Production

Marketed natural gas production increased for the fifth consecutive year in 2010, as producers continued to realize gains from improved technology, particularly in horizontal drilling in shale formations.figure data Additionally, high liquids prices drew producers to “wet” natural gas plays. Production gains in the lower-48 States more than offset declines in the GOM (Figure 1) where production continued an overall trend of long-term declines, falling from 6.7 Bcf per day to 6.2 Bcf per day.¹

Onshore marketed production grew from 51.5 Bcf per day in 2009 to 54.6 bcf per day in 2010, even as Henry Hub prices remained relatively low. Prices increased about 11 percent from the previous year's abnormally low levels, but were about 50 percent lower than the abnormally high levels of 2008 ($8.86 per MMBtu). Compared to the 5-year (2005 – 2009) average price of $7.07 per MMBtu, 2010 prices were about 38 percent lower.

Drilling activity rose in 2010

The natural gas rig count rose over the year, from 804 at the beginning of 2010 to 929 at the end of the year.² Horizontal natural gas-directed rigs grew about 36 percent in 2010, from 465 to 633. Directional rigs remained flat, and vertical rigs fell by 22 percent. The shift toward horizontal natural gas drilling rigs largely reflected the ongoing shift in drilling toward shale formations. The increased use of new drilling technologies, hydraulic fracturing as well as horizontal drilling, means that the overall number of natural gas rigs has taken on new meaning.  For example, shale wells often have higher initial production rates; and horizontal rigs have a greater number of wells per rig (although this is somewhat offset by a steeper decline curve than vertical rigs).³ As a result, even as rigs are far below levels reached in 2008, production has continued to grow.

High Natural Gas Liquids Prices Drove Production Growth

NGLs are the heavier hydrocarbons that are extracted when natural gas is processed, and can be fractionated into ethane, normal butane, iso-butane, and propane. They are important inputs to many industrial activities. In 2010, production of NGLs was at its highest level on record, at more than 2 million barrels per day.

Portions of both the Eagle Ford Shale and the Marcellus Shale are rich in NGLs. Natural gas-directed rig growth was aggressive in the Eagle Ford in 2010, as the number of rigs nearly doubled over the year, increasing to more than 80 operating units.⁴ The rapid growth in the Eagle Ford shale in recent years has highlighted the importance of NGLs in driving production strength. Although parts of the Marcellus Shale are liquids rich, and saw growth in 2010, the growth may have been somewhat limited due to lack of processing capacity and local markets for liquids, particularly ethane. Several proposed projects in the Marcellus Shale might address the excess ethane. For example, El Paso Corporation proposed the Marcellus Ethane Pipeline System, which would transport up to 60,000 barrels per day of ethane from fractionation plants to interconnections with third-party pipeline systems in Louisiana. The project has a proposed in-service date of April 1, 2013.⁵

The rise in liquids production also stretched existing processing capacity to its limit in other areas of the country. Oneok Partners, for example, announced it would build 100,000 barrels per day of fractionation capacity by 2012 to support NGL production from the Bakken Shale in North Dakota.⁶ Enterprise and Targa Resource Partners also announced major NGL capacity additions near the Eagle Ford.

Other Forces Put Both Positive and Negative Pressure on Production Growth

Despite strong year-over-year production growth, producers did face some challenges in 2010. Offshore, following the Macondo well blowout in April 2010, a temporary moratorium affected some GOM drilling. Onshore, in the Marcellus Shale in 2010, concerns about drilling safety led regulators to impose fines and penalties on a number of companies, including Cabot Oil & Gas and EOG Resources. Pennsylvania's Department of Environmental Protection fined Cabot for groundwater contamination and fined and ordered EOG to suspend drilling following a well blowout. While some lawmakers have proposed drilling bans and other regulations, production in the much of the Marcellus—especially Pennsylvania—has continued to grow.

Another obstacle to natural gas production in 2010 was weather. In general, onshore lower-48 production is less susceptible to traditional weather threats, such as the hurricanes and tropical storms experienced in the GOM and coastal areas of Texas and Louisiana. However, onshore production is not immune to cold weather and freeze-offs. In January of 2010, freeze-offs reduced national natural gas dry production by 5 percent.

Unlike regulatory and environmental challenges, joint ventures and foreign investment probably helped to boost production in 2010. Foreign companies partnered with U.S. producers to gain expertise in development of shale natural gas. For example, India’s Reliance Infrastructure entered into three large joint ventures to drill in shale plays, including a $1.7 billion deal with Atlas Resources in the Marcellus Shale. Seven joint venture deals were reached in the United States in 2010 for a total of $9.2 billion, and outright sales of shale lease ownership also took place.

Table 2. Joint ventures in U.S. shale plays in 2010

Foreign Partner	Domestic Partner	Shale Play	Deal Amount ($ billions)
Reliance	Pioneer	Eagle Ford	1.3
Reliance	Atlas	Marcellus	1.7
Reliance	Carrizo	Marcellus	0.4
Total	Chesapeake	Barnett	2.3
CNOOC	Chesapeake	Eagle Ford	1.1
British Gas	EXCO	Marcellus	1.0
Mitsui	Anadarko	Marcellus	1.4
Total			9.2

Source: U.S. Energy Information Administration, Natural Gas Monthly

---

Footnotes

 

 

Demand

Consumption Rose as the Economy Recovered

Natural gas consumption rose in 2010, with strength in the electric power and industrial sectors driving the increase. EIA reported two estimates of natural gas consumption for 2010 because it changed its methodology in July 2010.⁷ For the purpose of comparing 2009 and 2010 consumption, it is best to compare consumption estimates based on the same (older) methodology for the two years. By that estimate, 2010 consumption was 65.4 Bcf per day, an increase of 2.8 Bcf from the previous year's level of 62.6 Bcf per day. (Using the new methodology, estimated consumption in 2010 was 66.0 Bcf per day.)

The Electric Power Sector Showed Strength

Hot summer weather had a major effect on natural gas use in the electric power sector during 2010. Consumption of natural gas for electric power generation rose close to historical highs in the summer of 2010 as temperatures were very warm across most of the county. The only region that was cooler than the 30-year average in the third quarter of 2010 (July, August, and September) was the Pacific Northwest Census region. The West South Central Census region, which includes Texas, Oklahoma, Louisiana, and Arkansas, had the hottest third quarter in the country, with 1,593 cooling degree-days (CDDs), 12 percent more than the 30-year normal. This region is very dependent on natural gas-fired power generation.

Colder-than-normal weather in the winter also led to an increase in consumption of natural gas for electric power generation. January heating degree-days (HDDs) were 2 percent greater than normal and February HDDs were 12 percent greater than normal. States in the southeast United States in particular experienced the cold snap, and the use of natural gas for power increased substantially in that region. Some parts of the Southeast are very dependent on electric power for space heating needs and much of the area is also very dependent on natural gas-fired generators. January and February 2010 consumption in Florida, for example, rose 23 percent and 15 percent, respectively, year over year. Cold weather again in December 2010 resulted in a 27-percent higher demand for power in Florida over the same month in 2009.

Between 1995 and 2010, natural gas capacity additions in the electric power sector have outnumbered capacity additions of other generation types. Generators added close to 258 GW of natural gas-fired capacity, about 81 percent of total generation capacity additions in that time period. Most of these additions were more efficient combined cycle plants. By contrast, most coal-fired power plants were built before 1980. Many of these natural-gas-fired plants are only now coming into frequent use, as natural gas prices have become competitive with Appalachian coal prices. Over the past several years, natural gas has made up an increasing share of total generation, largely at the expense of coal. At the end of 2010, natural gas-fired generators constituted 39 percent of 1,042 GW of total electric generation capacity. After falling from high levels in the summer of 2008, natural gas prices remained low and relatively stable through 2010, and power generators took advantage of prices by using more of their natural gas-fired generation capacity. During 2010, the price of the NYMEX near-month Central Appalachian coal futures contract rose gradually, and natural gas prices fell over the year, which may have led to fuel switching, particularly near the end of the year.

Industrial Consumption Rebounded

Industrial use of natural gas rebounded in 2010, increasing to 18.1 Bcf per day from 16.9 Bcf per day in 2009, as prices remained relatively low and the economy expanded. The natural gas-weighted industrial production index⁸ increased from 82.0 in 2009 to 86.5 in 2010. Industrial consumption was slightly above the 5-year average of 17.9 Bcf per day.

---

Footnotes

 

Imports and Exports

With natural gas production increasing more rapidly than consumption, reliance on natural gas imports declined. Canada was the main source of natural gas pipeline imports. The United States also receives a small amount of imports in the form of liquefied natural gas (LNG).

Imports Fell as Production Grew

figure dataIn 2010, U.S. net imports (gross imports minus exports) decreased by 0.2 Bcf per day to 7.1 Bcf per day, marking the lowest volume of net imports since 1994 (Figure 2). Net imports represented 10.8 percent of total U.S. consumption, the lowest proportion since 1993. This is a remarkable change from just 2007, when net imports were the highest on record, equaling roughly 16.4 percent of consumption.

Pipeline Trade within North America

Gross pipeline imports from Canada remained around 9.0 Bcf per day. The West and Upper Midwest historically received the largest volumes of imports from Canada; for example, in 2010, Eastport, Idaho, received 1.9 Bcf per day. Significant volumes of natural gas also arrived into New York, North Dakota, Washington, Montana, and Minnesota.

A small increase in gross imports from Canada coincided with a strong increase in exports from the United States to Canada, driving net imports from Canada down for the fourth consecutive year. U.S. exports to Canada increased by 5.4 percent between 2009 and 2010. Historically, the largest volume of exports to Canada goes through St. Clair, Michigan, accounting for 88 percent of the total in 2010. Net imports from Canada in 2010 totaled 7.0 Bcf per day, a decrease of 1.1 percent from the previous year. Canadian supplies generally have decreased as a share of the U.S. market.

Gross U.S. pipeline exports to Mexico, a major destination for U.S. natural gas exports, decreased slightly to about 0.9 Bcf per day in 2010, which is close to the average level over the past 5 years.

LNG Imports

LNG imports fell in 2010 by more than 4.6 percent. Although LNG imports declined, the number of LNG source countries expanded from five to seven, with Peru and Yemen shipping cargoes to the United States for the first time from new liquefaction plants. The volume of LNG imports from existing exporters, however, was well below the 2009 level. Decreased supplies from Trinidad and Tobago (the source country with the largest contribution to U.S. LNG imports) and Egypt primarily accounted for the decline in 2010 deliveries. Imports from these countries totaled 0.5 Bcf per day and 0.2 Bcf per day, respectively, falling significantly from their 2009 levels.

In 2010, U.S. natural gas prices traded well below prices in European and Asian markets. Other parts of the world, particularly some Asian and European countries, depend more on LNG imports than the United States does. For example, Japan is the largest importer of LNG, with more than 40 LNG import terminals.  In 2010, Japan imported 3.3 trillion cubic feet (Tcf) of LNG (about 9.0 Bcf per day), close to 60 percent of the total LNG imports for the Asia and Oceania region and more than 7 times what the United States imports. Other major LNG importers include South Korea and Spain, which imported 1.2 Tcf (3.3 Bcf per day) and 910 Bcf (2.5 Bcf per day), respectively, of LNG in 2009, according to the most recent data available.

 

Storage Inventories

Strength in domestic production in 2010 led to record-setting inventories in underground storage at the end of the injection season. At the end of October, working natural gas in storage totaled 3,847 Bcf, the highest monthly level on record.⁹ Demonstrated peak working gas capacity also increased in 2010 to 4,049 Bcf. Working gas design capacity, a less conservative measure of capacity, also increased to 4,353 Bcf from 4,313 Bcf in 2009.

Despite the high inventory levels recorded October 2010, high consumption and withdrawals in late November and December actually resulted in a net withdrawal of about 5 Bcf during 2010,compared with net injections of about 349 Bcf during 2009.

---

Footnotes

 

Prices

National Trends

Despite some weather-related spikes, natural gas prices were moderate in 2010, reflecting strength in supply. The 2010 price was well below the 5-year (2005 – 2009) Henry Hub price level of $7.28 per Mcf and much lower than the unusually high 2008 price of $9.13 per Mcf. figure dataIt also represented an 11- percent increase from the unusually low 2009 price, which largely resulted from the economic downturn.

Over the year 2010, the Henry Hub price fell from $6.00 per Mcf in January to $4.38 per Mcf in December (see Figure 3).

While the overall pattern for the year was one of decline, daily price movements were more varied. For some days in January, the Henry Hub spot price spiked above $7.50 per Mcf, the result of high demand during very cold weather. In June, the price rose briefly above $5.00 per Mcf, likely as a response to the forecast of a more active hurricane season.

Regional Trends

Natural gas prices have always varied from one part of the country to another. In 2010, the most important differences from the national average came in the Rockies, where prices were lower than the national average, and in the northeastern Atlantic Coast, where prices were higher.

In the Rockies, the price at the Opal Hub, located in western Wyoming and an indicator of Rocky Mountain prices, was on average about 43 cents per Mcf below the Henry Hub price in 2010, although that difference (the basis¹⁰) has narrowed greatly since the opening of the Rockies Express Pipeline in 2009 (Figure 4). Several years ago, before the opening of the Rockies Express Pipeline, the difference between Opal and the Henry Hub was very wide because infrastructure constraints did not allow for sufficient transportation of gas out of the region. As a result, Opal Hub prices periodically fell to very low levels. In other words, local supply exceeded local demand, creating surpluses that occasionally lead to prices of only a few cents.

In the northeastern Atlantic Coast, prices at Transcontinental Pipeline's (Transco) Zone 6 pricing point for delivery into New York City remained generally close to the Henry Hub prices, except in times of cold weather. Transco Zone 6 New York prices often spike considerably higher than Henry Hub during cold parts of the winter, due to pipeline constraints and bottlenecks going into the Northeastern Atlantic Coast. Prices at Transco Zone 6 New York reached their high for 2010 at $21.00 per Mcf on December 13.¹¹

More information about the dynamics underlying regional prices is available here: http://www.eia.gov/todayinenergy/detail.cfm?id=350

End Use Prices

Prices of natural gas used for industrial and electric power rose 1 percent and 7 percent, respectively, between 2009 and 2010. Commercial and residential prices, however, fell somewhat from 2009 levels. figure dataCommercial and residential prices are often slower to respond to market forces, as local distribution companies often hedge supply, and the regulatory process adds delays in transmitting prices from suppliers to customers.The commercial and residential prices fell from $10.06 and $12.14 per Mcf in 2009 to $9.15 and $11.21 per Mcf, respectively, in 2010. In addition, greater consumption volumes during the winter causes per unit prices for residential natural gas to be lower than they are in the summer months (Figure 5).

 

 

 

---

Footnotes

 

Pipeline Construction

Production growth in shale plays drove pipeline construction in 2010, especially in the Southeast and Midcontinent. Major pipeline projects, including the Fayetteville Express and the Midcontinent Express expansion, came online, helping to bring this new production to consumers (Table 3).

Table 3. Major Pipeline Projects Were Located in the South

Project	Existing System	Length of Entire System	Capacity of Entire System	Length of Expansion	Capacity of Expansion	Begin	End
ETC Tiger	N/A	175 miles	2.0 Bcf/d	N/A	N/A	Panola County, TX	Richland Parish, LA
Fayetteville Express	N/A	185 miles	2.0 Bcf/d	N/A	N/A	Conway County, AR	Panola County, MS
Haynesville Expansion	Regency Intrastate Gas System	450 miles	2.1 Bcf/d	121 miles	1.1 Bcf/d	Caddo Parish, LA	Franklin Parish, LA
Midcontinent Express Expansion	Midcontinent Express	502 miles	1.8 Bcf/d	0 miles	300 MMcf/d	Bryan County, OK	Choctaw County, AL
Fayetteville Lateral Expansion	Fayetteville Lateral	165 miles	1.5 Bcf/d	100 miles	840 MMcf/d	Conway County, AR	Coahoma County, MS

Overall, pipeline construction activity during 2010 increased slightly, continuing an overall upward trend (Figure 6). At least 55 natural gas pipeline projects (those for which data and records are available with state and federal regulators) were completed in 2010 in the lower-48 States. These 55 projects in 2010 added over 2,142 miles of pipeline and represented investments totaling about $8.1 billion. figure data

The need for increased access to growing natural gas supplies from shale formations continued to drive pipeline construction in 2010. Rapid production-related infrastructure growth occurred in northeastern Texas, as well as Louisiana, Arkansas, and Mississippi. Several projects will increase the flow of natural gas from the Haynesville Shale to regional markets. For example, one major project is ETC Tiger Pipeline, completed by Energy Transfer Partners, LP in December 2010. The new pipeline, which has a design capacity of 2 Bcf per day and is only 175 miles long, picks up supplies in the critical supply regions of the Haynesville Shale, Bossier Sands, and Fort Worth Basin production areas for eventual delivery to end-use markets in the Midwest and Northeast via seven interstate pipelines.

Elsewhere, the Fayetteville Express pipeline, a joint venture between Kinder Morgan Energy Partners, LP and Energy Transfer Partners LP, was completed late in 2010, adding 2.0 Bcf per day of capacity to Fayetteville producers. This pipeline helps move gas produces in the Fayetteville Shale to end-use markets in the Midwest and Northeast via connections with four interstate pipelines.

The new Midcontinent Express Pipeline (MEP), completed in July 2009 and expanded in 2010, has proven to be a major infrastructure project that affects regional flow patterns. The pipeline, also a joint venture between Kinder Morgan Energy Partners, LP and Energy Transfer Partners, LP, interconnects with several major pipeline systems and connects with supply sources such as the Barnett Shale.

Although little pipeline capacity was added in the Northeast during 2010, several major projects are underway to give producers in the Marcellus Shale an outlet for their production. Tennessee Gas Pipeline's 300 Line Project, which opened in November 2011, involves the installation of seven looping segments in Pennsylvania and New Jersey totaling approximately 127 miles of 30-inch pipeline. Upon completion, Tennessee expects that the Line 300 Project will increase natural gas delivery capacity in the region by approximately 0.4 Bcf per day. Texas Eastern Gas Transmission (TETCO) expects to complete portions of its TEAM/TIME III in southern Pennsylvania in 2011, which will add about 0.5 Bcf per day of capacity.

In addition to the new pipeline capacity expected for 2011 in the Northeast, other areas of the country also have pipeline infrastructure projects underway. For example, in the summer of 2011, El Paso Corporation's 660-mile Ruby Pipeline came online. This pipeline begins in Opal, Wyoming, and ends at an interconnection in Malin, Oregon. Infrastructure additions also continue in the Southeast to support growth in production from areas such as the Eagle Ford, Haynesville, and Fayetteville Shales.