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

Natural Gas

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Natural Gas Weekly Update

for week ending April 1, 2015 | Release date: April 2, 2015 | Next release: April 9, 2015 | Previous weeks

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

In the News:

Pipeline infrastructure key to delivering U.S.-sourced natural gas to meet Mexico’s expanding needs

On March 26, U.S. based investment companies BlackRock and First Reserve announced that they contracted with PMI, a wholly owned subsidiary of Petroleos Mexicanos (Pemex), to acquire 45% equity interest in two natural gas pipelines: Los Ramones Phase II North and Los Ramones Phase II South. This deal will mark the first major Pemex-sponsored midstream assets to be built in partnership with foreign capital since the 2013 approval of Mexico’s Constitutional Energy Reform.

Since 2010, the United States has increased natural gas exports to Mexico. Between 2010 and 2014, exports from the United States to Mexico doubled to nearly 2.0 billion cubic feet per day (Bcf/d). EIA expects exports to Mexico, particularly from the Eagle Ford Shale in South Texas, to increase because of growing demand from Mexico’s electric power sector, coupled with flat, if not declining, Mexican natural gas production. Mexico’s energy ministry, Secretaria de Energia (Sener) projects that U.S. exports to Mexico could reach 3.8 Bcf/d by 2018.

Before 2013, the natural gas exported from the United States largely fed markets in northern Mexico, particularly near the border. Limitations to Mexico’s internal natural gas pipeline infrastructure have not allowed much, if any, gas to move between major regions in Mexico. With growing demand for natural gas in the country, and level-to-falling natural gas production, major demand centers in southern Mexico have had to rely on increasing volumes of liquefied natural gas (LNG) imports, which are relatively expensive compared to U.S. supply. Recent energy reforms have allowed natural gas transmission pipelines to be built, owned, and operated by private companies in Mexico. Much of the pipeline capacity is aimed at improving both internal and cross-border flow of natural gas to Mexico’s markets.

The Los Ramones natural gas pipeline is one of the larger pipeline projects to move gas farther into Mexico. Phase I of the project, which went into limited service in 2014, will have the capacity to deliver 2.1 Bcf/d of natural gas from the Eagle Ford Shale in Texas to northeastern Mexico when the entire project is complete. The pipeline is 70 miles long and is operated by Sempra Energy’s Mexican Subsidiary IEnova. Phase II of the project will link to Phase I, and will move the gas farther south into Mexico, providing an additional capacity of 1.4 Bcf/d to Mexico’s central zone, more than 600 miles from the border. Phase II of the project is scheduled to begin commercial service in mid-2016.

There are several other pipeline projects that have recently been completed or are underway to enhance the natural gas infrastructure in Mexico. These include:

TransCanada’s 146-mile extension to its Tamazunchale pipeline: Brought online in November 2014, this adds 0.6 Bcf/d of capacity to move natural gas supplies from the existing Gulf Coast pipeline and the Altamira LNG terminal farther south to interior markets north of Mexico City.

TransCanada’s El Oro-Mazatlan pipeline and El Encino-Topolobampo pipelines: These pipelines, with respective capacities of 0.2 Bcf/d and 0.7 Bcf/d, will stretch nearly a combined 600 miles, and will move U.S. natural gas to markets along the Pacific Coast of Mexico. Both of these pipelines have an anticipated in-service date of 2016, and will connect to existing pipelines along the Gulf of California and reach north to the Sierrita Pipeline, originating in Arizona, when construction is completed.

Overview:

(For the Week Ending Wednesday, April 1, 2015)

Natural gas prices decreased at most trading locations over the report week (Wednesday, March 25, to Wednesday, April 1). Although seasonably cooler temperatures moved in to parts of the country over the weekend, overall weather remained mild enough to keep the heating demand low. The Henry Hub spot price continued its decline during the report week from $2.74/MMBtu last Wednesday to $2.60/MMBtu yesterday.
At the New York Mercantile Exchange (Nymex), the April contract moved out of the near-month position on Friday, settling at $2.590/MMBtu. The Nymex May contract, which became the near-month contract on Monday, opened the report week at $2.740/MMBtu last Wednesday and settled yesterday at $2.605/MMBtu. The 12-month strip (the 12 contracts between May 2015 and April 2016) fell from $2.991/MMBtu last Wednesday to $2.883/MMBtu yesterday.
Working natural gas in storage decreased to 1,461 Bcf as of Friday, March 27, according to the U.S. Energy Information Administration (EIA) Weekly Natural Gas Storage Report (WNGSR). A net withdrawal from storage of 18 Bcf for the week resulted in storage levels 75.4% above year-ago levels and 11.5% below the five-year average for this week.
The total U.S. rig count continued to decline this week, dropping 21 units to 1,048 active rigs, 761 units below the year-ago count, according to data reported by Baker Hughes Inc. The natural gas rig count fell by 9 units to 233, while the oil rig count fell by 12 units to 813. Two miscellaneous units remained in service.
The natural gas plant liquids composite price rose 1.9%, a 10¢ increase for the week ending March 27, from $5.22/MMBtu to $5.32/MMBtu from Friday to Friday. With the exception of ethane and propane, which fell by 1.2% and 0.7% respectively, all other Mont Belvieu NGL spot prices rose this week, with natural gasoline rising 7.9%, butane up 1.3%, and isobutane up 1.6%.

more summary data

Prices/Demand/Supply:

Prices decrease on mild weather and reduced demand. Natural gas prices decreased on average by 5% in all markets except the Northeast, where several Marcellus trading locations posted gains. The Henry Hub spot price decreased from $2.74/MMBtu last Wednesday to $2.60/MMBtu yesterday. Moderate temperatures in the western half of the United States kept prices stable, with modest declines of 9¢-16¢/MMBtu in California and Arizona. Similarly, Midwest and Midcontinent prices decreased by 12¢-18¢/MMBtu, with regional averages closing the week at $2.72/MMBtu and $2.38/MMBtu, respectively. Prices in the Rocky Mountains declined slightly, by 5% on average, to close the week at $2.25/MMBtu at the Opal and Kern River markets in Wyoming.

New England prices are volatile on mixed weather. In New England, prices were volatile during the report week with a cold front moving in last weekend and the return of more seasonal temperatures at the end of the report week. The spot price at the Algonquin Citygate, which serves Boston consumers, almost tripled from $3.19/MMBtu on Wednesday to $8.94/MMBtu by Friday and continued to climb to $9.24/MMBtu on Monday, before falling to $3.00/MMBtu yesterday as temperatures moderated. Similarly, at the Tennessee Zone 6 200 line, serving Massachusetts, New Hampshire, and Rhode Island, prices reached $7.85/MMBtu on Friday, before falling back to $2.96/MMBtu yesterday, 11¢ lower than last Wednesday.

Prices in New York were also affected by changes in the temperatures, but to a more moderate degree. At Transcontinental Pipeline Zone 6, the trading point for New York City, prices began the week at $2.54/MMBtu, rising to $2.67/MMBtu by Friday, climbing further to $2.77/MMBtu on Tuesday, then falling to $2.36/MMBtu yesterday.

Marcellus-area prices strengthen, but remain low. The largest increase in the Marcellus area occurred on Tennessee's Zone 4 Marcellus location and Transcontinental's Leidy Line, where prices increased 39¢ to $1.61/MMBtu and 41¢ to $1.72/MMBtu, respectively, over the report week. At Dominion's South trading point, which serves customers in portions of Pennsylvania, Ohio, Maryland, West Virginia, and Virginia, prices increased by 11¢/MMBtu, from $1.59/MMBtu last Wednesday to $1.70/MMBtu yesterday.

Nymex prices mixed. The Nymex April contract moved out of the near-month position on Friday, settling at $2.590/MMBtu. The Nymex May contract, which became the near-month contract on Monday, opened the report week at $2.740/MMBtu last Wednesday and settled yesterday at $2.605/MMBtu. The 12-month strip (the 12 contracts between May 2015 and April 2016) fell from $2.991/MMBtu last Wednesday to $2.883/MMBtu yesterday.

Supply declines week-over-week, but dry gas production hits a 2015 record. Total natural gas supply declined 0.2% from last week. While imports from Canada decreased, dry-gas production increased 0.1% from last week, and is 8.4% higher than the same week last year. Dry production reached 73.3 Bcf/d on Monday, the highest level this year, and only 0.2 Bcf/d lower than the record of 73.5 Bcf/d set on December 20, 2014, according to Bentek data. Dry production averaged 72.0 Bcf/d during the first quarter of 2015, 8.9% higher than the same period in 2014. Total natural gas imported from Canada declined 3.3% from the previous week, as overall temperatures this week were milder and demand fell. However, regional imports were mixed, with imports into the West and Northeast declining by 3% and 41%, respectively, while imports into the Midwest rose by 38%. LNG sendout remained at minimal levels.

Consumption declines in all sectors. Consumption declined in all sectors, led by the decline in residential and commercial demand. Total domestic consumption fell 4.3% week over week, but was 2.7% higher than the same week last year. Residential and commercial consumption fell 8% (2.6 Bcf/d) from last week on reduced heating demand. Consumption of gas for electric power generation fell 1.6%, led by the declines in the Northeast, Midwest, Southeast, and Pacific Northwest. Industrial consumption declined 1.2%.

more price data

Storage

Net withdrawal is lower than both the five-year average and last year’s withdrawal. The net withdrawal reported for the week ending March 27 was 18 Bcf, 4 Bcf lower than the five-year average net withdrawal for that week, and 53 Bcf lower than last year’s net withdrawal. Working gas inventories for last week totaled 1,461 Bcf, 628 Bcf (75.4%) higher than last year at this time and 190 Bcf (11.5%) lower than the five-year (2010-14) average.

Storage withdrawals are larger than market expectations. Market expectations, on average, called for a pull of 11 Bcf. With the larger-than-expected withdrawal, when the EIA storage report was released at 10:30 a.m. on April 2, the price for the May natural gas futures contract increased 4¢ to around $2.67/MMBtu in trading on the Nymex. In the next hour, prices increased further to around $2.70/MMBtu.

The West and Producing regions report net injections for the week. Both the West and Producing regions had net injections of 4 Bcf (compared with its five-year average withdrawal of 1 Bcf) and 15 Bcf (14 Bcf greater than its five-year average net injection), respectively. The East region had a net withdrawal of 37 Bcf (15 Bcf greater than its five-year average net withdrawal). The East and Producing regions’ inventories are below their five-year averages by 173 Bcf (24.9%) and 95 Bcf (13.8%), respectively. The West region is the only region above its five-year average, with stocks up 29%. Storage levels for the East, West, and Producing regions are above their year-ago levels by 205 Bcf, 187 Bcf, and 236 Bcf, respectively.

Temperatures during the storage report week are close to normal. Temperatures in the Lower 48 states averaged 47.1° for the storage report week, 0.4° warmer than the 30-year normal temperature and 5.3° warmer than the average temperature during the same week last year. There were 131 population-weighted heating degree days during the storage report week, 14 higher than the five-year average and 34 fewer than during the same period last year.

more storage data

Spot Prices ($/MMBtu)	Thu, 26-Mar	Fri, 27-Mar	Mon, 30-Mar	Tue, 31-Mar	Wed, 1-Apr
Henry Hub	2.73	2.63	2.61	2.62	2.60
New York	2.70	2.67	2.66	2.77	2.36
Chicago	2.75	2.63	2.59	2.66	2.59
Cal. Comp. Avg,*	2.59	2.49	2.50	2.53	2.50
Futures ($/MMBtu)
April Contract	2.672	2.590	Closed	Closed	Closed
May Contract	2.688	2.639	2.644	2.640	2.605
June Contract	2.736	2.688	2.694	2.691	2.654
*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: (3/25/15 - 4/1/15)
	Percent change for week compared with:
	last year	last week
Gross production	8.50%	0.14%
Dry production	8.42%	0.14%
Canadian imports	32.00%	-3.33%
West (net)	61.98%	-2.56%
Midwest (net)	0.29%	38.35%
Northeast (net)	22.07%	-40.47%
LNG imports	-67.99%	-53.71%
Total supply	9.55%	-0.16%
Source: BENTEK Energy LLC

U.S. consumption - Gas Week: (3/25/15 - 4/1/15)
	Percent change for week compared with:
	last year	last week
U.S. consumption	2.7%	-4.3%
Power	23.2%	-1.6%
Industrial	-3.7%	-1.2%
Residential/commercial	-4.2%	-8.0%
Total demand	3.0%	-4.1%
Source: BENTEK Energy LLC

Rigs
	Fri, March 27, 2015	Change from
	Fri, March 27, 2015	last week	last year
Oil rigs	813	-1.45%	-45.33%
Natural gas rigs	233	-3.72%	-26.73%
Miscellaneous	2	0.00%	-50.00%

Rig numbers by type
	Fri, March 27, 2015	Change from
	Fri, March 27, 2015	last week	last year
Vertical	144	-2.70%	-62.50%
Horizontal	812	-2.05%	-32.95%
Directional	92	0.00%	-57.01%
Source: Baker Hughes Inc.

Working gas in underground storage
	Stocks billion cubic feet (bcf)
Region	2015-03-27	2015-03-20	change
East	522	559	-37
West	348	344	4
Producing	591	576	15
Total	1,461	1,479	-18
Source: U.S. Energy Information Administration

Working gas in underground storage
	Historical comparisons
	Year ago (3/27/14)		5-year average (2010-2014)
Region	Stocks (Bcf)	% change	Stocks (Bcf)	% change
East	317	64.7	695	-24.9
West	161	116.1	269	29.4
Producing	355	66.5	686	-13.8
Total	833	75.4	1,651	-11.5
Source: U.S. Energy Information Administration

Temperature -- heating & cooling degree days (week ending Mar 26)
		HDD deviation from:			CDD deviation from:
Region	HDD Current	normal	last year	CDD Current	normal	last year
New England	246	61	15	0	0	0
Middle Atlantic	219	49	2	0	0	0
E N Central	195	18	-46	0	0	0
W N Central	165	-10	-69	0	-1	0
South Atlantic	89	-7	-41	20	8	8
E S Central	61	-29	-68	0	-5	0
W S Central	32	-20	-37	17	4	12
Mountain	102	-45	-36	6	3	2
Pacific	42	-43	-23	1	0	1
United States	131	-2	-34	6	1	3
Note: HDD = heating degree-day; CDD = cooling degree-day Source: National Oceanic and Atmospheric Administration