U.S. Energy Information Administration - EIA - Independent Statistics and Analysis

Natural Gas

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Natural Gas Weekly Update

for week ending June 25, 2014 | Release date: June 26, 2014 | Next release: July 3, 2014 | Previous weeks

JUMP TO: In The News | Overview | Prices/Supply/Demand | Storage

In the News:

Natural gas production grows in three major tight oil production areas

Despite a decline of 11% in the gas-directed rig count over the past year, natural gas production has grown 5%, due in part to growing gas production in tight oil production areas. Over the past year, the number of gas-directed rigs fell by 38, while the number of oil-directed rigs rose by 140, according to data released by Baker Hughes last Friday.

Since 2011, natural gas production has been increasing in three growing tight oil production regions: the Eagle Ford, Permian Basin, and Bakken. According to EIA's June Drilling Productivity Report (DPR), natural gas production in these three tight oil areas grew from an average 7.4 billion cubic feet per day (Bcf/d) in 2011 to an estimated 13.9 Bcf/d in June 2014. That is an increase of 88%, 6.5 Bcf/d. These three tight oil regions accounted for an increasing share of total U.S. natural gas production, rising from 11% in 2011 to 19% in June 2014.

The DPR reports oil and natural gas volumes for six regions in the United States. These six regions accounted for 95% of domestic oil production growth and all domestic natural gas production growth during 2011 through 2013. DPR reports gross natural gas wellhead flows that include gas that may be flared or vented after it leaves the wellhead, especially in the Bakken.

Significant volumes of natural gas — called associated gas — are produced in conjunction with tight oil. Natural gas's volume expands in the reservoir as pressure declines, thereby providing the reservoir-drive that pushes the oil to the production wellbore. Without any natural gas in the reservoir, the oil will not move to the well. On a barrel-of-oil-equivalent basis, gas can constitute as little as 10% to 15%, or as much as 50% of the total hydrocarbons produced by a tight oil well.

The Eagle Ford region has posted the greatest increase in natural gas production growth, rising 259% from 2.7 Bcf/d in 2011 to an estimated 7.0 Bcf/d in June 2014 for an incremental increase of 4.3 Bcf/d. The Eagle Ford's gas production growth can partly be attributed to the high gas-oil ratio that recently leveled out at about 5,000 cubic feet per barrel (cf/b) of oil produced.

In 2007–10, the Eagle Ford gas-oil ratio averaged about 30,000 cf/b, when most of the drilling activity in that region was directed toward gas production. When oil became much more valuable than gas on a Btu basis during 2010-12, Eagle Ford drilling increasingly switched to oil. On June 20, Baker Hughes reported that 98% of the 215 Eagle Ford rigs were oil-directed.

Bakken gas production tripled from 0.4 Bcf/d in 2011 to an estimated 1.2 Bcf/d in June, for an incremental increase of about 0.8 Bcf/d. Bakken natural gas production has not increased as much as the Eagle Ford's during the 2011 through June 2014 period, largely because of the relatively low Bakken gas-oil ratio, which has averaged about 1,050 cf/b during that period. Unlike the Eagle Ford region, drilling in the Bakken has been almost exclusively oil-directed. On June 20, Baker Hughes reported that all 175 Bakken rigs were oil-directed.

Permian Basin gas production increased 33% from 4.2 Bcf/d in 2011 to an estimated 5.6 Bcf/d in June 2014 for an incremental increase of 1.4 Bcf/d. The Permian Basin has been experiencing a changing mix in the relative proportions of conventional and tight oil production. Permian Basin tight oil production currently accounts for 60% of the basin's total oil production, having risen from 35% at the beginning of 2011. Permian Basin oil production has a relatively high gas-oil ratio, with the June 2014 ratio estimated at 3,600 cf/b of oil produced. Like the Bakken Basin, Permian drilling has been almost exclusively oil-directed since early 2011. On June 20, Baker Hughes reported that 99% of the 553 Permian rigs were oil-directed.

Overview:

(For the Week Ending Wednesday, June 25, 2014)

Natural gas prices posted an overall decline during the report week (Wednesday, June 18— Wednesday, June 25). The Henry Hub spot price fell 13 cents per million British thermal units (MMBtu).
At the New York Mercantile Exchange (Nymex) the price of the front-month (July 2014) contract fell from $4.659/MMBtu last Wednesday to $4.553/MMBtu yesterday. The price of the 12-month strip fell from $4.579/MMBtu last Wednesday to $4.476/MMBtu yesterday.
Working natural gas in storage rose to 1,829 Bcf as of Friday, June 20, according to the U.S. Energy Information Administration (EIA) Weekly Natural Gas Storage Report (WNGSR). A net increase in storage of 110 Bcf for the week resulted in storage levels 27.4% below year-ago levels and 31.0% below the 5-year average.
The Baker Hughes rotary rig count totaled 1,858 as of June 20, up 4 units from the previous week. The number of active gas-directed rigs increased by 1 to 311, while oil rigs increased by 3 to 1,545. The oil-directed rig count is currently 140 units greater than its year-ago level, while the gas rig count is 38 units fewer than last year's level.
The Mont Belvieu natural gas plant liquids composite price increased 32 cents to $10.16/MMBtu for the week covering June 16 to June 20. The spot prices of propane, butane, and isobutane increased by 4.7%, 4.0%, and 4.7%, respectively. The spot prices of natural gasoline and ethane also rose this week, by 2.0% and 0.5%, respectively.

more summary data

Prices/Demand/Supply:

Prices decline moderately at most locations. Outside of the Northeast, prices were almost universally lower, ending the report week 14 cents/MMBtu on average below last Wednesday. The Henry Hub spot price was down 13 cents/MMBtu, from $4.70/MMBtu last Wednesday to $4.57/MMBtu this Wednesday.

In the Northeast, price movements were more diverse. At the Algonquin Citygate, which serves Boston-area consumers, prices began the report week at $5.64/MMBtu, a 94-cent/MMBtu premium to the Henry Hub price. On Friday prices fell to $2.83/MMBtu, $1.68/MMBtu below the Henry Hub price, and prices ended the week at $4.23/MMBtu, $1.41/MMBtu lower than last Wednesday. At Transcontinental (Transco) Pipeline's Zone 6 trading point for New York City delivery, prices gained 52 cents/MMBtu over the report week, increasing from $3.56/MMBtu last Wednesday to $4.08/MMBtu yesterday. Since the end of winter, Transco Zone 6 prices have traded at a strong discount to the Henry Hub. Since mid-May, prices at that location have generally traded more than $1/MMBtu below the Henry Hub. This week the discount to Henry Hub ranged from more than $2/MMBtu on Friday to 49 cents/MMBtu yesterday.

Nymex declines this week. The price of the Nymex near-month contract dropped this week from $4.659/MMBtu last Wednesday to $4.553/MMBtu yesterday. The price of the 12-month strip (the 12 contracts between July 2014 and June 2015) fell by 10.3 cents/MMBtu, from $4.579/MMBtu last Wednesday to $4.476 yesterday.

Supply and demand both increase this week. Dry natural gas production increased by 0.3 Bcf/d, or 0.5%, from the previous week, to 68.3 Bcf/d. Dry production hit a record high on Saturday of 68.5 Bcf, according to data from Bentek Energy. Imports from Canada increased 3.2% from last week, with a large decrease in the Northeast only partially offsetting increases in the West and Midwest. U.S. consumption rose 1.8%, driven by increases in the industrial and power sector.

more price data

Storage

Storage increases by triple digits for seventh straight week. The net injection reported for the week ending June 20 was 110 Bcf, 29 Bcf larger than the 5-year average net injection of 81 Bcf and 16 Bcf larger than last year's net injection of 94 Bcf. Working gas inventories totaled 1,829 Bcf, 690 Bcf (27.4%) less than last year at this time, and 822 Bcf (31.0%) below the 5-year (2009-13) average.

Storage build is larger than market expectations. Market expectations called for a build of 104 Bcf. When the EIA storage report was released at 10:30 a.m., the price for the July natural gas futures contract fell 7 cents to $4.48/MMBtu on the Nymex.

From the week ending on April 4 to the week ending on June 20, net storage injections have totaled 1,007 Bcf, versus 819 Bcf for the same 12 weeks in 2013, and 837 Bcf for these weeks between 2009 and 2013, on average. The average unit value of what storage holders put into storage from April 4 to June 20 was $4.61/MMBtu, 15% higher than the average value for the same 12 weeks last year of $4.02/MMBtu. The highest winter-month Nymex price (for the January 2015 contract) in trading for the week ending on June 20 averaged $4.83/MMBtu. This was 16 cents more than the current Nymex July contract price. A year ago, the difference was 26 cents/MMBtu.

There are currently 19 more weeks in the injection season, which traditionally occurs April 1 through October 31, although, in many years, injections continue into November. EIA forecasts that the end-of-October working natural gas inventory level will be 3,424 Bcf, which, as of June 20, would require an average injection of 84 Bcf per week through the end of October. EIA's forecast for the end-of-October inventory levels are below the 5-year (2009-13) average value of 3,837 Bcf. To reach the 5-year average by October 31, average weekly injections through the end of October would need to be 106 Bcf.

All three regions post larger-than-average builds. The East, West, and Producing regions had net injections of 68 Bcf (15 Bcf larger than its 5-year average injection), 17 Bcf (4 Bcf larger than its 5-year average injection), and 25 Bcf (10 Bcf larger than its 5-year average injection), respectively. Currently, storage levels for all three regions remain below their year-ago and 5-year average levels.

Temperatures during the storage report week were warmer than normal. Temperatures in the Lower 48 states averaged 72.0 degrees for the week, 1.1 degrees warmer than the 30-year normal temperature and 0.6 degree warmer than during the same period last year.

more storage data

Spot Prices ($/MMBtu)	Thu, 19-Jun	Fri, 20-Jun	Mon, 23-Jun	Tue, 24-Jun	Wed, 25-Jun
Henry Hub	4.64	4.51	4.48	4.49	4.57
New York	2.92	2.40	2.90	3.75	4.08
Chicago	4.75	4.59	4.55	4.57	4.66
Cal. Comp. Avg,*	4.86	4.72	4.73	4.76	4.82
Futures ($/MMBtu)
July Contract	4.584	4.531	4.446	4.535	4.553
August Contract	4.603	4.552	4.468	4.556	4.603
*Avg. of NGI's reported prices for: Malin, PG&E citygate, and Southern California Border Avg.
Source: NGI's Daily Gas Price Index

U.S. Natural Gas Supply - Gas Week: (6/18/14 - 6/25/14)
	Percent change for week compared with:
	last year	last week
Gross Production	5.79%	0.51%
Dry Production	5.73%	0.51%
Canadian Imports	-8.57%	3.23%
West (Net)	-18.94%	2.83%
MidWest (Net)	2.13%	8.91%
Northeast (Net)	-2.71%	-34.63%
LNG Imports	-69.25%	6.29%
Total Supply	4.31%	0.69%
Source: BENTEK Energy LLC

U.S. Consumption - Gas Week: (6/18/14 - 6/25/14)
	Percent change for week compared with:
	last year	last week
U.S. Consumption	-0.2%	1.8%
Power	-3.6%	6.7%
Industrial	2.3%	0.7%
Residential/Commercial	4.2%	-6.3%
Total Demand	0.7%	1.8%
Source: BENTEK Energy LLC

Rigs
	Fri, June 20, 2014	Change from
	Fri, June 20, 2014	last week	last year
Oil Rigs	1,545	0.19%	9.96%
Natural Gas Rigs	311	0.32%	-10.89%
Miscellaneous	2	0.00%	-60.00%

Rig Numbers by Type
	Fri, June 20, 2014	Change from
	Fri, June 20, 2014	last week	last year
Vertical	380	-2.06%	-13.24%
Horizontal	1,250	0.16%	15.85%
Directional	228	4.59%	-5.79%
Source: Baker Hughes Inc.

Working Gas in Underground Storage
	Stocks billion cubic feet (bcf)
Region	2014-06-20	2014-06-13	change
East	858	790	68
West	315	298	17
Producing	656	631	25
Total	1,829	1,719	110
Source: U.S. Energy Information Administration

Working Gas in Underground Storage
	Historical Comparisons
	Year ago (6/20/13)		5-year average (2009-2013)
Region	Stocks (Bcf)	% change	Stocks (Bcf)	% change
East	1,135	-24.4	1,240	-30.8
West	431	-26.9	415	-24.1
Producing	954	-31.2	996	-34.1
Total	2,519	-27.4	2,651	-31.0
Source: U.S. Energy Information Administration

Temperature -- Heating & Cooling Degree Days (week ending Jun 19)
		HDD deviation from:			CDD deviation from:
Region	HDD Current	normal	last year	CDD Current	normal	last year
New England	6	-5	-12	22	8	16
Middle Atlantic	3	-4	-5	38	11	19
E N Central	10	0	0	44	9	17
W N Central	9	0	6	47	1	-3
South Atlantic	0	-1	0	90	14	7
E S Central	0	0	0	81	10	3
W S Central	0	0	0	114	11	-5
Mountain	20	-1	16	48	-6	-20
Pacific	9	-6	3	11	-12	-6
United States	7	-2	1	56	6	5
Note: HDD = heating degree-day; CDD = cooling degree-day Source: National Oceanic and Atmospheric Administration