It’s no mystery that increasing supplies of natural gas in the U.S Lower 48 have contributed to serious erosion in gas prices. Perhaps less obvious is that major technological advancements in tools that better extract gas from the numerous shale deposits underlying the continent, which are easy to find but can be difficult to produce from, have contributed to the price deterioration.
Since hitting a high of more than $13 per thousand cubic feet in the early part of July, natural gas prices have plummeted more than 40 percent to their current level of around $7/Mcf.
In fact, the market is so awash in natural gas that Chesapeake Energy, among the largest gas producers in the United States and a major shale player, announced Sept. 22 that it planned to reduce its drilling budget during the second half of 2008 through year-end 2010 by $3.2 billion, or 17 percent, in response to the price decline and concerns of “an emerging U.S. natural gas surplus …”
Just how long this price downturn will last, and whether it threatens any long-term conventional gas projects, such as Alaska’s proposed gas pipeline system, is anybody’s guess. It largely hangs on future demand, which some hope will lead to a mass conversion to natural gas vehicles and gas-fired industrial plants to reduce America’s dependence on oil imports.
A recent study by Navigant Consulting for the American Clean Skies Foundation concluded the United States has up to 50 percent more natural gas reserves — or 2,247 trillion cubic feet — than some earlier projections because of higher-than-expected yields from 22 shale formations in 20 states.
U.S. domestic gas production, a good indicator of where prices are headed, at least in the short term, was up 8.8 percent in the first half of this year compared with the same period a year earlier. That rate of increase was last seen in 1959, during the great drilling boom that followed World War II. The increase in gas production stands in sharp contrast to the trend in domestic oil production, which has been declining steadily since 1970 and dropped 21 percent in the past decade alone.
Technology advances boost shale gas output
Among the largest shale fields contributing to the sharp increase in U.S. natural gas production is the Barnett Shale region around Fort Worth, Texas, which has been under development for several years. Big exploration and production independent Devon Energy, by far the largest producer in the Barnett, has been a key player in unlocking secrets associated with gas shale.
Devon helped champion innovations in technology that literally cracked open the shale to release the natural gas sealed inside. Engineers use a method known as fracturing to foster permeability in the shale. Crews inject a mixture of fresh water and sand into the rock at high pressure to fracture the formation and release gas trapped inside.
This new twist to hydraulic fracturing, along with horizontal drilling adaptations to capture more of the reservoir per well, has given Devon access to vast reserves in the Barnett, transforming this challenging play into one of the nation’s most important natural-gas producing fields. Today, Devon alone accounts for nearly a quarter of the Barnett’s overall daily production of more than 4 billion cubic feet, roughly the amount of gas that would be transported daily from Alaska’s North Slope to Lower 48 markets, via a mega-pipeline system that no doubt would be gas-price sensitive due to its projected cost of up to $30 billion.
Records show that there are more than 35,000 producing gas shale wells in the United States, with cumulative production of about 600 Bcf per year, according to College Oak Investments LLC, which formed a joint venture and financed 10 wells to pursue the New Albany Shale, which the group says contains as much as 86 Tcf.
A recent Deutsche Bank report forecasts that production from the eight largest shale fields could hit 6.6 Bcf /d this year, or 11.8 percent, of national gas production, and then rise to 14.5 Bcf/d, or 23 percent, of U.S. production, in the next three years.
Total U.S. gas shale resources are estimated to be between 500 Tcf and 600 Tcf, though some estimates range much higher. And this does not include additional trillions of cubic feet of estimated resources in other unconventional gas plays, such as coalbed methane and tight sandstones. So, with at least 27 shale deposits (see map), the Barnett Shale field, as big as it is with a wide-ranging resource base of 25-225 Tcf, is certainly not the only shale game on the U.S. continent.
Majors move into shale gas plays
These days one natural gas play, in particular, has producers jumping with excitement — the Haynesville Shale, which sits at a depth of around 11,000 feet stretching from East Texas into northwest Louisiana. Conservative estimates place Haynesville reserves at around 168 Tcf, certainly ranking it among the largest known U.S. onshore natural gas fields. Multitudes of companies are snatching up acreage in the area, though it’s probably too early to tell how much gas can actually be recovered.
For the most part, independent producers such as Devon, Chesapeake, Anadarko Petroleum and XTO Energy have dominated the shale scene in the United States. What’s interesting and somewhat perplexing has been the recent purchases of acreage in some of the newer gas shale plays, including Fayetteville Shale in Arkansas, by major oil companies.
The most recent deal was BP’s purchase of about 400,000 acres in the Fayetteville Shale for $1.9 billion from Chesapeake. A month earlier Chesapeake closed the sale of its Arkoma Basin Woodford Shale assets in Oklahoma to BP for $1.7 billion. The latest transaction was structured not only as an asset purchase ($1.1 billion), but also as a finance commitment for drilling in the Fayetteville. BP agreed to pay $800 million of the cost to drill and complete wells in the field.
Chesapeake said a separate joint venture with Plains Exploration and Production in the Haynesville Shale, coupled with the BP Fayetteville Shale joint venture, would pay for about $2.5 billion of Chesapeake’s drilling and completion expenditures planned for the second half of 2008 through 2010.
“Together with our substantial position in the emerging Haynesville Shale play in East Texas, BP has made a strategic entry into three top-tier shale plays in North America and established potential shale resources of 1 billion barrels oil equivalent net to BP,” said Andy Inglis, BP’s chief executive of exploration and production.
However, Chesapeake’s decision to slash its capital budget due to a natural gas glut undoubtedly will affect its various shale joint ventures. Of the overall $3.2 billion reduction, $1.9 billion “is attributable to reduced drilling activity,” Chesapeake said, noting that it will reduce its current operated drilling rig count of 157 rigs to about 140 rigs by the end of this year and expects to keep its rig count relatively flat through 2009 and 2010.
In addition, Chesapeake said it elected to curtail a portion of its un-hedged natural gas production in the Mid-Continent region “due to unusually weak wellhead natural gas prices that are substantially below industry breakeven costs.” The curtailment amounts to 100 Mmcf/d of net natural gas output. However, Chesapeake said it would restore the production once natural gas prices recover from recently depressed wellhead price levels of $3-$5/Mcf. The curtailment represents just 4 percent of the company’s current net natural gas and oil production capacity of more than 2.3 Bcfe/d.
Additionally, as a result of reduced drilling activity levels, Chesapeake lowered its anticipated annual production growth forecasts in 2009 and 2010 to 16 percent from 19 percent.
