Energy Secretary Ernest Moniz and Rep. Tim Murphy (R-Pa.) kicked off a one-day public meeting in Pittsburgh July 21 on natural gas infrastructure issues as part of the Quadrennial Energy Review (QER).
The QER task force, as directed by President Obama, is taking a big picture look at national energy policy ranging from the electric power sector to petroleum and natural gas infrastructure issues. The Pittsburgh meeting focused on Natural Gas Transmission, Storage and Distribution.
In his opening remarks, Moniz said that the nation is already about halfway toward President Obama’s target of reducing carbon dioxide emissions from power plants by 30% by 2030. “And about half of that is due to natural gas,” Moniz said.
Murphy and other speakers said that Pennsylvania has become a major producer of natural gas thanks to the boom in Marcellus Shale output. The Energy Information Administration (EIA) said in December that the Marcellus region was now responsible for 18% of total U.S. gas production.
Speakers at the Pittsburgh conference said that feature could exceed 50% by 2040.
At the same time, “natural gas cannot replace nuclear and it cannot replace coal,” Murphy said. Murphy noted that a significant number of his constituents are in coal country and are concerned about retirement of too many coal-fired plants.
Moniz agreed that a balanced energy portfolio is vital. Moniz said the “polar vortex” of this past winter revealed that energy diversity is important, especially given the infrastructure constraints on natural gas.
A Department of Energy (DOE) briefing paper noted that the United States has more than 500 natural gas processing plants to separate dry natural gas from liquids. The nation also has about 419 underground natural gas storage facilities, most of which are primarily for seasonal use to meet winter demand, and the remaining are high deliverability facilities used to inject and withdraw large natural gas volumes flexibly for short periods.
Natural gas infrastructure in the United States is highly integrated with infrastructure in Canada and to a lesser extent with Mexico to form an integrated North American market.
The U.S. natural gas landscape has changed dramatically since 2004, according to the DOE document drafted for the meeting. In 2004 it was assumed that U.S. natural gas production was on the decline.
Developers had proposed 13 GW of new coal-fired capacity to take advantage of the large, long-lasting price advantage that even relatively expensive Appalachian coal enjoyed over natural gas a decade ago.
Spot gas prices at the Henry Hub averaged $5.91/mmBtu and during the winter of 2003-2004, pipeline constraints into New England led to spot prices as high as $74/mmBtu. Developers were also building a number of liquefied natural gas (LNG) facilities to import natural gas.
Then the shale revolution occurred. As a result there has been a 35% rise in dry natural gas production between 2005 and 2013, about a 55% fall in average annual spot natural gas prices, an approximately 39% increase in the use of natural gas to generate electric power, DOE said.
Developers are also now looking at substantial exports of LNG from the United States and North America.
“Geographically, increased shale production has come in a series of waves. From 2005 until 2009, most of the increase came from the Barnett formation in east Texas,” DOE reported.
“Beginning in 2009, production stabilized in the Barnett, and increased rapidly in the Haynesville formation in Louisiana and east Texas,” according to the DOE document. “Beginning in 2012, production gains shifted to very rapid growth in the Marcellus formation in the Northeast and the Eagle Ford formation in Texas. Meanwhile, Haynesville production fell as producers moved to the more profitable basins.”
Gas claims bigger chunk of power generation
In April 2012, EIA reported that monthly shares of coal- and natural gas-fired generation were equal for the first time. In addition, natural gas power plants accounted for just over 50% of new utility-scale generating capacity added in 2013, according to the DOE report.
In general, neither natural gas nor Eastern coal has been able to establish and maintain a consistent pricing advantage over the other fuel. Total U.S. natural gas use for power generation was actually down 11% in 2013 compared to 2012, mostly because of higher natural gas prices relative to coal prices.
But gas use for power generation has generally been on the rise since 2008.
Accommodating growth in natural gas use for power will likely require changes to natural gas infrastructure: repurposing and reversals of existing pipelines; laterals to gas-fired generators; more looping and compression to the existing network; possibly some new pipelines; and additional processing plants and high deliverability storage, according to the DOE brief.
EIA estimates that between 2004 and 2013, the natural gas industry spent about $56bn expanding the natural gas pipeline grid. Even with this new capacity, over 1,800 wells in the Utica and Marcellus are drilled but not producing due to infrastructure constraints; those wells have an estimated production capacity of 10 Bcf/d, according to DOE.
There are several questions posed by the growing use of shale gas in power generation, DOE said.
Who should pay for new pipeline capacity and how should those costs be allocated? How can electricity markets incentivize flexibility and reliability of gas-fired generators, to ensure they have fuel when they are most needed? Also, what new gas infrastructure, if any, will be needed to backstop growth in intermittent supplies like wind and solar generation?