Natural Gas Pipelines to Expand U.S. Supply Glut: Energy Markets


 
 

Natural gas pipelines coming into service by year end may boost deliveries from the Marcellus shale deposit in the U.S. Northeast by 30 percent, extending a supply glut that helped send prices to decade lows.

As much as 2 billion cubic feet of gas a day are set to flow from the lines in Pennsylvania, Ohio and West Virginia, bound for markets along the Eastern Seaboard, based on government and pipeline-company projections. About 1,000 Marcellus shale wells sit uncompleted, mainly because of a lack of pipeline infrastructure, according to the Energy Department.

Natural Gas Pipelines to Expand U.S. Supply Glut

Natural Gas Pipelines to Expand U.S. Supply Glut

Julia Schmalz/Bloomberg

Shale gas has been key to the country’s move toward energy independence.

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Gas prices have dropped 60 percent since 2007 as producers used techniques such as hydraulic fracturing, or fracking, to reach supplies trapped deep in tight layers of shale. Gas futures tumbled to $1.902 per million British thermal units in April, the lowest price since 2002, as stockpiles ballooned during a mild winter and record U.S. production.

“There are new pipelines coming up and more Marcellus gas is going to flood storage going into winter,” Phil Flynn, senior market analyst at Price Futures Group in Chicago, said in a phone interview. “Unless you get a really cold winter, prices are going to be in the $2 range.”

Natural gas for October delivery rose 9.9 cents, or 3.4 percent, to settle at $3.023 per million British thermal units on the New York Mercantile Exchange. Prices have gained 1.1 percent this year.

The futures have averaged $2.679 since the April low after rising as high as $3.277. Prices may average $3.20 per million Btu during the first quarter of 2013, when demand peaks, based on the median of 18 analyst estimates compiled by Bloomberg.

Winter Demand

“Higher prices are all predicated on more normal space heating” this winter and demand from power generators burning gas instead of coal, Teri Viswanath, director of commodities strategy at BNP Paribas SA in New York, said in a Sept. 21 interview. Viswanath expects first-quarter prices to average $3.60 per million Btu.

Cabot Oil & Gas Corp., which pumps gas from Marcellus deposits in Pennsylvania, has a break-even point that’s“probably below $2,” Chief Financial Officer Scott Schroeder said in a Sept. 14 interview from Houston.

About 4,525 miles of interstate gas pipelines serving consumers from Maine to Virginia have been put into service since 1996, Energy Department data show. About 693 miles of lines in the Marcellus, with a daily capacity of 8.06 billion cubic feet, are planned, under construction or already in service, according to Federal Energy Regulatory Commission data going back to 2006.

Fall Completions

New pipelines can quickly add 1 billion cubic feet a day of Marcellus gas to the market and as much as 2 billion, as projects with 3.5 billion cubic feet of additional pipeline capacity will be completed from September through December, Viswanath said. Marcellus gas output in May averaged 6.85 billion cubic feet a day, according to the most recent Energy Department data.

Shale gas has been key to the country’s move toward energy independence. Production gains helped the U.S. meet 81 percent of its energy demand in 2011, the highest level since 1992, according to U.S. Energy Department data compiled by Bloomberg.

Stockpiles in the week ended Sept. 14 totaled 3.496 billion cubic feet, 8.6 percent above the five-year average, the Energy Department said on Sept. 20. Supplies of gas may rise to a record 3.95 trillion by the end of October, before demand begins to rise with colder weather, according to department estimates.

Mid-Atlantic Lines

Spectra Energy Corp.’s (SE) Texas Eastern Transmission pipeline has a project that will go into service in November to carry 200,000 dekatherms (200 million cubic feet) a day from West Virginia to eastern Pennsylvania to connect to mid-Atlantic points, Brian McKerlie, vice president of business development at Spectra in Houston, said in a Sept. 19 interview.

Spectra is also building a pipeline to ship Marcellus gas to Manhattan by next November and is seeking customers to build a line to Florida, according to the company.

TransCanada Corp. (TRP), based in Calgary, is reversing its Niagara pipeline to start moving Marcellus gas from West Virginia into southern Ontario in November, Karl Johannson, executive vice president of natural gas pipelines with TransCanada, said in a Sept. 19 interview.

“It’s a very large resource and it’s going to change the flow of gas in North America,” Johannson said.

Williams Cos. projected that more than half of its estimated $11.5 billion of capital investments from 2012 through 2014 is in the Marcellus region, according to a Sept. 5 presentation by the Tulsa, Oklahoma-based company.

Rising Production

Kinder Morgan Energy Partners LP (KMP)’s Tennessee Gas Pipeline and a unit of Dominion Resources Inc. also have Marcellus projects under construction.

Marcellus will account for 22 percent of the 79 billion cubic feet a day of U.S. gas output in 2016, or about 17.4 billion a day, according to Goldman Sachs Group Inc. estimates. The region accounted for 5 percent of output last year and none in 2006, the bank’s data show.

Barclays Plc estimates that additional pipeline capacity may boost daily U.S. supplies by 1.8 billion cubic feet by the end of this year and by another 3.4 billion in 2013, the majority of it from Marcellus.

“We will be watching for evidence of a large uptick in production” in November, March and November 2013, Shiyang Wang, a Barclays analyst in New York, said in an Aug. 28 report.

Winter Demand

Laurent Key, a natural gas analyst with Societe Generale in New York, predicts that 900 million cubic feet a day of Marcellus production will come online in the fourth quarter, according to a Sept. 10 note to clients. Key’s first quarter price forecast is $3.07.

Demand for the fuel used by power plants and in home heating peaks in January and February, though last winter’s mildest weather since 2000 has helped keep inventory levels atseasonal records.

The movement of drilling rigs to the Eagle Ford shale in Texas from Haynesville in Louisiana will slow U.S. natural-gas output growth, David Greely, head of energy research at Goldman Sachs in New York, said in a Sept. 24 research report.

The additional capacity in Pennsylvania will cut pipeline costs, Richard Hunter, vice president of investor relations with Carrizo Oil & Gas Inc. in Houston, said in an Aug. 28 interview. Charges in Pennsylvania, where the company has wells, rose as high as $1.40 per thousand cubic feet recently, about double the rate before it started to run up in mid-2012, Hunter said.

“Starting in November of this year to December, that price is going to fall dramatically on new pipeline capacity,” to 50 or 75 cents per thousand cubic feet, he said.

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I think some folks are missing the boat on continued declines in the Haynesville - the movement of rigs and decline in completion backlog have already happened...  

The September LA. Haynesville numbers will be out soon.  It will be interesting to see if wells waiting on completion have declined significantly below the 205 reported at the end of August.  Permits may bring a surprise.  August HA permits were up 37% over July.  I'm seeing a surprising number of recent HA permits for unit wells.  Leasing was still going strong two and a half years ago and companies with proven acreage will likely drill required unit wells regardless of the market.

Sept. HA Unit Wells (not Alternate Unit Wells) Permitted To Date:  Caddo - 1, DeSoto - 9 and Sabine - 2.

Have you seen many extentions of those leases?  

The few sections from Barksdale to Caplis Sligo on Sligo Road have been extended for 2 years.

I haven't checked the leases, Bobi.  Just noticed a spurt in unit wells that may indicate primary lease terms nearing expiration in the southern end of the play.  Extensions may not be well received everywhere and operators will likely find room in budgets to hold acreage in areas they have already proved up.  They know the glut will not last forever and the asset is too valuable to loose.

Skip---you have any ideal the number of wells or units that must be drilled to simply hold present leases (HBP) in HA ?

Nope.  You'd think we would be at or very near the end  of drilling to HBP at this stage but it appears that several operators are waiting until the eleventh hour to drill their remaining inventory of leases approaching expiration.  A reasonable strategy IMO.  And another factor in the rather slow rate of decline in LA HA production.

Skip-- is slow decline in production due to simply new wells keeping up or are the wells production in HA holding production better than originally projected due to chocking back plus other tech learning with drilling and fac

Some combination.  It may be more helpful to think of LA HA production in terms of localized take away capacity as opposed to actual well production.  A gathering system has a finite capacity.  And all the wells depending on that system for market access must be managed (choked) in such a way as not to exceed that capacity.  New wells must flow into systems that may be already at or near optimum take away. 

There are numerous variables that operators must take into consideration.  An example of one which we rarely delve into is compression.  One of the advantages of HA gas is that it flows for a long time at pressures greater than that required to be introduced into long distance pipelines.  The operators delay incurring the cost of compression by managing the pressure declines in their wells.

Some gathering systems may not fall below capacity for many months after the last well is placed on line.  Although all the wells on that system are declining, their production rates will likely be managed so that the system stays at or near capacity as long as possible.

Skip---I know this question maybe difficult to answer but assuming no new wells in system how long can operators (with the compression  edge that HA wells high natural pressure have) maintain full capacity before you begin to see supply into system start the rapid decline rate that has been quoted on individual well ( i.e. up to 90% after one year) Would like maybe a Just in you opinion answer. Also assume no new take away capacity of new pipelines coming into play.

In the past couple of weeks I have had folks in the South end of the Dolet Land Grant that I leasesd 3 years ago call and tell me that Petrohawk didn't pull the trigger on the extension option. The bonus for 3 years was $3000 and the 2 year extension was $3000. This would be in T11N-R11W.

Gathering systems vary in design and capacity so there's no way to answer such a question.  Keep in mind that the well IPs were a 24 hour test and that many wells have been choked back since then not because of price but as a requirement to flow new wells on the same system.  I don't think you can assume an overall decline rate but if you did it would be far south of 90%.  Maybe much closer to 50% since most operators instituted restricted rate production programs several years ago.  If you asked every major HA operator questions regarding production management and take away capacity I suspect you'd get different answers from each.

Skip--thanks I understand it was a "no way to answer question" but I was interested in your thoughts for it makes for a interesting discussion as part of the Big Picture of Market Forces on Nat Gas Supply/Demand--- if after that end point ( Falling below capacity) occurred a 50% decline after one year would really bring back activity very fast I bet.

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