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

Natural Gas

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Natural Gas Weekly Update

for week ending April 30, 2014 | Release date: May 1, 2014 | Next release: May 8, 2014 | Previous weeks

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In the News:

Decreasing natural gas price seasonality keeps inventories in April at 11-year low

Natural gas net storage injections for the Lower 48 totaled 82 billion cubic feet (Bcf) for the week ending on April 25. This was the fourth consecutive week of net storage injections, which this year began in the week ending on April 4. Over this period, cumulative net injections totaled 163 Bcf, a 53% increase when compared to the same weeks in 2013, but only 8% above the 5-year average for these weeks of 151 Bcf. Total Lower 48 working inventories totaled 981 Bcf, an 11-year low. This was well below the 2009-13 minimum for that week of 1,716 Bcf, as can be seen from the storage graph below this article. It is also the latest point in the year that inventories have remained below 1,000 Bcf since 2003. Despite a steady increase in natural gas supply, current high spot prices coupled with comparatively low price expectations for the upcoming winter season, when stored volumes are likely to be withdrawn, have put a damper on natural gas storage injections in April (Figure 1).

Lower 48 working natural gas inventories started the injection season on April 1 at 824 Bcf, their lowest level since April 1, 2003, following a record natural gas 2013-14 winter storage withdrawal of 2,970 Bcf (Figure 2). This contributed to the highest natural gas spot prices in April since 2008. The higher spot prices likely narrowed the expected return from storing natural gas because forward contracts thus far show moderate prices for winter. The difference during days when natural gas contracts were traded in April between the most expensive monthly natural gas delivery contract for the upcoming winter season (November to March), and the front-month contract (May, and June for the final two trading days in April), has decreased to almost zero (Figure 3). This means that producers have little incentive to store their output in April, because they have almost no expected payoff from withdrawing and selling it when demand peaks during the upcoming winter season, compared to what they could make from selling it to consumers in the current market.

The lower expected return from storing natural gas reflects a trend that has occurred generally in recent years, as increased natural gas production, particularly in consuming states such as Pennsylvania, has contributed to decreasing seasonality in natural gas prices. In April 2013 and April 2014, the average difference in the maximum winter futures contract and April spot prices was 31 cents per million British thermal units (MMBtu), compared to an average of $2.14/MMBtu in April 2011 and 2012. The expected return from storing natural gas has thus fallen significantly, not accounting for costs directly associated with storing gas. Partially as a result, average net storage injections for weeks 14-17 (corresponding with the weeks ending on April 4 and April 25) fell by 51%, to an average of 135 Bcf for April 2013 and 2014, versus 204 Bcf for April 2011 and 2012.

There are other factors beyond direct economic considerations that drive storage builds. These include competition for available supplies from current consumers, and the need for local distribution companies (LDCs) to ensure there are adequate supplies in storage for the upcoming winter withdrawal season. Although expected returns from storage in April 2014 were slightly lower than in April 2013, net injections increased, due largely to a 3% decrease in total consumption coupled with a 3% increase in total supply. Despite high consumption in the middle of the month, particularly from the electric power sector (power burn), overall power burn in April was down by 5% compared to last year, averaging 17.8 Bcf/d, while residential and commercial consumption was down by 3%, averaging 23.2 Bcf/d. Supply was up; dry gas production rose by 4%, to 67.3 Bcf/d.

Net injections in April do not necessarily indicate what will occur through the end of the injection season on October 31. For example, the high net injections that occurred during April 2012 were followed by low net injections through October 2012, as high levels of existing inventories contributed to lower prices and increased consumption from the electric power sector. Similarly, the low current storage levels could lead to high injections through October in areas where LDCs are legally required to meet prewinter storage level requirements, and where there is a greater incentive to store in anticipation of regional winter price spikes. This is particularly true in the eastern storage region, where working inventories consistently reach 90%-95% of available storage capacity by the end of October.

For the week ending on April 4, a net withdrawal in the eastern storage region brought inventories there to 305 Bcf, their lowest level in 11 years (Figure 4). Relatively low injections over the next three weeks brought inventories there to 362 Bcf for the week ending on April 25. This was less than half of the average for that week from 2009 to 2013, of 828 Bcf.

Overview:

(For the Week Ending Wednesday, April 30, 2014)

Natural gas spot prices were generally flat for the report period, increasing by a few cents in some locations. The Henry Hub spot price was nearly flat, changing from $4.79/MMBtu last Wednesday to $4.78 yesterday.
At the New York Mercantile Exchange (Nymex), the May near-month contract gained just over a nickel, beginning the week at $4.730/MMBtu last Wednesday and settling at $4.795/MMBtu on Monday, when the June contract moved to near-month position. The June contract gained about 7 cents over the report week, from $4.747/MMBtu last Wednesday to $4.815 yesterday.
Working natural gas in storage rose to 981 Bcf as of Friday, April 25, according to the U.S. Energy Information Administration (EIA) Weekly Natural Gas Storage Report (WNGSR). A net storage injection of 82 Bcf for the week resulted in storage levels 44.6% below year-ago levels and 50.1% below the 5-year average.
Active drilling rigs totaled 1,861 as of April 25, up by 30 rigs from the previous week, according to data from Baker Hughes Inc. The natural gas rig count increased by 7 rigs to 323, and the number of oil-directed rigs increased by 24 to 1,534. The average oil rig count for April 2014 is 11% higher than April 2013, and the active gas rig count is 12% lower.
After increasing for four consecutive weeks, the weekly average natural gas plant liquids composite price decreased slightly, falling 0.8% this week (covering April 21 through April 25) from $10.40/MMBtu to $10.31/MMBtu. The spot prices of propane, isobutane, and natural gasoline each fell by between 1% and 2%. The ethane spot price increased by 1.3% to $4.08/MMBtu, which is significantly below the natural gas spot price. The butane price was essentially flat.

more summary data

Prices/Demand/Supply:

Natural gas spot prices stay flat. In most trading locations, natural gas spot prices stayed flat, with some locations posting modest increases for the week. The Henry Hub price remained flat for the report week, moving from $4.79/MMBtu last Wednesday to $4.78 yesterday. Across the country, many trading points continue to trade at a discount to the Henry Hub price. Even Algonquin Citygate, which delivers gas to Boston, was settling at a discount to Henry Hub until this past Monday.

Prices for delivery in California were up about a nickel, possibly due to the cooler weather in the Pacific Northwest relative to last week, as well as the explosion at Williams's Opal gas processing plant last Wednesday, detailed below. The Malin spot price, which delivers at the southern Oregon border, rose from $4.67 last Wednesday to $4.73 yesterday. The SoCal Citygate price in California also rose a few cents over that period, from $5.01 to $5.08.

Nymex modestly increases. The May near-month contract began the week at $4.730/MMBtu last Wednesday and settled at $4.795 on Monday, when the June contract moved to near-month position. The June contract gained about 7 cents over the report week, from $4.747 last Wednesday to $4.815 yesterday. The 12-month strip (the average of the June 2014 through May 2015 contracts) increased by a similar increment, rising from $4.799 last Wednesday to $4.882 yesterday. The small spread between the near-month price and the 12-month strip indicates that markets do not anticipate significant natural gas price increases over the next year.

Spread between June and January futures contracts is 21 cents. The highest winter month Nymex price in trading yesterday was January, which settled at $4.976/MMBtu. This is 21 cents more than the Nymex June contract price yesterday.

Ethane spot price remains low despite new developments. The Mont Belvieu ethane spot price is currently very low relative to the natural gas price. So far in 2014, it has averaged $0.61/MMBtu below the Henry Hub price. Consequentially, many natural gas processors continue to leave some amount of ethane in their dry gas stream and sell it as natural gas, a phenomenon referred to as ethane rejection. The price gap between Mont Belvieu ethane and Henry Hub natural gas has increased since 2013, when ethane averaged $0.19/MMBtu below Henry Hub for the year. This is in contrast to prices that occurred as recently as 2011, when the annual average ethane spot price was $10.47/MMBtu, which was $6.47/MMBtu above the Henry Hub price.

As a result of this attractively priced ethane, many chemical companies are rushing to build steam crackers that consume ethane to produce various other hydrocarbon products. Additionally, ethane exports to Canada via the Mariner West Pipeline have begun, averaging 24,000 barrels per day (Mbbl/d) in February. Other key ethane export projects include Mariner East and Marcus Hook in the Marcellus region, supporting shipments out of New Jersey, the Vantage Pipeline from North Dakota to Canada, and the recently announced Enterprise project in the Gulf Coast.

Natural gas supply stays flat with production decreasing slightly and imports increasing. According to Bentek data, overall supply remained flat this week. A small decrease in production (0.3%) was offset by an increase in imports from Canada (4.8%). Total imports from Canada were driven up largely based on increased imports in the West, as California and the Pacific Northwest faced cooler week-on-week temperatures.

Production was down, partly because of processing plant maintenance in the Marcellus region and partly due to an explosion at Williams's Opal gas plant on April 23. The plant, which had been processing about 1 Bcf/d of natural gas, caused westward flows on the Kern River and Ruby pipelines to decrease shortly after the explosion. Producers in the region quickly rerouted flows through other processing plants, such as Enterprise Product Partners's Pioneer plant. Gas flowing into the southwest on the El Paso Natural Gas (EPNG) pipeline system, ramped up quickly to replace missing volumes. Williams said early today that it had restarted its Opal operations.

Consumption falls slightly. Bentek data show overall consumption declining by 0.4% over the report period. Continuing into the shoulder season, residential and commercial consumption decreased by 4.0%, and industrial consumption, which also is weather-sensitive, decreased by 1.3%. These decreases offset increases in exports to Mexico, which climbed by 7.3%, and electric-sector consumption, which rose by 7.6%. On colder weather and lack of hydroelectric availability, the Pacific Northwest consumed 55% more gas for electric generation this week. The Southeast, which is the biggest market for electric-sector natural gas consumption, consumed 20.9% more gas in this sector, likely because of initial air conditioning load accompanying the beginning of warm weather.

more price data

Storage

Net storage injection is larger than average. The net injection reported for the week ending April 25 was 82 Bcf, 24 Bcf larger than the 5-year average net injection of 58 Bcf and 41 Bcf larger than last year's net injection of 41 Bcf. Working gas inventories totaled 981 Bcf, 790 Bcf (44.6%) less than last year at this time, 984 Bcf (50.1%) below the 5-year (2009-13) average, and 735 Bcf (42.8%) below the 5-year observed minimum.

Storage build is larger than market expectations. Market expectations called for a build of 75 Bcf. When the EIA storage report was released at 10:30 a.m., the price for the June natural gas futures contract fell 3 cents to $4.75/MMBtu on the Nymex. Prices continued trading around that level in the hour following the release.

Net injections in all three regions are larger than average. The East, West, and Producing regions had net injections of 34 Bcf (4 Bcf larger than its 5-year average injection of 30 Bcf), 13 Bcf (5 Bcf larger than its 5-year average injection of 8 Bcf), and 35 Bcf (16 Bcf larger than its 5-year average injection of 19 Bcf), respectively. Storage levels for all three regions remain below their year-ago and 5-year average levels, and their 5-year minimums.

Temperatures during the storage report week warmer than normal. Temperatures in the Lower 48 states averaged 55.6 degrees for the week, 0.6 degree warmer than the 30-year normal temperature and 4.0 degrees warmer than during the same period last year.

more storage data

Spot Prices ($/MMBtu)	Thu, 24-Apr	Fri, 25-Apr	Mon, 28-Apr	Tue, 29-Apr	Wed, 30-Apr
Henry Hub	4.81	4.70	4.78	4.82	4.78
New York	4.08	3.66	4.47	4.38	4.23
Chicago	4.80	4.69	4.79	4.88	4.89
Cal. Comp. Avg,*	5.01	4.79	4.90	4.93	4.96
Futures ($/MMBtu)
May Contract	4.705	4.647	4.795	Expired	Expired
June Contract	4.723	4.658	4.799	4.831	4.815
July Contract	4.755	4.687	4.819	4.853	4.843
*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: (4/23/14 - 4/30/14)
	Percent change for week compared with:
	last year	last week
Gross Production	3.71%	-0.26%
Dry Production	3.68%	-0.26%
Canadian Imports	-4.90%	4.80%
West (Net)	-3.82%	8.12%
MidWest (Net)	-15.23%	6.31%
Northeast (Net)	409.65%	-26.05%
LNG Imports	-43.06%	-8.19%
Total Supply	2.95%	0.04%
Source: BENTEK Energy LLC

U.S. Consumption - Gas Week: (4/23/14 - 4/30/14)
	Percent change for week compared with:
	last year	last week
U.S. Consumption	1.9%	0.2%
Power	-1.7%	7.6%
Industrial	-1.5%	-1.6%
Residential/Commercial	8.8%	-4.0%
Total Demand	2.3%	0.4%
Source: BENTEK Energy LLC

Rigs
	Fri, April 25, 2014	Change from
	Fri, April 25, 2014	last week	last year
Oil Rigs	1,534	1.59%	11.08%
Natural Gas Rigs	323	2.22%	-11.75%
Miscellaneous	4	-20.00%	-42.86%

Rig Numbers by Type
	Fri, April 25, 2014	Change from
	Fri, April 25, 2014	last week	last year
Vertical	398	1.79%	-15.50%
Horizontal	1,245	1.72%	14.85%
Directional	218	0.93%	9.55%
Source: Baker Hughes Inc.

Working Gas in Underground Storage
	Stocks billion cubic feet (bcf)
Region	2014-04-25	2014-04-18	change
East	362	328	34
West	191	178	13
Producing	428	393	35
Total	981	899	82
Source: U.S. Energy Information Administration

Working Gas in Underground Storage
	Historical Comparisons
	Year ago (4/25/13)		5-year average (2009-2013)
Region	Stocks (Bcf)	% change	Stocks (Bcf)	% change
East	701	-48.4	828	-56.3
West	338	-43.5	313	-39.0
Producing	731	-41.5	824	-48.1
Total	1,771	-44.6	1,965	-50.1
Source: U.S. Energy Information Administration

Temperature -- Heating & Cooling Degree Days (week ending Apr 24)
		HDD deviation from:			CDD deviation from:
Region	HDD Current	normal	last year	CDD Current	normal	last year
New England	124	5	-3	0	0	0
Middle Atlantic	110	8	-1	0	0	0
E N Central	98	-8	-34	0	0	-1
W N Central	85	-10	-89	0	-1	0
South Atlantic	62	14	-5	15	-3	-7
E S Central	36	-6	-28	3	-3	-4
W S Central	16	-1	-43	29	4	17
Mountain	67	-36	-78	12	2	6
Pacific	40	-19	2	0	-4	0
United States	73	-6	-27	7	-2	1
Note: HDD = heating degree-day; CDD = cooling degree-day Source: National Oceanic and Atmospheric Administration