Released: January 16, 2014
U.S. natural gas production increases by 1% in 2013
Average dry natural gas production grew modestly in 2013, despite a 35%
year-on-year rise in prices. Production grew from 65.7 billion cubic feet
per day (Bcf/d) in 2012 to 66.5 Bcf/d in 2013, a 1% increase and the lowest
annual growth since 2005. This production growth was essentially flat when
compared to the 5% growth in 2012 and the 7% growth in 2011.
Average wholesale (spot) prices for natural gas in 2013 increased significantly throughout the
United States compared to 2012. The average wholesale price for natural gas at
Henry Hub in Erath, Louisiana, a key benchmark location for pricing throughout
the United States, rose to $3.73 per million British thermal units (MMBtu) in
2013. However, 2013 prices were, with the exception of 2012, at their lowest level
since 2002.
Slower demand growth, low imports limit room for gas
production growth
Although prices remained relatively low, total disposition (consumption,
gross exports, and net storage injections) of natural gas was flat in 2013
compared with 2012 levels, versus the annual 3% increase in 2012, and the 4%
increase in 2011. Domestic consumption in 2013, which makes up 96% of total U.S.
natural gas disposition, increased by 2%, despite the decrease in consumption of natural gas for
electric generation (power burn) in 2013. Natural gas consumed for power
burn was 2.6 Bcf/d below 2012 levels as coal
regained some of its market share in response to higher natural gas prices,
compared with coal, and as cooler summer temperatures in 2013 reduced
total electric generation demand. Increased winter natural gas demand offset the
decline in power burn, leading to a net increase in consumption for the
year.
Since 2010, domestic production has satisfied 88% of U.S. natural gas
disposition, as natural gas imports to the United States have continued to
decline. As recently as 2007, the United States depended on imports for 16% of
its natural gas needs. Although U.S. production has displaced some natural gas
imports to the United States, imports continue, although as a marginal source of
supply, largely during cold weather and pipeline maintenance outages.
Storage injections provided another outlet for U.S. natural gas production
growth. The net withdrawal in working natural gas storage inventories in 2013
was significantly higher than 2012 because of large withdrawals in January and
December. High demand at the end of the year offset the effect of end-of-October
working gas inventories that had reached their third-highest level in the past 10 years.
By the end of December, inventories had declined to their seventh-highest level in the past 10
years. The net withdrawal in inventories in 2013 was 537 billion cubic feet
(Bcf), significantly greater than the net withdrawal of 49 Bcf in 2012. In 2011,
there was a net injection into working inventories of 351 Bcf.
Growth
in Marcellus Shale production offsets decreases in other basins
Greater levels of natural gas output in the
Marcellus Shale contributed to the net increase in national production
levels despite decreases in other basins. Dry natural gas production from
Marcellus rose by 61%, from a 2012 average of 6.5 Bcf/d to a 2013 average of
10.4 Bcf/d (Figure 2), according to U.S. Energy Information Administration (EIA)
calculations based on data from Drillinginfo.
Marcellus production alone
accounted for 75% of all production growth over the past
year in the six basins covered in EIA's recently released Drilling Productivity Report (DPR), which
highlights the latest regional trends in drilling, completion, and production
from gas- and oil-producing wells.
Despite a 21% decline from 2012 to 2013 in the total
rig count in the Marcellus, natural gas output per rig rose by 47%, according to the DPR. Production
gains have come largely from northeastern portions of the basin producing drier
natural gas, where output has benefitted from gathering line
and pipeline capacity expansions. However, infrastructure improvements have also
bolstered production in the wetter southwestern portions of the basin, which saw
increased drilling in
2013.
Outside of Marcellus, the shift toward liquids-rich production
continued in 2013
Wide differences in natural gas and oil prices affect the decisions that
upstream operators make about where and how to deploy capital. Although natural
gas prices remained at relatively low levels through the end of 2013, crude oil
prices remained mostly above $100/barrel (bbl), encouraging operators to target
regions with wetter gas and higher returns on investment.
The Haynesville Shale in Texas and Louisiana
and the Barnett Shale in Texas generally are
considered dry natural gas plays because of the low level of liquids in their
production streams. Production from the Haynesville and Barnett declined by 27%
and 9%, respectively, between 2013 and 2012. The Barnett and Haynesville
reductions exceeded the 3% combined increase in gas production at the Fayetteville Shale in Arkansas and the
nearby Woodford Shale in Oklahoma. The Baker
Hughes active rig count decreased significantly in all four of these basins
between 2011 and 2013. Some of the production declines in these fields are also
partially attributable to the normal decline or maturity of their existing
wells.
At the same time, increased new production activity in wetter shale basins
enabled these basins to pick up some of the drop-off in production from their
drier counterparts. At the Eagle Ford in south Texas, where operators target a combination of crude oil,
condensate, and natural gas liquids, average daily gas production reached
3.3 Bcf/d in 2013, 54% higher than in 2012. In 2012, the average active rig
count in Eagle Ford rose by 29% before declining slightly in 2013. Production
also grew by 33% in the Bakken Shale in North Dakota and Montana,
where operators predominantly target crude oil,
following a rig count increase in 2012.
The shift in new production activity from drier to wetter production fields
is demonstrated by data on Lower 48 gross withdrawals from wells producing only
natural gas, versus those producing a combination of gas and oil. While gross
withdrawals from wells containing only natural gas rose by 4% from 2011 to 2013,
from 40.4 Bcf/d to 42.1 Bcf/d, gross withdrawals from wells producing a
combination of both gas and oil increased by 7%, from 25.0 Bcf/d to 26.8 Bcf/d
(Figure 3), according to EIA calculations with data from Drillinginfo.
The increased gross withdrawals from wells producing both gas and oil
coincided with changes in the oil-to-natural gas price ratio. When the
oil-to-natural gas price ratio increased by 49% in 2012, from $28.33/bbl of
Brent crude oil in 2011 to $42.13/bbl of Brent crude oil for every $1.00/MMBtu
of natural gas, gross withdrawals from wells producing both gas and oil rose by
8%. When gas prices rose and the oil-to-gas price ratio decreased by 30% to
$29.61/bbl of Brent crude oil for every $1.00/MMBtu of natural gas in 2013,
gross withdrawals from wells producing both gas and oil decreased by 1%. The
shift in the focus of new natural gas production activity was also evident in
terms of the increase since 2010 in the percentage of new wells that produced
both natural gas and oil (Figure 4). In 2010, 57% of all new natural
gas-producing wells produced both gas and oil. By 2012, 73% of all new natural
gas producing wells produced both gas and oil. This share fell to 68% in
2013.
Other production
The shift in natural gas production also involved movement away from
geologically more permeable zones that have traditionally accounted for a
greater share of North American gas supply. Marketed natural gas production was
generally flat or down for inland production areas outside of shale and tight
formations in 2012 and 2013, except for New Mexico, and also remained relatively
flat in onshore Canada. Production from offshore areas in both Canada and the
United States declined between 2012 and 2013
