Rick Smead, a director in Navigant Consulting Inc.’s Energy Practice, co-authored the firm’s 2008 North American Natural Gas Supply Assessment, which was considered a breakthrough in recognizing the potential of unconventional natural gas supplies. However, many of the two-year-old supply assumptions already need to be updated because of remarkable advancements in technology, he said Wednesday.
Smead shared his insight into the tremendous changes in the U.S. gas supply picture as part of a panel discussion at the World Shale Gas Conference & Exhibition in Grapevine, TX.
“This is very much an industry in the middle of a lot of change,” Smead said to a standing room only crowd. “This industry has just been in a state of shock for a while. In 2008 gas was seen as a depleting resource…There were 54 receiving terminals proposed for LNG…Russians were building huge pipelines. All of the building was around the notion that gas was scarce. Now we know that’s not true. The world has an abundance of supply, for well over a century.
“There are a lot of debates about the perils of oversupply, market disconnect. We’re in a situation where the world faces long-term energy prices driven by carbon concerns while at the same time we have an abundance of the lowest-emitting carbon fuel. How do we solve that problem? We have to use it effectively.
“There’s been a huge change in two years,” said Smead. “We still have debates about how robust the resource base is, and trauma on the transportation link from Point A to Point B. The industry is still adjusting. The consuming markets that have made decisions in the past about [viewing gas as a] depleting resource are still working their way around to trust it…But we have to pull forth the resources to support it.”
Because U.S. gas supplies have grown so quickly, it’s difficult to determine how much potential there is, said Smead. But he said, somewhat tongue in cheek, “to keep things simple: there is really, really a lot.”
The United States is “very far along” in shale development, which may be translated into developing global shale resources. However, it’s still too early to determine how much of the shale underlying other parts of the world will be economic. Some estimates put global shale resources at 16,000 Tcf, said Smead. “But it’s important to note that this is gas in place. How much can you really get? The challenge is to know how much can be recovered.”
For instance, in the United States the shale gas reserves estimates continue to move upward. “What we have is a rapid movement of the boundary of what’s there versus what’s recoverable. Every technical advance is changing that faster than we can think about it. Every improvement in horizontal drilling, completing laterals in formations, every improvement in fracturing technology…Everything that causes the initial production rate to be higher in shale plays dramatically increases the percentage of total resource base that can be recovered.”
That means that on a global basis, “there could be more recoverable reserves. It keeps increasing,” said Smead.
“In the United States, how wrong we have been,” he said. The Energy Information Administration, he noted, has kept track of shale production for a long time. Just four years ago it reported that production was going up but predicted that supplies would flatten out. “This year they changed their outlook and said shale gas was very robust and would reach 16 Bcf/d by 2030, or 25% of current production…”
However, “we are presently producing 13 Bcf/d from the major shale plays, a four power exponential rate of growth,” said Smead. “Can we keep doing that? A lot of people think we can. Drilling went down a lot in 2008…It takes a lot to slow down independent producers…[like] a complete global meltdown…a freeze on capital. But it didn’t stop them. It caused the total rig count to drop from 1,600 to 600…but horizontal rigs are 40% above where they were in 2008. Development is continuing very rapidly.”
Smead said the “industry is together on the notion that there’s probably at least 100 years of gas out there, if the market and development can work to produce it. Meanwhile, one of the beauties of big shale basins aligns with infrastructure…we have to build some infrastructure but not the equivalent of the Alaska gas pipeline…It’s tremendously convenient.
“The Marcellus Shale, which is potentially the largest of all, is in the middle of a market area. It’s been called ‘Prudhoe Bay on the Pittsburgh.’ It’s a really nice resource.”
Smead noted how dramatically onshore gas production has affected the U.S. supply picture.
“In 2005 we had two hurricanes, Katrina and Rita, and there was a big drop in production…When the production drop happened, prices tripled, then we had an enormous winter. When there is no supply and a winter, that’s a good thing for the gas industry.”
In 2008 two more hurricanes in the Gulf of Mexico impacted U.S. gas and oil supplies: Gustav and Ike. “They took out exactly the same amount of [gas] production. But prices went down. Between 2005 and 2008 we had completely replaced the offshore production with onshore production…”
Meanwhile, because of the economic climate of the last few years, “things have flattened out, and it’s working its way up again. We are seeing a very healthy supply and we’re basically secure from hurricane impacts on the gas market.”
However, the gas market faces several challenges, said Smead. “Land impact, water issues and hydraulic fracturing are tough issues that have to be resolved,” he said. And gas prices are a big dilemma. During the morning’s keynote sessions, Chesapeake Energy Corp. CEO Aubrey McClendon said his company needed $6/Mcf gas prices for shale gas development. But as Smead noted, some plays will require higher prices, while some will be lower. Technology advances have led to lower costs to produce.
“Anything that causes the initial production rate to go up, causes prices to go down. $3 is not stable, and producers are beginning to turn to oil. A lot of producers are doing that because gas is not nearly as profitable. Up until now it’s been about the need to retain leases…sweet spots kept development going at a high pace…”
Navigant has “explored” prices by looking at the historical data and talking with producers, he said. “We ultimately came to the conclusion that in the $5 to $7 range everything could work…We came to that conclusion based on our observation of the market. But we can’t tell other than watching what producers really do…Producers signed a lot of leases requiring them to drill within a period of time…Second, they confined their drilling to the best parts of the play, which kept prices lower…Third, especially in plays like the Marcellus, Eagle Ford, drilling is very oriented to wet gas, natural gas liquids [NGL].
“They are making money off NGLs to the point where NGL markets may become oversupplied…All of those factors combine still make it attractive to drill for a while. When producers like Chesapeake make the decision to drill for oil, it won’t take effect until 2011 so there’s a lag in prices. By the same token, when producers started doing these wells it got to where 1-2 MMcf/d was no big deal. Now the shale wells are producing 5-10 MMcf/d. When that happens, prices drop almost proportionally with deliverability. Then prices are closer to $4 than $6. The incentive starts diminishing when you get in some parts of the shale plays that are more difficult to produce, where it’s harder to fracture.”
Asked when gas drilling may become more discretionary in the United States, Smead said “we’re right at the point where initial drilling and commitment to leases…to hold the leases…has pretty much been exhausted. It is very clear to me that drilling for gas becomes pretty discretionary as of next year.”
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