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Natural Gas Weekly Update

for week ending June 18, 2014   |  Release date:  June 19, 2014   |  Next release:  June 26, 2014   |   Previous weeks

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

In the News:

Growth in Marcellus Production Drives Changes this week in REX Pipeline Dynamics

In 2006, the Rockies Express Pipeline (REX) began flowing natural gas out of the Rocky Mountains, starting in Colorado and first moving northward to Wyoming and then eastward, eventually to a point on the Ohio-Pennsylvania border. It became a $5 billion, 1,700-mile pipeline, the largest project of its time, and it flowed previously stranded Rockies gas to burgeoning markets in the Northeast.

This week, REX headed back westward.

The insurmountable challenge to the eastward REX is the prolific Marcellus Shale field, now the fastest-growing gas producing area in the nation.

As with its start, REX's retreat begins small. Its Seneca Lateral, the first of many planned projects that will send Appalachian Basin gas west, is expected to come online this week, and REX announced yesterday it would accept nominations for flows tomorrow.

The 14.3-mile Seneca pipeline will allow natural gas to flow north to the Rockies Express mainline, where a new compressor station will allow the gas to flow west to points in Ohio, Indiana, and Illinois. The lateral will have an initial operating capacity of 0.25 billion cubic feet per day (Bcf/d), but REX plans to expand its capacity to 0.60 Bcf/d by the end of the year.

REX has provided service since 2009 along its entire 1,700-mile route. The pipeline – one of the longest in the United States — was originally built to bring natural gas produced in the Rocky Mountains to eastern markets. Before REX began operating, gas produced in the Rockies was often stranded and traded below a dollar per million British thermal unit (MMBtu). However, production dynamics have changed in the past several years, with supply growing exponentially in the Northeast. Much like in the Rockies in 2008, prices at Marcellus trading points often are far below the national benchmark because production growth has exceeded even the increased takeaway capacity. In response, producers and pipeline developers are exploring ways to move the glut of gas out of the Marcellus and Utica to other market areas. Tallgrass Energy, REX's parent company, plans to add bidirectional capacity on a significant portion of REX's easternmost segment (from northeast Missouri to eastern Ohio), and has received binding commitments to deliver 1.2 Bcf/d of gas west.

Several major natural gas pipelines interconnect with REX in Illinois, Indiana, and Ohio that could receive Appalachian Basin gas from REX. These include:

REX is also holding a nonbinding open season for the Clarington West Project, which would provide additional east-to-west capacity on REX through either new compression, new pipelines, or a combination of the two, beginning in 2016 or 2017. It is not yet known whether the Clarington West Project will allow for an expansion of westward natural gas flows to cover all of Zone 3 or just a significant portion of it. There are plans to add five new receipt points to provide REX with the capacity to receive at least 2.35 Bcf/d of Appalachian production by the end of 2016.

In addition to REX expansions, a number of other projects are planned to provide capacity to flow Appalachian production west. These include Tetco's Ohio Pipeline Energy Network (OPEN) project to flow additional gas to REX at Clarington, and Tetco's TEAM 2014 project to flow gas to Lebanon and the Gulf Coast on existing pipelines from western Pennsylvania. They also include a DTI project to ship 0.25 Bcf/d to its interconnections with REX and Tetco in eastern Ohio and to ship another 0.25 Bcf/d directly to the Lebanon hub.

Overview:

(For the Week Ending Wednesday, June 18, 2014)

  • Natural gas prices posted a slight overall increase during the report week (Wednesday, June 11 – Wednesday, June 18) at most market locations, as temperatures warmed, increasing demand for natural gas that is consumed for electric generation (power burn). The Henry Hub spot price rose from $4.50/MMBtu last Wednesday to $4.70/MMBtu yesterday, its highest level since early May.
  • At the New York Mercantile Exchange (Nymex) the price of the front-month (July 2014) contract rose from $4.508/MMBtu last Wednesday to $4.659/MMBtu yesterday. The price of the 12-month strip also rose, from $4.448/MMBtu last Wednesday to $4.579/MMBtu yesterday.
  • Working natural gas in storage rose to 1,719 Bcf as of Friday, June 13, according to the U.S. Energy Information Administration (EIA) Weekly Natural Gas Storage Report (WNGSR). A net increase in storage of 113 Bcf for the week resulted in storage levels 29.1% below year-ago levels and 33.1% below the 5-year average.
  • The Baker Hughes rotary rig count decreased by 6 for the second week in a row, to 1,854 as of June 13. The number of active gas-directed rigs fell by 10. An increase of 3 gas-directed rigs in the Marcellus Shale only partially offset a decrease of 3 rigs in the Granite Wash Shale in Texas and Oklahoma and a decrease of 10 rigs in the rest of the United States. The total number of U.S. oil-directed rigs rose by 6. There was an increase of 8 oil-directed rigs in the Permian Basin in West Texas and eastern New Mexico, 6 oil-directed rigs in the Niobrara Shale in Colorado and Wyoming, and 6 oil-directed rigs in Granite Wash. This was only partially offset by a decrease of 4 oil-directed rigs in the Williston Basin, which includes the Bakken Shale, and 10 oil-directed rigs in the rest of the United States.
  • The Mont Belvieu natural gas plant liquids composite price partially recovered from last week's decrease, rising by 10 cents to $9.84/MMBtu for the week covering June 9 to June 13. After decreasing last week, the price for natural gasoline, propane, butane and isobutane all rose this week, by 3.2%, 1.0%, 0.1%, and 0.6%, respectively. The ethane spot price spot price decreased by 1.6%, after increasing last week.

more summary data

Prices/Demand/Supply:

Prices rise at most locations. On Friday, June 13, natural gas spot prices at most major U.S. hubs increased significantly, likely in anticipation of warmer temperatures that caused a sharp increase in power burn by Monday. The average daily Henry Hub spot price rose from $4.50/MMBtu last Thursday, to $4.67/MMBtu on Friday. The price increased to $4.70/MMBtu on Monday prior to warmer temperatures on Tuesday that caused another significant gain in power burn. The Henry Hub price traded down on Tuesday, before closing the report week yesterday at $4.70/MMBtu. This was the highest Henry Hub spot price since May 8.

Algonquin prices reach end-winter levels. At the Algonquin Citygate, which serves Boston-area consumers, the spot price averaged $7.18/MMBtu on Tuesday, its highest level since March 25. The Algonquin spot price decreased significantly over the previous 11 report weeks, following a period of frequent spikes this winter, when it reached record levels. Starting in mid-April, Algonquin traded below Henry Hub on most days. It traded below Henry Hub on Friday, when it traded at $4.64/MMBtu. It then rose to $5.72/MMBtu on Monday, likely in anticipation of Tuesday temperatures that on average rose above 70 degrees Fahrenheit, and to $7.18/MMBtu on Tuesday, anticipating temperatures yesterday that reached an average of 83 degrees. Temperatures in New York were even warmer yesterday, averaging 87 degrees. However, the Transco Zone 6-New York spot price remained below $4.00/MMBtu through the report week, as New York area consumers have benefited from pipeline expansions that have eased congestion on pipelines carrying Marcellus Shale gas.

Nymex increases this week. The price of the Nymex near-month (July) contract began the report week on Wednesday, June 11, at $4.508/MMBtu. It traded up by 25.4 cents/MMBtu on Thursday, closing at $4.762/MMBtu, as temperature expectations rose. This was the highest price for both the July contract and the near-month contract since May 6. The July contract closed above $4.700/MMBtu through Tuesday, before trading down yesterday to $4.659/MMBtu, a 15.1-cent/MMBtu gain for the report week. The price of the 12-month strip (the 12 contracts between July 2014 and June 2015) rose by 13.2 cents/MMBtu, from $4.448/MMBtu last Wednesday to $4.579 yesterday.

Production and supply partially recover from last week. Overall supply increased by 0.4 Bcf/d, or 0.6%, from the previous week, to 72.7 Bcf/d, following a 0.7 Bcf/d decrease last week. Dry natural gas production increased by 0.1 Bcf/d, or 0.2%, to 67.9 Bcf/d, following a decrease last week of 0.3 Bcf/d. Dry production remained 0.5% below the record average of 68.3 Bcf/d for the week ending on May 28. Pipeline imports from Canada increased by 0.3 Bcf/d, while liquefied natural gas (LNG) sendout remained flat.

Consumption decreases, despite higher power burn. Total U.S. natural gas consumption declined for the seventh week in a row, by 0.2 Bcf/d, or 0.3%, to 54.8 Bcf/d, despite increasing power burn by electricity generators. From Thursday to Sunday, total U.S. natural gas consumption fell from 53.5 Bcf to 52.1 Bcf, as power burn fell from 21.8 Bcf to 20.2 Bcf. Consumption rose to 55.4 Bcf on Monday and 59.0 Bcf on Tuesday, driven by a jump in power burn to 24.5 Bcf and 28.2 Bcf, respectively, as temperatures warmed significantly throughout the country, particularly in the Northeast, Midwest, Southeast, and Midcontinent. Consumption and power burn both decreased on Wednesday.

Although average power burn for the report week rose by 0.3 Bcf/d, to 23.2 Bcf/d, this was less than the 0.4 Bcf/d decrease in residential and commercial consumption, which fell as a result of the warmer temperatures, causing total U.S. consumption to decrease. Industrial natural gas consumption decreased slightly, while pipeline exports to Mexico increased slightly.

more price data

Storage


Correction: June 26, 2014, text below was modified and updated.

Storage increases by triple digits for sixth straight week. This is the first time that inventory builds were more than 100 Bcf for six consecutive weeks. The net injection reported for the week ending June 13 was 113 Bcf, 26 Bcf larger than the 5-year average net injection of 87 Bcf and 21 Bcf larger than last year's net injection of 92 Bcf. Working gas inventories totaled 1,719 Bcf, 706 Bcf (29.1%) less than last year at this time, and 851 Bcf (33.1%) below the 5-year (2009-13) average.

Storage build is larger than market expectations. Market expectations called for a build of 110 Bcf. When the EIA storage report was released at 10:30 a.m., the price for the July natural gas futures contract fell 4 cents to $4.62/MMBtu on the Nymex.

From the week ending on April 4 to the week ending on June 13, net storage injections have totaled 897 Bcf, versus 725 Bcf for the same 11 weeks in 2013, and 756 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 June 13 was $4.60/MMBtu, 14% higher than the average value for the same 11 weeks last year of $4.04/MMBtu. The highest winter-month Nymex price (for next January) in trading for the week ending on June 13 averaged $4.80/MMBtu. This was 14 cents more than the current Nymex July contract price. A year ago, the difference was 28 cents/MMBtu.

There are currently 20 more weeks in the injection season, which traditionally occurs April 1 through October 31, although, in many years, injections continue into November. EIA forecasts that the end-of-October working natural gas inventory level will be 3,424 Bcf, which, as of June 13, would require an average injection of 85 Bcf per week through the end of October. EIA's forecast for the end-of-October inventory levels are below the 5-year (2009-13) average value of 3,837 Bcf. To reach the 5-year average by October 31, average weekly injections through the end of October would need to be 106 Bcf.

All three regions post larger-than-average builds. The East, West, and Producing regions had net injections of 70 Bcf (14 Bcf larger than its 5-year average injection), 16 Bcf (3 Bcf larger than its 5-year average injection), and 27 Bcf (8 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.

Temperatures during the storage report week were warmer than normal. Temperatures in the Lower 48 states averaged 70.3 degrees for the week, 1.1 degrees warmer than the 30-year normal temperature, but similar to the degree days recorded during the same period last year.

more storage data

See also:



Natural gas spot prices
Spot Prices ($/MMBtu)
Thu,
12-Jun
Fri,
13-Jun
Mon,
16-Jun
Tue,
17-Jun
Wed,
18-Jun
Henry Hub
4.50
4.67
4.70
4.66
4.70
New York
3.16
3.09
3.80
3.94
3.56
Chicago
4.58
4.70
4.76
4.82
4.83
Cal. Comp. Avg,*
4.76
4.86
4.90
4.85
4.91
Futures ($/MMBtu)
July Contract
4.762
4.739
4.707
4.709
4.659
August Contract
4.763
4.748
4.718
4.722
4.763
*Avg. of NGI's reported prices for: Malin, PG&E citygate, and Southern California Border Avg.
Source: NGI's Daily Gas Price Index
Natural gas futures prices
Natural gas liquids spot prices


U.S. Natural Gas Supply - Gas Week: (6/11/14 - 6/18/14)
Percent change for week compared with:
 
last year
last week
Gross Production
5.88%
0.21%
Dry Production
5.83%
0.21%
Canadian Imports
-6.29%
7.06%
      West (Net)
-19.69%
-7.96%
      MidWest (Net)
-8.30%
9.89%
      Northeast (Net)
-439.91%
967.80%
LNG Imports
-60.78%
-7.83%
Total Supply
4.72%
0.62%
Source: BENTEK Energy LLC
U.S. Consumption - Gas Week: (6/11/14 - 6/18/14)
Percent change for week compared with:
 
last year
last week
U.S. Consumption
-0.5%
-0.3%
Power
-4.6%
1.2%
Industrial
0.4%
-0.2%
Residential/Commercial
7.5%
-3.3%
Total Demand
0.6%
-0.2%
Source: BENTEK Energy LLC
Natural gas supply


Weekly natural gas rig count and average Henry Hub
Rigs
Fri, June 13, 2014
Change from
 
last week
last year
Oil Rigs
1,542
0.39%
9.13%
Natural Gas Rigs
310
-3.13%
-12.18%
Miscellaneous
2
-50.00%
-60.00%
Rig Numbers by Type
Fri, June 13, 2014
Change from
 
last week
last year
Vertical
388
-0.26%
-12.02%
Horizontal
1,248
-0.16%
14.92%
Directional
218
-1.36%
-10.66%
Source: Baker Hughes Inc.


Working Gas in Underground Storage
Stocks
billion cubic feet (bcf)
Region
2014-06-13
2014-06-06
change
East
790
720
70
West
298
282
16
Producing
631
604
27
Total
1,719
1,606
113
Source: U.S. Energy Information Administration
Working Gas in Underground Storage
Historical Comparisons
Year ago
(6/13/13)
5-year average
(2009-2013)
Region
Stocks (Bcf)
% change
Stocks (Bcf)
% change
East
1,076
-26.6
1,187
-33.4
West
418
-28.7
402
-25.9
Producing
930
-32.2
981
-35.7
Total
2,425
-29.1
2,570
-33.1
Source: U.S. Energy Information Administration


Temperature -- Heating & Cooling Degree Days (week ending Jun 12)
 
HDD deviation from:
 
CDD deviation from:
Region
HDD Current
normal
last year
CDD Current
normal
last year
New England
12
-8
-13
12
4
10
Middle Atlantic
5
-9
-7
14
-6
1
E N Central
14
-3
-3
11
-17
-10
W N Central
18
3
-3
20
-17
-9
South Atlantic
0
-3
0
81
14
4
E S Central
0
-2
0
64
3
-6
W S Central
0
0
0
94
1
0
Mountain
17
-11
9
58
13
-19
Pacific
4
-16
-1
36
18
5
United States
8
-6
-2
45
2
-2
Note: HDD = heating degree-day; CDD = cooling degree-day

Source: National Oceanic and Atmospheric Administration

Average temperature (°F)

7-Day Mean ending Jun 12, 2014

Mean Temperature (F) 7-Day Mean ending Jun 12, 2014

Source: NOAA/National Weather Service

Deviation between average and normal (°F)

7-Day Mean ending Jun 12, 2014

Mean Temperature Anomaly (F) 7-Day Mean ending Jun 12, 2014

Source: NOAA/National Weather Service