Production

Total marketed production grew by 7.9 percent in 2011, from 61.4 Bcf/d in 2010 to 66.2 Bcf/d in 2011. 2011 was the sixth consecutive year of growth in marketed production, and the largest year-over-year percentage increase since 1984. Production gains continued despite falling prices, as producers continued to capitalize on more efficient drilling technologies and target wet gas. Additionally, a number of other factors helped to buoy production, including foreign joint venture partners financing production, increases in natural gas production associated with oil production, and drilling required for producers to hold leases.

figure data

The increase in production came exclusively from the onshore, lower-48 States, where marketed production rose from 53.9 Bcf/d to 60.2 Bcf/d. In the Federal offshore Gulf of Mexico (GOM), marketed production fell from 6.2 Bcf/d in 2010 to 5.0 Bcf/d in 2011, continuing a long-term trend (Figure 3). Following the Macondo well blowout in April 2010, a temporary moratorium affected some GOM drilling; however, natural gas production in the Gulf has been declining for the past several years as producers shift to more economical areas of production.¹

figure data

Onshore production growth was largely concentrated in shale plays. The increase in shale natural gas production in the past several years is largely due to strong production in the Haynesville Shale in Louisiana and the Marcellus Shale in Pennsylvania. Production out of Texas, particularly in the Eagle Ford shale, has also grown, particularly in the past year (Figure 4).

The growth in onshore production has made production disruptions from freezing weather more important; “freeze-offs” (gas flow blockages resulting from water vapor freezing in the gas stream) could rival hurricanes as the major weather-related disruption at least for short periods. Indeed, frigid weather led to major production curtailments for several days in February 2011. Natural gas dry production averaged about 59.2 Bcf/d the last week of January 2011 and fell to an average of 53.5 Bcf/d during the first week of February, based on estimates from BENTEK Energy LLC (Bentek) (Figure 5). It should be noted, however, that while the effects of shut-ins resulting from hurricanes can last months—with some wells never returning to service—recovery time for cold-weather-related shut-ins typically is only a few days, as was the case for the February 2011 freeze-offs.

Natural gas rotary rig count declines

figure data

U.S. production growth continued even as natural gas rotary rig counts declined. The weekly overall natural gas rig count, as reported by Baker Hughes Incorporated, averaged 887 rigs in 2011, compared with 943 rigs in 2010. The shift towards horizontal rigs, which continued in 2010 and 2011, underlies the increase in production (Figure 6). Horizontal wells, especially when combined with hydraulic fracturing, typically have significantly higher initial production rates than vertical wells.

Shift towards crude oil and natural gas liquids contributes to production growth

figure data

By the end of 2011, the oil rig count overtook the natural gas rig count by nearly 100 rigs, as drillers shifted their focus to oil to take advantage of its much higher price relative to gas (Figure 7). As the price of Brent crude oil remained well over $100 per barrel, and natural gas prices fell through 2011, the widening price spread provided an incentive for producers to focus on oil production. In addition to increasing oil production, expanding oil-directed drilling programs also generated increases in natural gas produced in association with the oil.

Also related to the relatively high oil prices is an increase in drilling in areas rich in natural gas liquids (NGLs), prices for which are linked more closely to crude oil than natural gas. Throughout 2011, natural gas rigs have increased in key areas where NGLs, lease condensate, and crude oil production occurs, such as the Utica Shale in Ohio and the Eagle Ford shale in Texas, according to Smith Bits data. NGLs, the hydrocarbons that are extracted from natural gas, include ethane, propane, butane, and pentane. Because of the comparatively high market values for NGLs, drilling for natural gas in liquids-rich areas is usually profitable for natural gas producers. For example, throughout 2010 and 2011, Chesapeake Energy began ramping up its investments in the liquids-rich portion of Ohio's Utica Shale, which underlies the Marcellus Shale.

Several projects have been proposed to address processing and handling the expanding volumes of NGLs. In 2011, Enterprise Products Partners LP announced plans to build a 1,230-mile pipeline to transport ethane to the Gulf Coast from the Marcellus and Utica shales.² The company has also announced numerous plans for new fractionators, which break NGLs into their separate components.

Other forces affect production levels

Joint ventures and foreign investment may have helped to boost production in 2011. Foreign companies partnered with U.S. producers to gain expertise in the development of shale natural gas, which has helped spur drilling even in a low-price environment. Korea National Oil Corporation (KNOC), for example, entered into a $1.6 billion joint venture with Anadarko to drill in the Eagle Ford shale. Five major joint venture deals were reached in the United States in 2011 for a total of $3.7 billion (Table 2).

Table 2. Major shale gas and tight oil joint ventures in 2011³

Foreign Partner	Domestic Partner	Shale Play	Deal Amount ($B)
CNOOC	Chesapeake	Eagle Ford	1.1
KNOC	Anadarko	Eagle Ford	1.6
Marubeni	Marathon	Niobrara	0.3
Mitsui	SM Energy	Eagle Ford	0.7
GAIL	Carrizo	Eagle Ford	0.1
Source: U.S. Energy Information Administration based on trade press and company announcements.

 

---

Footnotes