Study projects $205.2 billion in midstream gas outlays by 2035
An average $8.2 billion/year will have to be spent by 2035 for the US and Canada to accommodate new natural gas supplies, particularly from prolific shale plays, and meet growing demand, a study commissioned by the INGAA Foundation concluded.
OGJ Washington Editor
WASHINGTON, DC, June 28 -- An average $8.2 billion/year will have to be spent by 2035 for the US and Canada to accommodate new natural gas supplies, particularly from prolific shale plays, and meet growing demand, a study commissioned by the INGAA Foundation concluded.
Some $205.2 billion will be needed for mainlines, laterals, processing, storage, compression, and gathering lines, it indicated.
“We think the numbers for capital requirements are achievable,” INGAA Foundation Pres. Donald F. Santa told reporters. “We’re very confident the pipeline and storage segment can do its part to realize North America’s natural gas potential.”
The study by ICF International updated one in October 2009 for the foundation, which is associated with the Interstate Natural Gas Association of America. Santa, also INGAA president, said the update came after less than 2 years, instead of the usual 4, because the North American gas supply situation has changed so dramatically as more gas is recovered from previously inaccessible tight shale formations.
The INGAA Foundation’s latest North America midstream outlook also looked at natural gas liquid and crude oil systems associated with gas development for the first time, he added.
It predicted by 2035, 43 bcfd of additional interregional pipeline capacity will be required, along with 35,600 miles of transmission mainline; 13,900 miles of laterals to and from power plants (where most of the new demand will occur), storage fields, and processing plants; 414,000 miles of gathering lines; 4.9 million hp more of compression capacity; another 589 bcf of working gas storage; and an additional 32.5 bcf of processing capacity.
Gas capital requirements totaling $205.2 billion in the next 25 years will include $97.7 billion for mainlines, $29.8 billion for laterals, $41.7 billion for gathering lines, $9.1 billion for pipeline compression, $4.8 billion for storage fields, and $22.1 billion for additional processing capacity, the study indicated.
Associated NGL and oil capital requirements during that same period will include $14.5 billion for another 12,500 miles of NGL transmission mainline, and $31.4 billion for 19,300 miles of new oil mainline, it continued.
The study’s reference case assumes US economic growth of 2.8%/year, crude oil prices averaging about $80/bbl in real terms, US population growth averaging about 1%/year, and electric load growth averaging 1.3%/year, according to Bruce Henning, vice-president of energy regulatory affairs and market analysis within ICF’s fuels group and one of the study’s authors. The reference case also projects real gas prices will rise from $4 to $6-7/MMBtu by 2035, high enough to encourage significant gas supply development, but not so high that it limits market growth significantly, he said.
Total US and Canadian shale gas production is expected to grow from 13 bcfd in 2010 to 52 bcfd by 2035, Henning said, adding that shale play development continued during the 2008-09 recession despite relatively low gas prices. “Our Marcellus shale growth forecast assumes the number of wells will stay at their levels at the end of 2010, and no development in New York,” he told reporters.
There also will be demand for pipeline capacity to transport or process NGLs recovered from wet gas produced from many shale formations, noted Harry Vidas, an ICF upstream supply and economics specialist who wrote the report’s section on anticipated NGLs and crude oil needs. “The expenditures are going to be quite large,” he said. “Almost all of the plays have wet components which have to be removed and sold before the gas is dry enough to put into a pipeline.” He said there will be markets for propane and butane in the east, but not for ethane, which makes a pipeline or local cracking capacity likely.
Vidas said as Alaskan oil production declines, US West Coast refineries will need to get crude feedstock elsewhere and likely will turn to crude recovered from Alberta’s oil sands, shipped by pipeline to a British Columbia port, and loaded onto tankers bound for refineries in California and Washington. New crude production from the Bakken and Three Forks shale formations in North Dakota and Montana, and the Niobrara shale in the Denver, Powder River, and Green River Basins of Wyoming and Colorado also will support demand for another 5 million b/d of crude pipeline capacity by 2035, he said.
“In order to have this happen, infrastructure will have to be built to deliver all this new production to markets,” said Henning. “There are substantial requirements through the entire natural gas value chain that will demand substantial amounts of capital.”
Santa said the gas midstream segment has benefited from being able to use master limited partnerships to raise capital in the past. “This could change if the tax laws are changed,” he conceded. But he also said that midstream gas’s record of successfully lining up financing suggests investors in pipe mills and compressor manufacturers can feel secure because the demand for gas will be there.
“These are big dollar investment projects, but not that big within overall financial markets,” Henning added.
As production has moved to liquids-rich plays because of favorable market signals, pipeline system growth will be more complicated because more NGL and crude capacity will be needed, Santa observed.
The result could be a move toward a single North American gas market with more competitive pricing because there would be so much transportation, storage, and processing systems, he said. “We’re very confident the pipeline and gas storage segment can do its part in realizing North America’s gas potential in the next 25 years,” Santa said.
Contact Nick Snow at email@example.com.