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

Natural Gas

‹ See the most recent Natural Gas Weekly Update

Natural Gas Weekly Update

for week ending January 31, 2018 | Release date: February 1, 2018 | Next release: February 8, 2018 | Previous weeks

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

In the News:

Proposed natural gas plant liquids pipeline from North Dakota supports increased production of natural gas in the Bakken

In January 2018, OneOK Inc. announced plans to build the Elk Creek Pipeline, a new 900-mile, 240,000 barrels per day (b/d) pipeline to transport Bakken natural gas plant liquids (NGPL) from eastern Montana to Bushton, Kansas. Bushton and nearby Conway, Kansas, serve as a mid-continent NGPL hub with significant infrastructure to store, fractionate, and pipe NGPL to the consuming regions of the Midwest or to the petrochemical and export facilities along the Gulf Coast. Once complete in 2019, the pipeline will allow for more natural gas production in the Bakken region, reduce natural gas flaring, and support higher recovery of high-value NGPL.

Natural gas production in the Bakken in North Dakota is experiencing a resurgence (after a period of slow to stagnant growth in 2015 and 2016) as a result of strong growth in crude oil production and higher output of natural gas per barrel of oil produced in 2017.

To accommodate rising natural gas production over the past decade and to remain compliant with North Dakota’s increasingly stringent restrictions on natural gas flaring, the industry significantly expanded natural gas processing capacity across the state. Gas processing capacity in the state has expanded from slightly less than 500 million cubic feet per day (MMcf/d) at the end of 2010 to more than 2 billion cubic feet per day (Bcf/d) at the end of 2016, according to the North Dakota Pipeline Authority. By 2019, capacity is expected to grow an additional 700 MMcf/d above the 2016 total.

The processing of raw natural gas yields not only dry pipeline-quality natural gas, which is then shipped on pipelines to consumers across the country, but also NGPL, which require their own dedicated infrastructure. Production of NGPL in the MN-WI-ND-SD refining district, where North Dakota natural gas plant production constitutes most of the output, has continued to increase, reaching 241,000 b/d in August 2017. Although a large part of this NGPL production finds its way to market by rail and truck, most is moved out by pipeline, which is the most efficient way to transport NGPL. Currently only two pipelines move NGPL out of North Dakota:

Pembina Pipeline Corporation’s Vantage Pipeline, which was expanded to 68,000 b/d in late 2016, ships nearly 40,000 b/d of ethane from North Dakota to Canada.
OneOK’s Bakken NGL Pipeline, in service since 2013 with a capacity of 135,000 b/d (expanding to 160,000 b/d later this year), moves mixed NGPL (Y-grade) south to Colorado, where it interconnects with the Overland Pass Pipeline flowing to Kansas. EIA’s statistics suggest flows on the Bakken NGL Pipeline, which closely correlate with reported NGPL pipeline movements from PADD 2 to PADD 4, are now at full capacity.

Capacity constraints on existing pipelines have hindered production of NGPL in North Dakota—and, indirectly, the processing of higher quantities of natural gas—resulting in increases in both natural gas flaring and the rejection of ethane into natural gas pipelines. Keeping ethane in the natural gas stream raises the heat content of pipeline gas. As a result, natural gas delivered to North Dakota consumers had the highest heat content in the country for the past four reported months. High natural gas heat content may result in improper function of natural-gas consuming equipment and impede natural gas pipeline operations. Expanded NGPL pipeline capacity, which will enable Bakken producers to increase natural gas production while reducing flaring, provides an outlet for NGPL that are in increasingly high demand, particularly on the Gulf Coast.

Overview:

(For the Week Ending Wednesday, January 31, 2018)

Natural gas spot prices fell at most locations this report week (Wednesday, January 24 to Wednesday, January 31). The Henry Hub spot price fell from $3.56 per million British thermal units (MMBtu) last Wednesday to $3.21/MMBtu yesterday.
At the New York Mercantile Exchange (Nymex), the February 2018 contract expired Monday at $3.631/MMBtu. The March 2018 contract price decreased to $2.995/MMBtu yesterday, down 9¢ Wednesday to Wednesday.
Net withdrawals from working gas totaled 99 billion cubic feet (Bcf) for the week ending January 26. Working natural gas stocks are 2,197 Bcf, which is 19% less than the year-ago level and 16% lower than the five-year (2013–17) average for this week.
The natural gas plant liquids composite price at Mont Belvieu, Texas, fell by 25¢, averaging $7.73/MMBtu for the week ending January 31. The price of ethane, propane, and butane fell by 1%, 7%, and 6%, respectively. The price of natural gasoline and isobutane both rose by 1%.
According to Baker Hughes, for the week ending Tuesday, January 23, the natural gas rig count decreased by 1 to 188. The number of oil-directed rigs rose by 12 to 759. The total rig count increased by 11, and it now stands at 947.

more summary data

Prices/Supply/Demand:

Spot prices fall around the country with generally warmer weather. This report week (Wednesday, January 24 to Wednesday, January 31), the Henry Hub spot price fell 35¢ from $3.56/MMBtu last Wednesday to $3.21/MMBtu yesterday, after reaching a high of $3.60/MMBtu on Tuesday. At the Chicago Citygate, prices decreased 16¢ from $3.27/MMBtu last Wednesday to $3.11/MMBtu yesterday. Prices at PG&E Citygate in Northern California fell 28¢, down from $3.02/MMBtu last Wednesday to $2.74/MMBtu yesterday. The price at SoCal Citygate decreased 72¢ from $3.48/MMBtu last Wednesday to $2.76/MMBtu yesterday, as temperatures warmed in Southern California.

Northeast prices exhibit volatility. At the Algonquin Citygate, which serves Boston-area consumers, prices were volatile amid shifting weather forecasts. Overall, prices went down $8.68 from $14.98/MMBtu last Wednesday to $6.30/MMBtu yesterday. However, prices fell as low as $4.68/MMBtu on Friday, then rose again to $14.48/MMBtu on Monday. At the Transcontinental Pipeline Zone 6 trading point for New York, prices decreased 59¢ from $5.12/MMBtu last Wednesday to $4.53/MMBtu yesterday. New York prices had a low of $3.50/MMBtu on Friday, followed by a high of $8.57/MMBtu on Monday.

Tennessee Zone 4 Marcellus spot prices increased 26¢ from $2.55/MMBtu last Wednesday to $2.81/MMBtu yesterday. Prices at Dominion South in northwest Pennsylvania rose 17¢ from $2.78/MMBtu last Wednesday to $2.95/MMBtu yesterday, with a high of $3.03/MMBtu on Monday.

February contract expires higher, while March contract falls. At the Nymex, the February 2018 contract expired Monday at $3.631/MMBtu, up 12¢ from last Wednesday. The Monday price was the highest for a front-month contract since December 30, 2016. The March 2018 contract decreased to $2.995/MMBtu, down 9¢ from last Wednesday to yesterday. The price of the 12-month strip averaging March 2018 through February 2019 futures contracts declined 1¢ to $2.972/MMBtu.

Supply rises. According to data from PointLogic Energy, the average total supply of natural gas rose by 1% compared with the previous report week. Dry natural gas production grew by 1% compared with last week, while average net imports from Canada decreased by 2% from last week.

On Wednesday, an explosion was reported on the Seneca Lateral pipeline near Summerfield, Ohio. Tallgrass Energy announced flows on the segment would be curtailed until repairs were completed. The Seneca Lateral, a part of Tallgrass Energy’s Rockies Express (REX) pipeline, transports natural gas produced from the Utica shale onto the REX system.

Demand remains flat. Total U.S. consumption of natural gas fell by 2% compared with the previous report week, according to data from PointLogic Energy. Natural gas consumed for power generation declined by 8% week over week. Industrial sector consumption decreased by 1% week over week. In the residential and commercial sectors, consumption remained at last week's level, averaging 37.8 Bcf/d. Exports to Mexico increased 3%, and deliveries to Sabine Pass liquefied natural gas (LNG) export terminal increased by 62%, week over week, largely as a result of the Sabine Pass facility returning to normal operations.

U.S. LNG exports increase week over week. After an unexpected shutdown of several trains at Sabine Pass in mid-January because of reported water supply problems, LNG loadings at the terminal increased last week, with five departed vessels (combined LNG-carrying capacity 18.4 Bcf), and two vessels (combined LNG-carrying capacity 7.6 Bcf) loading on Wednesday. The natural gas feedstock to the terminal averaged 3.2 Bcf/d during the report week, after decreasing to 2.0 Bcf/d (weekly average) in the prior week, and averaged 2.6 Bcf/d during January.

Two LNG cargoes from Nigeria and Trinidad were delivered to the Cove Point LNG facility in Maryland in December and January. The first cargo was reportedly sold into the local Mid-Atlantic market during a period of peak winter demand, while the second cargo will likely be used as a cool down cargo in the liquefaction commissioning process to test the terminal’s systems. Cove Point, the only liquefaction facility located on the East Coast of the United States, announced on January 31 that it has begun producing LNG, with the first LNG exports expected in early March.

more price data

Storage:

Working gas deficit to the five-year average declines by 61 Bcf. Net withdrawals from storage totaled 99 Bcf for the week ending January 26, compared with the five-year (2013–17) average net withdrawal of 160 Bcf and last year's net withdrawals of 92 Bcf during the same week. Working gas stocks totaled 2,197 Bcf, which is 425 Bcf less than the five-year average and 526 Bcf less than last year at this time.

Working gas stocks post net injections on the week in the South Central salt region. Net injections into working gas stocks in the South Central salt region totaled 18 Bcf. These net injections came a week after working gas stocks fell 55 Bcf to 151 Bcf—the lowest level reported since April 2015. This is the largest January net injection for the region on record, and it is the second-largest net injection over the period from December to February (working gas stocks posted a net injection of 19 Bcf for the week ending February 21, 2014). As in 2014, this week’s net injections followed a period of significant withdrawals from working gas. Warmer-than-average weather in the Gulf Coast region for the first part of the report week likely contributed to the net injections. The largest weekly injection ever reported in the region was 25 Bcf, which last occurred in October 2016.

The average March 2018 futures contract price is the same as the average weekly spot price. During the most recent storage week, the average natural gas spot price at the Henry Hub was $3.36/MMBtu, the same as the front-month futures price at the Nymex. A year ago, the spot price was 8¢ lower than the front-month contract.

Reported withdrawals out of storage are near the median of analysts’ expectations. According to the Desk survey of natural gas analysts, estimates of the weekly net change in working natural gas storage ranged from 87 Bcf to 119 Bcf, with a median of 102 Bcf. Prices for the futures contract for March delivery at the Henry Hub fell about 2¢/MMBtu, averaging $2.87/MMBtu, following the release of the Weekly Natural Gas Storage Report with 699 contracts traded at the release. Prices varied and remained close to this level in subsequent trading.

Temperatures are higher than normal during the storage week throughout most of the Lower 48 states. Temperatures in the Lower 48 states averaged 40 degrees Fahrenheit (°F), 7°F higher than normal, 4°F lower than last year at this time, and 10° warmer on average since last week.

more storage data

Spot Prices ($/MMBtu)	Thu, 25-Jan	Fri, 26-Jan	Mon, 29-Jan	Tue, 30-Jan	Wed, 31-Jan
Henry Hub	3.57	3.52	3.56	3.60	3.21
New York	3.66	3.50	8.57	5.33	4.53
Chicago	3.12	3.26	3.22	3.15	3.11
Cal. Comp. Avg,*	2.96	2.91	2.75	2.70	2.54
Futures ($/MMBtu)
February Contract	3.447	3.505	3.631	Expired	Expired
March Contract	3.099	3.175	3.167	3.195	2.995
April Contract	2.901	2.929	2.939	2.97	2.86
*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: (1/25/18 - 1/31/18)
	Average daily values (Bcf/d):
	this week	last week	last year
Marketed production	87.0	86.0	78.9
Dry production	77.5	76.7	70.4
Net Canada imports	5.9	6.0	6.0
LNG pipeline deliveries	0.2	0.3	0.2
Total supply	83.5	83.0	76.6
Source: OPIS PointLogic Energy, an IHS Company Note: LNG pipeline deliveries represent gas sendout from LNG import terminals.

U.S. natural gas consumption - Gas Week: (1/25/18 - 1/31/18)
	Average daily values (Bcf/d):
	this week	last week	last year
U.S. consumption	81.9	83.6	83.5
Power	21.4	23.2	22.1
Industrial	22.7	22.8	22.6
Residential/commercial	37.8	37.6	38.9
Mexico exports	4.4	4.3	4.0
Pipeline fuel use/losses	6.4	6.5	6.5
LNG pipeline receipts	3.2	2.0	1.9
Total demand	95.9	96.4	96.0
Source: OPIS PointLogic Energy, an IHS Company Note: LNG pipeline receipts represent pipeline deliveries to LNG export terminals.

Rigs
	Fri, January 26, 2018	Change from
	Fri, January 26, 2018	last week	last year
Oil rigs	759	1.6%	34.1%
Natural gas rigs	188	-0.5%	29.7%
Note: Excludes any miscellaneous rigs

Rig numbers by type
	Fri, January 26, 2018	Change from
	Fri, January 26, 2018	last week	last year
Vertical	66	15.8%	-8.3%
Horizontal	808	0.7%	39.6%
Directional	73	-5.2%	19.7%
Source: Baker Hughes Inc.

Working gas in underground storage
	Stocks billion cubic feet (Bcf)
Region	2018-01-26	2018-01-19	change
East	525	555	-30
Midwest	596	634	-38
Mountain	137	145	-8
Pacific	220	233	-13
South Central	719	729	-10
Total	2,197	2,296	-99
Source: U.S. Energy Information Administration

Working gas in underground storage
	Historical comparisons
	Year ago (1/26/17)		5-year average (2013-2017)
Region	Stocks (Bcf)	% change	Stocks (Bcf)	% change
East	573	-8.4	593	-11.5
Midwest	734	-18.8	682	-12.6
Mountain	165	-17.0	155	-11.6
Pacific	223	-1.3	251	-12.4
South Central	1,028	-30.1	941	-23.6
Total	2,723	-19.3	2,622	-16.2
Source: U.S. Energy Information Administration

Temperature – heating & cooling degree days (week ending Jan 25)
		HDD deviation from:			CDD deviation from:
Region	HDD Current	normal	last year	CDD Current	normal	last year
New England	222	-53	36	0	0	0
Middle Atlantic	205	-58	36	0	0	0
E N Central	211	-85	45	0	0	0
W N Central	217	-97	21	0	0	0
South Atlantic	137	-45	42	6	-2	-6
E S Central	150	-37	74	0	-1	0
W S Central	103	-34	48	2	-2	-5
Mountain	206	-23	-16	0	0	0
Pacific	122	4	-22	0	-1	0
United States	174	-50	27	1	-1	-2
Note: HDD = heating degree day; CDD = cooling degree day Source: National Oceanic and Atmospheric Administration