Natural Gas

Overview:

(For the Week Ending Wednesday, May 14, 2014)

• Natural gas spot prices fell throughout the United States. The Henry Hub decreased by 42 cents per million British thermal units (MMBtu), moving from $4.83/MMBtu last Wednesday to $4.41 yesterday.
• At the New York Mercantile Exchange (Nymex), the June contract fell by 37 cents/MMBtu, beginning the report week at $4.740/MMBtu last Wednesday and settling at $4.367/MMBtu yesterday.
• Active oil and natural gas drilling rigs totaled 1,855 as of May 9, up 1 rig from the previous week, according to data from Baker Hughes Inc. The natural gas-directed rig count was flat for the second consecutive week, while the oil-directed rig count increased by 1, to 1,528. The oil rig count is currently 116 higher than this week last year, and the gas rig count is 27 lower.
• The weekly average natural gas plant liquids composite price decreased for the third consecutive week, falling this week (covering May 5 through May 9) by 2.7% to $9.78/MMBtu, 27 cents/MMBtu lower than last week. The Mont Belvieu spot prices of ethane, propane, butane, isobutane, and natural gasoline all decreased, by between 1.9% and 3.6%.
• Working natural gas in storage rose to 1,160 Bcf as of Friday, May 9, according to the U.S. Energy Information Administration (EIA) Weekly Natural Gas Storage Report (WNGSR). A net storage increase of 105 billion cubic feet (Bcf) for the week resulted in storage levels 40.5% below year-ago levels and 45.3% below the 5-year average. Net injections totaled 97 Bcf, with an additional 8 Bcf increase in working gas inventories because of the reclassification of base gas inventories as working gas in the eastern storage region.

more summary data

Prices/Demand/Supply:

Natural gas spot prices decrease throughout the United States. Natural gas prices fell throughout the United States this week. Natural gas demand decreased as temperatures rose in most of the contiguous United States, while domestic production increased significantly. The Henry Hub spot price decreased by 42 cents/MMBtu to $4.41/MMBtu. Prices generally declined by between 20 and 40 cents/MMBtu at most major hubs outside of the Northeast, including in the Rockies and Midcontinent regions, where temperatures cooled this week.

In the Northeast, prices fell more significantly. A combination of lower demand and increasing production from the Marcellus Shale contributed to lower spot prices at the Tetco M3 hub serving mid-Atlantic consumers, the Transco Zone 6-New York Hub, and the Algonquin Citygate hub, which serves Boston area consumers. Spot prices at Tetco M3 and Transco Zone 6-New York both averaged less than Henry Hub for the seventh week in a row, while the Algonquin Citygate price averaged less than Henry Hub for the third week in a row. The Transco Zone 6-New York spot price dropped 98 cents/MMBtu, from $4.19/MMBtu last Wednesday to $3.21/MMBtu yesterday. Tetco M3 dropped 91 cents/MMBtu, from $4.15/MMBtu last Wednesday to $3.24/MMBtu yesterday. The Algonquin Citygate spot price decreased 37 cents/MMBtu for the week. It dropped 61cents/MMBtu, from $4.43/MMBtu last Wednesday, to $3.82/MMBtu on Tuesday, before trading up yesterday to $4.06/MMBtu, as Boston temperatures cooled. The lowest Marcellus price was at the Leidy Hub, falling $1.21 in a week to $2.36/MMBtu yesterday.

Nymex price falls slightly. At the New York Mercantile Exchange (Nymex), the June contract declined, beginning the week at $4.740/MMBtu last Wednesday and settling at $4.367 yesterday. The June contract decreased every trade day through Tuesday as temperatures warmed throughout the country. The largest price decrease occurred on Thursday, May 8, when the June contract dropped by 17 cents/MMBtu. It then decreased by 4 cents/MMBtu on Friday, May 9, 10 cents/MMBtu on Monday, May 12, and 8 cents/MMBtu on Tuesday, May 13, before trading up by 1 cent/MMBtu yesterday, when the weather cooled slightly.

The 12-month strip (the average of the June 2014 through May 2015 contracts) similarly fell, moving from $4.700/MMBtu last Wednesday to $4.363/MMBtu yesterday. The entire forwards curve traded down significantly through Tuesday, and then rose slightly yesterday, in line with changes in the June contract.

Higher production drives up natural gas supply. According to Bentek Energy data, dry natural gas production in the United States surpassed 68.0 Bcf/d for the first time ever this week. Dry production rose 0.6 Bcf/d (1%) over last week to a record weekly average of 67.8 Bcf/d. Dry production jumped from 67.7 Bcf on Friday, May 9, to a record 68.0 Bcf on Saturday, May 10. According to trade press reports, production rose significantly in the Gulf Coast, from offshore fields, and onshore fields in Texas, which include the Eagle Ford Shale. U.S. dry production broke this record the next day, when it reached 68.1 Bcf on Sunday, May 11.

The increase in U.S. dry production over the weekend drove total U.S. natural gas supply to a record average of 73.0 Bcf/d this week. Net imports of natural gas from Canada and of liquefied natural gas (LNG) were flat this week compared to last week.

Consumption declines. For the second consecutive week, lower natural gas consumption from the residential and commercial sectors drove down total U.S. natural gas consumption, despite higher natural gas consumption from the power sector (power burn). A decrease of residential and commercial consumption that exceeds increased power burn is typical of the spring shoulder season, when total power burn begins to overtake residential and commercial sector consumption. This occurred last week for the first time in 2014.

Total consumption fell by 1.4 Bcf/d (2.3%) below last week's daily average. Residential and commercial consumption fell by 2.7 Bcf/d (14.8%), to 15.5 Bcf/d, while power burn rose by 1.7 Bcf/d (8.8%), to 21.3 Bcf/d. Power burn decreased in Texas, the Midcontinent, Rockies, and the Southwest, where temperatures were the same as or cooler than they were last week. Power burn increased in the Northeast, Midwest, and Southeast, where temperatures warmed. The largest increase this week occurred in the Southeast, where power burn rose by 1.1 Bcf/d (16.7%), to 7.7 Bcf/d, followed by the Northeast, where power burn rose by 0.9 Bcf/d (21.9%), to 4.8 Bcf/d.

Industrial consumption fell by 0.3 Bcf/d, to 1.8%, while net exports to Mexico increased by 0.1 Bcf/d, to 1.9 Bcf/d.

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Storage

Net storage increase is in triple digits. The net injection reported for the week ending May 9 was 97 Bcf, but there also was an upward reclassification of working gas storage in the East, thus raising the total-U.S. stock level by 105 Bcf. Last year's net injection for this week was 98 Bcf. Working gas inventories totaled 1,160 Bcf, 790 Bcf (40.5%) less than last year at this time and 959 Bcf (45.3%) below the 5-year (2009-13) average.

Storage build is larger than market expectations because of reclassification. Market expectations called for a build of 98 Bcf. Despite the higher than expected build, when the EIA storage report was released at 10:30 a.m., the price for the June natural gas futures contract rose 11 cents to $4.45 /MMBtu on the Nymex. Prices increased an additional 3 cents in the hour following the release.

From the week ending on April 4 to the week ending on May 9, net storage injections have totaled 338 Bcf, versus 275 Bcf for the same six weeks in 2013, and 305 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 May 9 was $4.73/MMBtu, 14% higher than the average value for the same six weeks last year of $4.13/MMBtu. The highest winter month Nymex price in trading for the week ending on May 9 averaged $4.91/MMBtu. This was 23 cents more than the Nymex June contract price. For the same storage week last year, which ended on May 10, 2013, the difference between the maximum winter contract and the front-month contract was 31 cents/MMBtu.

There are currently 25 more weeks in the injection season, which traditionally occurs April 1 through October 31, although in many years injections continue into November. In order to reach EIA's forecasted end of October working natural gas inventory level of 3,405 Bcf, an average injection of 90 Bcf per week will need to occur through the end of October. EIA's forecast for the end of October inventory levels are below the 5-year (2009-13) minimum value of 3,792 Bcf. To reach the 5-year minimum, average weekly injections through the end of October would need to be 105 Bcf.

All three regions post larger-than-average builds. The East, West, and Producing regions had net injections of 60 Bcf (10 Bcf larger than its 5-year average injection), 16 Bcf (5 Bcf larger than its 5-year average injection), and 29 Bcf (7 Bcf larger than its 5-year average injection), 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 60.6 degrees for the week, 1.6 degrees warmer than the 30-year normal temperature and 2.0 degrees warmer than during the same period last year.

more storage data

See also:

• Natural Gas Analysis Reports
• Short-Term Energy Outlook