zero within 20 years. In less than a decade the petroleum outlook in North America changed from a mature and declining industry to a vibrant and fast-growing economic segment of the economy.

An aerial photo of the Dominion Liquified Natural Gas Facility in Cove Point, MD.

An aerial photo of the Dominion Liquified Natural Gas Facility in Cove Point, MD.

If the optimism about North American shale resources is borne out, it will have a profound effect on world energy markets. A high degree of success in exploiting gas and oil shales would be contagious, increasing activity levels across the globe. Larger supplies of natural gas and oil would depress the price for all fuels. Moreover, lower energy prices would encourage consumption and raise economic growth. There would be changes in the geopolitical and economic balance among exporting and importing nations as oil/gas purchase options increase and as nations become more energy self-sufficient. In the near term it would be wise for world energy markets to prepare for North America becoming a global LNG exporter.

The U.S. Experience

How and when these shale fuels will be developed outside North America remains uncertain; still it might be useful to provide some background on the U.S. shale gas experience, in particular its market disruptions and cyclicality. Throughout its 100-plus-year history the petroleum industry focused on conventional natural gas production, which accounted for about two-thirds of U.S. production 10 years ago. Declining natural gas production after 2000 prompted global petroleum companies and domestic gas utilities to propose 23 new LNG import terminals by 2003.(1) Those proposals were abandoned a few years later when it became apparent that technical innovations in fracturing shale and horizontal drilling would result in a resurgence in U.S. natural gas production. As Figure 1 shows, by 2012 U.S. gas production was one-third higher than the 2005 trough and shale gas accounted for 37% of the total energy production.

 

Figure 1. Recent U.S. natural gas production history. Source: U.S. Energy Information Administration. Coalbed methane production in 2012 was estimated and conventional gas includes tight gas. (Note: Bcfd = billion cubic feet per day)

Figure 1. Recent U.S. natural gas production history. Source: U.S. Energy Information Administration. Coalbed methane production in 2012 was estimated and conventional gas includes tight gas. (Note: Bcfd = billion cubic feet per day)

Adding so much supply in a relatively short period transformed the North American market from one that was in a shortage condition to one in surplus. Since the North America gas market is basically a closed system, with little ability to engage in international trading, this surplus sent natural gas prices plummeting. In 2005 the spot price ($2012) of Henry Hub natural gas, which is the primary North America benchmark, peaked at over $10.00 per million Btu (MMBtu), but by 2012 it fell to $2.75 per MMBtu. In contrast, internationally traded natural gas was priced at a sizeable premium to the Henry Hub, particularly after 2009 (see Figure 2). Since quantity demanded always equals quantity supplied, the market was forced to find unique ways to maximize demand and constrain supply.

Figure 2. Key international natural gas prices

Figure 2. Key international natural gas prices

Finding markets to absorb large volumes of natural gas proved daunting because this period included the largest economic decline since the great Depression. Total U.S. energy consumption fell in both 2008 and 2009, impacted in part by business closures and downsizing. Over these same two years natural gas consumption also showed a net decline (up slightly in 2008 but down in 2009) due primarily to falling use in the industrial sector. The industrial sector saw a rebound in 2010 as economic growth resumed, with natural gas use rising about 2.5 Bcfd (+15%) between 2009 and 2012. residential and commercial consumers have not generated any demand growth over this period due to more efficient appliances, milder winters, and a tepid new housing market. The only contestable market left for natural gas was power generation.

On a gross basis, the electric power sector increased gas use by about 8.9 Bcfd between 2005 and 2012 (+55%). With net generation roughly flat over this period (see Figure 3) most of the gain in natural gas consumption was at the expense of coal. This gain in gas share accelerated in 2008, when in a period of seven months (September 2008 to April 2009), the market bid down nominal Henry Hub spot gas prices from an $8-handle to a $3-handle. Various estimates have gas-for-coal displacement climbing from near zero in 2008 to roughly 2.5 Bcfd in 2009. By 2012, which saw the Henry Hub spot price fall to $2.00 per MMBtu in April, coal-to-gas switching boosted electric power generation demand for natural gas by nearly 7.0 Bcfd. Of course, coal’s share of the electric generation market plummeted from 50% in 2005 to 37% in 2012. Surplus U.S. coal supplies sent exports soaring over 150% over this seven-year period, with Europe the main recipient (up 250%).

Figure 3. U.S. net electricity generation by source. Source: U.S. Energy Information Administration2

Figure 3. U.S. net electricity generation by source. Source: U.S. Energy Information Administration(2)

With so much new domestic natural gas, U.S. imports saw a rapid decline. Net natural gas imports to the U.S. totaled 9.9 Bcfd in 2004, mainly from Canada; but by 2012, volumes declined to 4.1 Bcfd, a 58% plunge. Moreover, low U.S. prices increased the demand for exports to Mexico, which rose by 103% over the same period.

To the market’s surprise, shale gas production kept growing despite natural prices widely acknowledged to be below exploration and production costs. History has shown that for commodities like natural gas—those that involve large amounts of capital to purchase leases, develop fields, and construct necessary infrastructure—it is often difficult to quickly ramp activities up or down. Low natural gas prices impacted gas drilling activity, with recent reports showing fewer than 400 rigs drilling for gas versus the modern day peak of 1606 rigs in August 2008.

Now, in early 2013, some data suggest that natural gas production growth has flattened and that declining drilling levels may now be sufficient to balance supply and demand. With Henry Hub natural gas futures generally seeing prices above $4.00 per MMBtu for the first time in roughly 18 months, the market appears to be giving credence to a tighter supply-demand balance in the months ahead.

What many analysts in the U.S. have garnered from this four- year cycle is that, in the near term, the market clearing sector on the demand side is electric power generation, with natural gas prices targeting gas-for-coal switching economics. On the supply side, the U.S. was able to ratchet down natural gas imports from Canada, but matching domestic gas production to demand was more difficult and storage levels set record highs. Moreover, there is every reason to believe that North America has the capacity to increase shale gas production significantly over the next two decades, raising the possibility that it might become a major LNG exporter.

International Implications: Lessons and Opportunities

Over the past two decades a host of studies have projected rapid growth in the global natural gas trade.(7–9) On the demand side, the driver for this growth is an increased emphasis on cleaner burning fuels, particularly in the electric power and industrial sectors as a replacement for coal and oil. Supply-side drivers include international capital to exploit remote gas resources in the Middle East, Russia, and Australia and commensurate investment to deliver the gas to consuming areas via LNG or pipeline. Consumers were excited about prospects for obtaining an attractive fuel at a discount to oil, while exporters were looking to sell gas at an oil-equivalent basis. There were even discussions about forming a gas cartel similar to OPEC to enhance pricing power. With the rapid development of North American shale gas and optimism on international shale gas prospects (see Figure 4), this paradigm has changed drastically.

Figure 4. EIA assessment of potential world shale gas sources.

Figure 4. EIA assessment of potential world shale gas sources.(11)

Efforts are underway to determine the viability of shale gas developments outside North America, with recent activity in China, Poland, the UK, Argentina, and elsewhere. Thus far there are few reports of sustained activity levels, so great uncertainty remains about the scope and timing of exploiting this potentially large resource. Nonetheless, the promise of this bonanza is emboldening natural gas importers to negotiate for lower prices and better terms.(9) It may well be that the catalyst in moving the international gas trade toward a free market will be the onset of North American LNG exports.

Today, there are only three approved LNG export terminals in North America: the Kenai Alaska Terminal, operating since 1969, the Sabine Pass Louisiana Terminal, and the Freeport Texas Terminal. The latter two LNG terminals were initially constructed as Gulf Coast import facilities and will not be capable of exporting gas until 2016 or 2017. However, there are applications to export over 28 Bcfd of LNG in the U.S. and proposals to build 22 export terminals, 17 in the U.S. and five in Canada. Many of these proposals are placeholders for companies that would like to profit if the U.S. reduces natural gas export constraints. These constraints include industry groups that are lobbying the U.S. Congress to keep cheap and plentiful natural gas in North America for gas-intensive manufacturing, such as petrochemicals. Environmental groups are against new terminals to prevent coastal damage and because of public safety concerns. Alternately, energy producers are lobbying Congress to accelerate LNG export permits.

In addition to U.S. politics, North American LNG exports are dependent on a multitude of variables, including: future global economic growth; environmental regulations on fossil fuel use in all nations; shale gas production costs and fracking regulations; world oil and natural gas prices; competitive actions of other natural gas exporters; technological progress on carbon capture and storage, growth in renewable fuels; and energy efficiency gains. Looking at a few scenarios can provide perspective on the impact that North American shale gas can make.

Two recent studies provide a number of U.S. LNG export scenarios (Figure 5). In the 2013 U.S. Annual Energy Outlook (AEO), the Reference Case shows new LNG exports beginning at 0.6 Bcfd in 2016 and gradually rising to 4.5 Bcfd in 2040.(10) In a more optimistic scenario, High Resource and Low/No Net Imports, LNG exports rise to 10.6 Bcfd in 2040. Another recent report by NERA Economic Consulting to the U.S. Department of Energy showed that LNG exports in 2035 could range from 3.8 Bcfd to 15.8 Bcfd.(12) Canada could easily add 3.0–5.0 Bcfd of LNG exports to the equation.

Scenarios for U.S. LNG exports in 2035. Sources: U.S. Energy Information Administration and NERA

FIGURE 5. Scenarios for U.S. LNG exports in 2035. Sources: U.S. Energy Information Administration and NERA(10,12)

Nations importing these incremental volumes of LNG could use the re-gasified product to displace coal, oil, or other more carbon-intensive fuels. The energy content of 1.0 Bcfd of LNG is the equivalent of about 180,000 barrels of oil per day or roughly 14 million metric tons of coal on an annual basis. Using optimistic North American LNG export assumptions result in the displacement of over 5% of estimated annual world oil and coal use in the 2030–2040 timeframe and a much larger share of world trade in these fuels.(6,13) Unit prices and producer revenues would be lower for oil and coal exporters, and upheavals could be precipitated in exporting nations that depend on these proceeds for income supplements, for subsidies to influential groups, and for related programs.

Adding to the potential for disruption is the likelihood of a rapidly growing supply of liquids from the shale revolution. For gas-prone shales, the liquids come in the form of natural gas liquids (NGLs), which should grow by 144% in the U.S. between 2010 and 2030 according to the AEO’s High Resource Case. In this same case, production growth from oil shale would make the U.S. self-sufficient by 2040. There is no reason to believe that other regions with potential shale resources would not also see a surge in liquids production.

Hedge Your Bets

It is difficult for most businesses to foresee the long-term effects of game-changing or disruptive technologies, much less take advantage of them. While it remains to be seen whether developments in producing natural gas and oil from shales qualify for such a designation, the reemergence of natural gas and oil growth in the U.S. is impressive. However, we have less than a decade of history to judge whether this is an ad hoc event. We still do not know if this trend will continue and if so, for how long? Nor do we know whether the North American experience is applicable to other regions. While it may take a few more years to answer these questions, savvy businessmen and governments that have livelihoods tied to alternate fuels such as coal and conventional petroleum should hedge their bets.

On the consuming side, I would be reluctant to enter into long- term and fixed price contracts for any fuel—coal, oil, nuclear, pipeline natural gas, or LNG. If the optimists hold sway, not only will the price of these fuels decline, there will also be many sellers to choose from. Producers of coal and other fuels can try to lock in long-term, fixed price contracts, perhaps with take-or-pay clauses. This might prove advantageous even if the terms are more lenient than in current agreements. Getting the buyer to invest in the supply chain might be another way to protect a producer via investments in production, transportation, export/import terminals, and end-use facilities.

Then again, some new technology could make natural gas and oil shale developments uneconomic. Low-cost carbon capture and storage could reinvigorate coal. Battery technology and low- cost solar power could make central electric power stations obsolete. It is not a question of whether a better mousetrap will come along, it is just a matter of when. My advice is to invest in a portfolio of energy-producing and consuming technologies and be in a position to take advantage of the next “game changer”.

NOTES
1. Note that shale gas and oil is a subset of “unconventional” petroleum fuels. Unconventional oil and gas typically includes production from tight formations, coalbed methane, shales, kerogen, hydrates, etc.
2. For an updated list see: fossil.energy.gov/programs/gasregulation/reports/ summary_lng_applications.pdf

REFERENCES
1. National Petroleum Council, Balancing Natural Gas Policy, September 2003.
2. EIA database, www.eia.gov
3. British Petroleum, Statistical Review of World Energy 2012, Accessed May 2013, www.bp.com/statisticalreview
4. Platts Database, Accessed May 2013, www.platts.com
5. YCharts, Accessed May 2013, www.ycharts.com
6. ExxonMobil, The Outlook for Energy: A View to 2040, 2013. Available at: www.exxonmobil.com/Corporate/Files/news_pub_eo2013.pdf
7. International Energy Agency, World Energy Outlook 2012, November 2012.
8. British Petroleum, BP Energy Outlook 2030, January 2012.
9. J. Marson, J., Parkinson, In Reversal, Neighbors Squeeze Russia’s Gazprom over Natural Gas Prices, Wall Street Journal, 1 May 2013.
10. U.S. Energy Information Administration, Annual Energy Outlook 2013, January 2013. Available at: www.eia.gov/forecasts/aeo/pdf/0383%282013%29.pdf
11. U.S. Energy Information Administration, World Shale Gas Resources: An Initial Assessment of 14 Regions Outside the U.S., Accessed May 2013, Available at www.eia.gov
12. NERA Economic Consulting, Macroeconomic Impacts of LNG Exports from the United States, December 2012.
13. U.S. Energy Information Administration, International Annual Energy Outlook 2011.

This article is republished by permission from www.conerstonemag.net. All rights reserved.

The content included in Cornerstone is based on the opinion of the authors, and does not necessarily reflect the views of the World Coal Association or its members.

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