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

Natural Gas

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Natural Gas Weekly Update

for week ending October 21, 2015 | Release date: October 22, 2015 | Next release: October 29, 2015 | Previous weeks

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

In the News:

Increasing U.S. natural gas pipeline exports to Mexico begin to gradually displace LNG

Growing U.S. natural gas pipeline exports to Mexico are beginning to gradually displace Mexico's liquefied natural gas (LNG) imports, as new U.S. export capacity is brought online and connecting pipelines in Mexico are ramping up to full capacity. U.S. exports to Mexico set a monthly record high in July, averaging 3.3 billion cubic feet per day (Bcf/d), according to EIA data, and averaged 2.7 Bcf/d in the first seven months of this year, 35% higher than in the same period last year. In contrast, Mexico's LNG imports were 7% lower in the first seven months of 2015 as compared to the same period last year, according to data from Secretaría de Economía.

Before a significant growth in the U.S. shale production, Mexico considered LNG imports as a viable alternative to offset the declining domestic production and expected limited growth in pipeline imports from the United States. With the rise of U.S. shale production and a decline in natural gas prices in recent years, the need in Mexico for LNG imports decreased. As a result, LNG regasification terminals have been operating below capacity.

Currently Mexico has three regasification terminals, one on the east coast–Altamira, 0.7 Bcf/d capacity commissioned in 2006, and two on the west coast–Ensenada, also called Energia Costa Azul, 1.0 Bcf/d capacity, in operation since 2008, and Manzanillo, 0.5 Bcf/d capacity, commissioned in 2012. While utilization at the Manzanillo terminal has been relatively high, averaging 85% in 2013-14, the Altamira terminal was used around 50% in the same period, while the Costa Azul terminal in the Baja peninsula remains virtually unused.

LNG imports at the Manzanillo terminal provide natural gas for the gas-fired power plants in Mexico's Central West region. The location of the Manzanillo terminal provides a unique point of entry and serves to relieve pipeline bottlenecks in the region. As a result, LNG imports to the terminal are expected to remain high in the next few years, until additional pipeline capacity is developed to provide alternative sources.

Imports at the Energia Costa Azul terminal, on the other hand, have averaged 4% of the terminal's nameplate capacity since 2011, despite a long-term contract with the Tangguh liquefaction project in Indonesia. Originally, the terminal was constructed to supply the Southern California market and new power plants in Mexico's state of Baja California. However, these plants could also be supplied via U.S. pipelines. Therefore, the terminal depended mostly on natural gas demand in California, which was limited because of the availability of lower-cost U.S. supply sources. Because this terminal's contract allowed for diversion of supply volumes to other markets, most of contracted supply from Indonesia went to higher-priced Asian markets in the past several years. Due to low use, the terminal's operator, Sempra Energy, is considering a conversion of the terminal into a liquefaction facility.

LNG imports at the Altamira terminal have consistently averaged around 50% of the terminal's capacity in 2008-15. Terminal operators Shell and Total have a supply contract with Mexico's Comisión Federal de Electricidad (CFE), which allows them to supply CFE with either pipeline natural gas or LNG. However, the contract stipulates that at least 50% of the supply has to be provided as LNG. In the first six months of this year, imports to the Altamira terminal have declined by 14% compared with the same period last year, as increasingly available lower-priced pipeline gas from the United States displaced some of LNG imports into Altamira. In September, CFE canceled a tender for several spot cargoes into Altamira for a period between September and December, noting increased availability of less-expensive pipeline natural gas from the United States. The Manzanillo terminal may follow suit in the coming years as additional pipeline infrastructure becomes available in the region to alleviate the existing bottlenecks.

Overview:

(For the Week Ending Wednesday, October 21, 2015)

Natural gas prices fell at most market locations during the report week (Wednesday, October 14, to Wednesday, October 21). The Henry Hub spot price fell 8¢ from $2.44 per million British thermal units (MMBtu) last Wednesday to $2.36/MMBtu yesterday.
At the New York Mercantile Exchange, the price of the near-month (November 2014) futures contract fell by 11¢ from $2.518/MMBtu last Wednesday to $2.404/MMBtu yesterday.
Working natural gas in storage increased by 81 Bcf, rising to 3,814 Bcf as of Friday, October 16. The net injection into storage resulted in storage levels 13% above a year ago and 4% above the five-year average for this week.
The total rig count declined by 8 units to 787 as of Friday, October 16, according to data from Baker Hughes Incorporated. This is 1,131 units below the level at the same time last year. Oil rigs declined by 10 units to 595 (995 below last year's level), and natural gas rigs increased by 3 to 192 (136 below last year's level). The U.S. rig count has not been this low since May 2002.
The natural gas plant liquids composite price at Mont Belvieu decreased by 4.7% to $5.09/MMBtu for the week ending October 16. Natural gasoline, propane, butane, and isobutane prices dropped by 4.3%, 6.6%, 8.3%, and 5.2%, respectively, while ethane prices increased by 1.7%.

more summary data

Prices/Demand/Supply:

Price changes are down and small in most locations, with the exception of the Northeast. The Henry Hub spot price began the week at $2.44/MMBtu, fluctuated slightly through the report week, and then settled at $2.36/MMBtu yesterday. At the Chicago Citygate, prices fell 16¢, from $2.50/MMBtu to $2.34/MMBtu. While most of the Midwest prices had similar declines, prices at St. Clair, which represents gas delivered from the TransCanada PipeLines system into Michigan at St. Clair, rose by 11¢, likely because of colder Canadian temperatures. Price declines also occurred in the West. PG&E Citygate, serving Northern California, started the report week at $3.02/MMBtu and decreased 20¢ to close at $2.82/MMBtu yesterday.

Temperatures began the report week slightly above average for most of the nation, but by the weekend cooler temperatures started in the Great Lakes, and moved south and east. Friday brought temperatures of more than 10° below normal for the upper Midwest. This below-average cold remained in the East until Tuesday. Warmer temperatures at the end of the report week reduced overall daily consumption for the residential/commercial and power sectors.

Prices mixed in the Northeast. In the Northeast prices varied in response to temperatures and to maintenance, especially in New England where temperatures were as much as 13° below normal through the weekend, but returned to seasonal norms by Tuesday. Maintenance on the Burrillville compressor station (Rhode Island) began on Thursday, October 15, and limited mainline capacity to 630 MMcf/d, down from 800 MMcf/d. This maintenance will continue until Friday, October 23. Algonquin pipeline also posted constraints for gas quality problems at the Mendon, Massachusetts, interconnect with Tennessee Gas Pipeline that will restrict flow to 100 MMcf/d, down from normal capacity of approximately 275 MMcf/d. Both of these maintenance events placed upward pressure on Algonquin Citygate prices during this period.

Algonquin Citygate, which serves Boston-area consumers, opened at $2.83/MMBtu, rose to $4.81/MMBtu on Friday and again to $4.94/MMBtu on Monday, dropping to $2.82/MMBtu with warmer seasonal temperature to end the week yesterday. At Transcontinental Pipeline's Zone 6 trading point, which serves New York City, prices were less affected by temperature, opening Wednesday, October 14, at $2.38/MMBtu, rising to $2.44/MMBtu for the weekend (Friday), then settling down at $2.17/MMBtu yesterday.

Marcellus prices rise. Though still low, Marcellus prices rose through the report week by more than 20%. At Tennessee's Zone 4 Marcellus trading point, prices began at 89¢/MMBtu last Wednesday and rose to $1.19/MMBtu yesterday. Similarly, on Transco's Leidy Line prices rose from 98¢/MMBtu to $1.15/MMBtu Wednesday to Wednesday. At Dominion South, which serves customers in portions of Pennsylvania, Ohio, Maryland, West Virginia, and Virginia, prices began the report week at $1.18/MMBtu, fluctuated through the week to as high as $1.71/MMBtu on Monday, and closed yesterday at $1.60/MMBtu.

Nymex prices are down. The price of the near-month (November 2015) contract fell by 11¢ from $2.518/MMBtu last Wednesday to $2.404/MMBtu yesterday. The price of the 12-month strip (the average of the 12 contracts between November 2015 and October 2016) fell 10¢ from $2.782/MMBtu last Wednesday to $2.685/MMBtu yesterday, likely because of above-normal fall temperature forecasts.

Supply decreases. Total supply fell again this week by 0.1%, with a 0.2% decrease in dry production leading the decline, according to data from Bentek Energy. The decrease in Appalachian Basin production, which accounted for most of the decrease, was largely attributed to maintenance activity on Tennessee Gas Pipeline and Transco pipeline at several gathering lines and production points, including the Latini Dehy and Liberty Dehydration stations in Pennsylvania, which concluded yesterday. Although dry production declined, it is still 2.4% greater than the year-ago level. Imports from Canada rose by 4.1% week-over-week. Sendout of LNG increased by 3.3% over last week, but still remains at minimal levels.

Consumption increases slightly. Week-over-week consumption rose by 5.3%. Residential/commercial and industrial consumption rose this report period by 29.8% and 2.3%, respectively, while consumption of natural gas for power generation (power burn) fell 6.7%. Exports to Mexico fell for the week, down 3%, but remain higher than 2014 levels, up 56% over this time last year.

more price data

Storage

Storage level is equal to five-year maximum. With a net injection reported for the week ending October 16 of 81 Bcf, inventories rose to 3,814 Bcf, equal to the record storage level for the week reached in 2012. This injection compares with the five-year average increase of 86 Bcf for the week and last year's increase of 94 Bcf. Working gas inventories for the report week were 434 Bcf (13%) higher than last year at this time and 163 Bcf (4%) higher than the five-year (2010-14) average.

Storage injections are smaller than market expectations. Market expectations, on average, called for a build of 88 Bcf for this week. When the EIA storage report was released at 10:30 a.m. on October 22, the November Nymex price rose about 2¢, to $2.43/MMBtu, but fell back down to around $2.37/MMBtu in the following hour.

From April 3 (the beginning of the injection season) through October 16, net storage injections totaled 2,353 Bcf, or 194 Bcf lower than the 2,547 Bcf injected during the same 29 weeks in 2014. During these weeks for the years 2010-14, net injections into storage averaged 2,000 Bcf. The estimated average unit value of the natural gas put into storage from April 3 to October 16 this year is $2.71/MMBtu, 36% lower than the average value of $4.24/MMBtu for the same 29 weeks last year. The highest winter-month Nymex price (for the January 2016 contract) in trading for the week ending October 16 averaged $2.83/MMBtu. This price is 37¢/MMBtu more than the November Nymex contract price. A year ago, the difference was 29¢/MMBtu.

Temperatures during the storage report week are warmer than normal. Temperatures in the Lower 48 states averaged 63° for the storage report week, 5° warmer than the 30-year normal temperature and 3° warmer than the average temperature during the same week last year. There were 37 population-weighted heating degree days (HDD) during this report week, 7 HDD fewer than the five-year average and 14 HDD fewer than during the same period last year. There were also 24 population-weighted cooling degree days (CDD) this report week, 9 CDD more than the five-year average and 4 CDD more than this week last year.

more storage data

Spot Prices ($/MMBtu)	Thu, 15-Oct	Fri, 16-Oct	Mon, 19-Oct	Tue, 20-Oct	Wed, 21-Oct
Henry Hub	2.49	2.38	2.42	2.45	2.36
New York	2.34	2.44	2.42	2.29	2.17
Chicago	2.55	2.42	2.43	2.44	2.34
Cal. Comp. Avg,*	2.71	2.55	2.57	2.54	2.43
Futures ($/MMBtu)
November contract	2.453	2.430	2.442	2.476	2.404
December contract	2.686	2.650	2.657	2.671	2.603
*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: (10/14/15 - 10/21/15)
	Percent change for week compared with:
	last year	last week
Gross production	2.43%	-0.12%
Dry production	2.41%	-0.15%
Canadian imports	-2.17%	4.07%
West (net)	1.34%	-6.08%
Midwest (net)	-21.27%	-7.15%
Northeast (net)	N/A	N/A
LNG imports	80.56%	3.29%
Total supply	2.14%	0.14%
Source: BENTEK Energy LLC

U.S. consumption - Gas Week: (10/14/15 - 10/21/15)
	Percent change for week compared with:
	last year	last week
U.S. consumption	8.2%	5.3%
Power	14.4%	-6.7%
Industrial	-1.1%	2.3%
Residential/commercial	10.9%	29.8%
Total demand	9.6%	5.0%
Source: BENTEK Energy LLC

Rigs
	Fri, October 16, 2015	Change from
	Fri, October 16, 2015	last week	last year
Oil rigs	595	-1.65%	-62.58%
Natural gas rigs	192	1.59%	-41.46%
Miscellaneous	0	-100.00%	0.00%

Rig numbers by type
	Fri, October 16, 2015	Change from
	Fri, October 16, 2015	last week	last year
Vertical	110	-3.51%	-69.61%
Horizontal	591	-1.17%	-56.32%
Directional	86	3.61%	-57.64%
Source: Baker Hughes Inc.

Working gas in underground storage
	Stocks billion cubic feet (bcf)
Region	2015-10-16	2015-10-09	change
East	1,961	1,912	49
West	524	521	3
Producing	1,329	1,300	29
Total	3,814	3,733	81
Source: U.S. Energy Information Administration

Working gas in underground storage
	Historical comparisons
	Year ago (10/16/14)		5-year average (2010-2014)
Region	Stocks (Bcf)	% change	Stocks (Bcf)	% change
East	1,865	5.1	1,973	-0.6
West	481	8.9	512	2.3
Producing	1,033	28.7	1,166	14.0
Total	3,380	12.8	3,651	4.5
Source: U.S. Energy Information Administration

Temperature -- heating & cooling degree days (week ending Oct 15)
		HDD deviation from:			CDD deviation from:
Region	HDD Current	normal	last year	CDD Current	normal	last year
New England	69	-24	-12	0	0	-3
Middle Atlantic	56	-25	-7	0	-1	-3
E N Central	62	-23	-24	0	-2	-1
W N Central	54	-28	-43	2	-1	2
South Atlantic	28	-15	6	30	0	-16
E S Central	25	-17	4	12	-2	-14
W S Central	3	-11	-11	65	31	16
Mountain	29	-52	-32	31	17	16
Pacific	6	-23	-2	56	46	37
United States	37	-24	-14	24	10	4
Note: HDD = heating degree-day; CDD = cooling degree-day Source: National Oceanic and Atmospheric Administration