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Natural Gas Weekly Update

for week ending June 7, 2017   |  Release date:  June 8, 2017   |  Next release:  June 15, 2017   |   Previous weeks


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

In the News:

Mexico conducts its first natural gas pipeline capacity open season

As part of ongoing energy reforms, Mexico's National Center for Natural Gas Control (Centro National de Control del Gas Natural—CENAGAS), recently conducted the country's first open season for capacity rights on the national natural gas grid. CENAGAS manages Mexico's Integrated National Natural Gas Transportation and Storage System (Sistema de Transporte y Almacenamiento Nacional Integrado de Gas Natural—SISTRANGAS). SISTRANGAS currently has a pipeline length of 6,256 miles with a total transportation capacity of 6.3 billion cubic feet per day (Bcf/d).

CENAGAS was created in 2014 as the decentralized public entity entrusted with assignment of capacity rights for pipelines that were previously owned, operated, and largely used by Mexico's national energy company (Petroleus Mexico—PEMEX). Historically, PEMEX was the legal monopoly owner of Mexico's pipeline assets. Mexico's energy reform provided a process to dismantle the PEMEX monopoly and transition the energy sector into a more open market where foreign and local companies can compete to offer the best prices and services to customers.

Under Mexico's reforms, CENAGAS now owns PEMEX's pipeline assets and it will reimburse PEMEX in a series of negotiated payments estimated at 9 billion pesos. Mexico hopes that the entry of international firms can shore up the country's stagnant energy sector through the injection of foreign funds, the promotion of economic development, and the introduction of a more competitive energy industry.

In order to transition to the new market structure, two open seasons were scheduled, "Round 0" and "Round 1". During the Round 0 phase, which occurred in October 2016, 1.1 Bcf/d was reserved for Mexico's Federal Electricity Commission (Comisión Federal de Electricidad--CFE) and 1.4 Bcf/d was reserved for PEMEX. Another 1.6 Bcf/d of capacity was reserved for Mexico's independent power producers (IPPs). These IPPs hold long term contracts to sell power to the CFE and are not subject to the any short term capacity auctions. Thus, out of the 6.3 Bcf/d capacity only 2.2 Bcf/d was up for auction for the Round 1 auction.

On May 8, 2017, Round 1 auctions were held and 24 local and international companies requested 3.6 Bcf/d, but CENAGAS allocated only the available 2.2 Bcf/d. PEMEX won most of this allocation with 59% of the awards. The next largest shares went to ENGIE Mexico and ArcelorMittal, each getting 7% of the allocations. ENGIE Mexico provides energy and gas services to public and private sectors in Mexico through its ENGIE MaxiGas subsidiary. ArcellorMittal, one of the largest steel manufactures in the world, operates iron ore mining and steel production facilities in Mexico. Many of its plants use natural gas to generate electricity and as feedstock for industrial processes. Shell Trading Mexico acquired 6% of the allocations and is a natural gas marketer. Groupo Alpha acquired 5% of the natural gas allocations for space and water heating purposes. The company's line of business includes the wholesale distribution of industrial machinery and equipment. The remaining 338 MMcf/d went to 19 other companies. Many of these companies are in the natural gas retailing and marketing business but the list also includes industrial customers such as cement companies.

Overall, companies expressed great interest in injection points supplying U.S. natural gas to Mexican pipelines. The Kinder Morgan Texas Pipeline interconnect at Pesqueria, and the Ramones injection point connected to the Net Mexico pipeline, which bring U.S. natural gas to Mexico, were two of the most oversubscribed injection points with demand exceeding allocated capacity.

Awarded companies have until mid-June to sign capacity contracts with CENAGAS that will last for one year, until June 30, 2018.

Overview:

(For the Week Ending Wednesday, June 7, 2017)

  • Natural gas spot prices fell at most locations this report week (Wednesday, May 31 to Wednesday, June 7). The Henry Hub spot price fell from $3.00 per million British thermal units (MMBtu) last Wednesday to $2.99/MMBtu yesterday.
  • At the New York Mercantile Exchange (Nymex), the July 2017 contract price fell 5¢ from $3.071/MMBtu last Wednesday to $3.020/MMBtu yesterday.
  • Net injections to working gas totaled 106 billion cubic feet (Bcf) for the week ending June 2. Working natural gas stocks are 2,631 Bcf, which is 11% less than the year-ago level and 10% more than the five-year (2012–16) average for this week.
  • The natural gas plant liquids composite price at Mont Belvieu, Texas, fell by 34¢, averaging $5.83/MMBtu for the week ending June 7. Spot prices for natural gasoline, ethane, propane, butane, and isobutane all fell, by 4%, 5%, 7%, 6%, and 6%, respectively.
  • According to Baker Hughes, for the week ending Friday, June 2, the natural gas rig count decreased by 3 to 182. The number of oil-directed rigs rose by 11 to 733. The total rig count increased by 8, and it now stands at 916.

more summary data

Prices/Supply/Demand:

Prices fall across much of the country. This report week (Wednesday, May 31 to Wednesday, June 7), the Henry Hub spot price decreased 1¢ from $3.00/MMBtu last Wednesday to $2.99/MMBtu yesterday, after falling to a weekly low of $2.84/MMBtu on Friday. At the Chicago Citygate, prices increased 8¢ from $2.78/MMBtu last Wednesday to $2.86/MMBtu yesterday, as temperatures in the Midwest rose above seasonal norms. Prices at PG&E Citygate in Northern California fell 5¢, down from $3.22/MMBtu last Wednesday to $3.17/MMBtu yesterday. The price at SoCal Citygate increased 8¢ from $3.09/MMBtu last Wednesday to $3.17/MMBtu yesterday.

Northeast prices decrease. At the Algonquin Citygate, which serves Boston-area consumers, prices went down 16¢ from $2.40/MMBtu last Wednesday to $2.24/MMBtu yesterday, as temperatures in the Northeast were moderate for most of the past week. At the Transcontinental Pipeline Zone 6 trading point for New York, prices decreased 36¢ from $2.58/MMBtu last Wednesday to $2.22/MMBtu yesterday.

Tennessee Zone 4 Marcellus spot prices decreased 16¢ from $2.15/MMBtu last Wednesday to $1.99/MMBtu yesterday. Prices at Dominion South in northwest Pennsylvania fell 23¢ from $2.23/MMBtu last Wednesday to $2.00/MMBtu yesterday.

July Nymex price falls. At the Nymex, the price of the July 2017 contract decreased 5¢, from $3.071/MMBtu last Wednesday to $3.020/MMBtu yesterday. The price of the 12-month strip averaging July 2017 through June 2018 futures contracts declined 3¢ to $3.099/MMBtu.

Supply remains flat. According to data from PointLogic, the average total supply of natural gas remained the same as the previous report week, averaging 77.4 Bcf/d. Dry natural gas production also remained constant week over week. Average net imports from Canada increased by 1% from last week.

Demand falls. Total U.S. consumption of natural gas rose by 1% compared with the previous report week, according to data from PointLogic. Power burn climbed by 11% week over week, as the Midwest and Southwest experienced average temperatures above seasonal norms, some days by as much as 10°F. Industrial sector consumption decreased by 1% week over week. In the residential and commercial sectors, consumption declined by 18%, a decrease of less than 2 Bcf/d. Natural gas exports to Mexico decreased 7%.

U.S. liquefied natural gas (LNG) exports remain flat week over week. Three vessels (combined LNG-carrying capacity of 11.4 Bcf) departed Sabine Pass last week (Thursday to Wednesday), and one vessel (LNG-carrying capacity 3.4 Bcf) was loading at the terminal on Wednesday.

more price data

Storage:

Weekly net injections top 100 Bcf mark for the first time since 2015. Net injections into storage totaled 106 Bcf, compared with the five-year (2012–16) average net injection of 94 Bcf and last year's net injections of 68 Bcf during the same week. This marks the first time since September 18, 2015 that the weekly net injections exceeded 100 Bcf. After topping the 100 Bcf threshold five times in 2015 and a record ten times in 2014, net injections never exceeded 82 Bcf in any week during 2016. Record levels of working gas in storage entering the 2016 refill season likely contributed to the unusually slow refill activity. This is the first time in five weeks that net injections exceeded the five-year average.

Net injections into working gas storage top five-year average in most regions of the Lower 48 states. Net injections exceeded the five-year average in the East, Mountain, and Pacific regions. Only the South Central nonsalt region posted net injections below the five-year average, falling 3 Bcf below its five-year average of 6 Bcf for the report week. Net injections in the East region totaled 38 Bcf, 11 Bcf above the five-year average. Net injections in the Pacific region were 11 Bcf, topping the five-year average for the first time during the 2017 refill season.

Working gas levels are 11% lower than last year's record levels, and 10% ahead of the five-year average. Working gas stocks total 2,631 Bcf, which is 237 Bcf more than the five-year average and 332 Bcf less than last year at this time. This year-over-year deficit prevails in each of the regions of the Lower 48 states. However, each of the regions posted declines in the year-over-year deficit during the storage week. The South Central region has the largest year-over-year deficit at 123 Bcf. The East region has the largest deficit in relative terms, at 99 Bcf, 18% lower than last year's stock level. The Midwest region is 62 Bcf lower than last year at this time, and the Pacific region is 38 Bcf lower than last year's level. In contrast, working gas levels are higher than the five-year averages in all regions except the East and the Pacific regions, which are 49 Bcf and 22 Bcf lower than their five-year averages, respectively. The South Central region accounts for 189 Bcf of the surplus compared with the five-year average, and the Midwest region is 89 Bcf more than the five-year average.

The January futures price is trading at a premium over the current spot price, but trades at a discount with the near-month contract. During the most recent storage week, the average natural gas spot price at the Henry Hub was $3.02/MMBtu, while the Nymex futures price of natural gas for delivery in January 2018 averaged $3.45/MMBtu, a difference of 43¢. The premium was $1.14 a year ago. In comparison, the average natural gas spot price at the Henry Hub during the most recent storage week was only 10¢/MMBtu lower than the front-month futures price at the Nymex. A year ago, the spot price was 23¢/MMBtu lower than the front-month contract.

Reported net implied flows into storage are just above the range of market expectations for the week. According to the June 6 issue of The Desk survey of natural gas analysts, estimates of net injections to working natural gas storage ranged from 93 Bcf to 106 Bcf with a median of 99 Bcf. Prices of the Nymex futures contracts for July 2017 delivery at Henry Hub decreased 2¢ to $2.99/MMBtu in 951 trades at the release of the Weekly Natural Gas Storage Report (WNGSR). Prices varied in subsequent trading, climbing to $3.00/MMBtu.

Mild temperatures in large sections of the Lower 48 states contribute to larger than normal injections into storage. Temperatures in the Lower 48 states averaged 67°F, 1°F higher than the normal and 4°F lower than last year at this time. Mild temperatures in northern and western regions of the Lower 48 states limited both heating and cooling demand for natural gas, while somewhat warmer-than-normal temperatures in southern regions likely contributed to increased cooling demand for natural gas. In the northeast, temperatures in the New England Census and Middle Atlantic Census divisions were cooler than normal, averaging 58°F and 62°F, respectively. Temperatures in the East North Central Census division and the West North Central Census division matched normal levels, averaging 63°F and 64°F, respectively. Temperatures in the Mountain Census division averaged 66°F, 2°F higher than the normal, and temperatures in the Pacific Census division averaged 64°F, 1°F higher than the normal. Temperatures in the South Atlantic Census division averaged 74°F, 2°F higher than the normal. Temperatures in the East South Central Census division averaged 72°F, 1°F higher than the normal and 3°F lower than last year at this time. Temperatures in the West South Central Census division averaged 77°F, 1°F higher than the normal.

more storage data

See also:

CENAGAS allocations of non reserved natural gas pipeline capacity


Natural gas spot prices
Spot Prices ($/MMBtu)
Thu,
01-Jun
Fri,
02-Jun
Mon,
05-Jun
Tue,
06-Jun
Wed,
07-Jun
Henry Hub
2.93
2.84
2.91
2.96
2.99
New York
2.48
1.83
2.10
2.30
2.22
Chicago
2.72
2.70
2.84
2.85
2.86
Cal. Comp. Avg.*
2.76
2.64
2.83
2.91
2.93
Futures ($/MMBtu)
July Contract
3.008
2.999
2.982
3.042
3.020
August Contract
3.047
3.041
3.024
3.076
3.054
*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: (6/1/17 - 6/7/17)
Average daily values (Bcf/d):
this week
last week
last year
Marketed production
80.9
80.8
80.4
Dry production
71.9
71.7
71.5
Net Canada imports
5.6
5.5
5.8
LNG pipeline deliveries
0.0
0.0
0.0
Total supply
77.4
77.2
77.3

Source: OPIS PointLogic Energy, an IHS Company
Note: LNG pipeline deliveries represent gas sendout from LNG import terminals.

U.S. natural gas consumption - Gas Week: (6/1/17 - 6/7/17)
Average daily values (Bcf/d):
this week
last week
last year
U.S. consumption
54.2
53.4
58.1
    Power
26.5
24.0
31.0
    Industrial
19.8
19.9
19.6
    Residential/commercial
7.9
9.6
7.5
Mexico exports
3.7
4.0
3.7
Pipeline fuel use/losses
6.0
6.0
6.5
LNG pipeline receipts
2.2
1.6
0.5
Total demand
66.1
65.1
68.8

Source: OPIS PointLogic Energy, an IHS Company
Note: LNG pipeline receipts represent pipeline deliveries to LNG export terminals.

Natural gas supply


Weekly natural gas rig count and average Henry Hub
Rigs
Fri, June 02, 2017
Change from
 
last week
last year
Oil rigs
733
1.5%
125.5%
Natural gas rigs
182
-1.6%
122.0%
Note: Excludes any miscellaneous rigs
Rig numbers by type
Fri, June 02, 2017
Change from
 
last week
last year
Vertical
77
0.0%
71.1%
Horizontal
771
0.7%
141.7%
Directional
68
4.6%
54.5%
Source: Baker Hughes Inc.


Working gas in underground storage
Stocks
billion cubic feet (Bcf)
Region
2017-06-02
2017-05-26
change
East
457
419
38
Midwest
614
585
29
Mountain
172
166
6
Pacific
269
258
11
South Central
1,119
1,097
22
Total
2,631
2,525
106
Source: U.S. Energy Information Administration
Working gas in underground storage
Historical comparisons
Year ago
(6/2/16)
5-year average
(2012-2016)
Region
Stocks (Bcf)
% change
Stocks (Bcf)
% change
East
556
-17.8
506
-9.7
Midwest
676
-9.2
525
17.0
Mountain
182
-5.5
142
21.1
Pacific
307
-12.4
291
-7.6
South Central
1,242
-9.9
930
20.3
Total
2,963
-11.2
2,394
9.9
Source: U.S. Energy Information Administration


Temperature – heating & cooling degree days (week ending Jun 01)
 
HDD deviation from:
 
CDD deviation from:
Region
HDD Current
normal
last year
CDD Current
normal
last year
New England
50
15
48
0
-4
-32
Middle Atlantic
22
-4
21
1
-10
-57
E N Central
23
-8
21
6
-14
-46
W N Central
26
-1
18
16
-10
-18
South Atlantic
2
-7
2
65
10
-6
E S Central
2
-6
2
51
4
-18
W S Central
0
-1
0
87
11
2
Mountain
32
-8
-13
36
3
16
Pacific
9
-18
-9
4
-9
-3
United States
17
-7
9
30
-3
-20
Note: HDD = heating degree day; CDD = cooling degree day

Source: National Oceanic and Atmospheric Administration

Average temperature (°F)

7-Day Mean ending Jun 01, 2017

Mean Temperature (F) 7-Day Mean ending Jun 01, 2017

Source: NOAA National Weather Service

Deviation between average and normal (°F)

7-Day Mean ending Jun 01, 2017

Mean Temperature Anomaly (F) 7-Day Mean ending Jun 01, 2017

Source: NOAA National Weather Service