Rocky Mountain producers, facing ever-widening basis differentials, are cutting back on natural gas production due to a lack of immediate demand, as well as a deficit of storage facilities and takeaway capacity in the region, according to a veteran energy analyst. But most are seeing it as a short term phenomenum.
If you look at the cash markets today [last Thursday], you’d just simply retch,” with Rocky Mountain prices fetching between 65 cents to $1.06 compared to $5.81 at the Henry Hub, said John Olson, co-manager of Houston Energy Partners. “There’s nobody up there that I’m aware of who could make money producing gas at less than $3-4.”
There has been a “big air pocket in the gas market that has been painfully apparent for the last six or seven months because the basis differential between the Rockies and Henry Hub has been well over $3,” he noted.
Producers “are looking at pretty ugly basis differentials there,” and Olson does not expect the situation in the Rockies to get any better for at least another 60 days. He noted that 60 days is a long time for producers, especially “if you need the cash flow.” But “hopefully it’s going to get cold again beginning in November and the heating season will be upon us. That should start to stimulate the market,” he said.
In the meantime, “anybody who is unprotected via hedging is going to have to consider cutting back production substantially.” Natural gas prices have taken the severest beating in the Piceance Basin in southwestern Wyoming over into the Uinta Basin, and in the Powder River Basin in northeastern Wyoming, according to Olson.
One Rocky Mountain producer acknowledged that his company has shut in some production in an effort to balance supply and demand and match supply with limited pipeline capacity in the region. “It’s a difficult time,” he told NGI. But not as difficult as it has been on other occasions when prices cratered. For one thing, coming off a sustained period of higher prices most producers have their balance sheets in order, resisting impulses to borrow excessively or overspend. And, most also are playing the hedging game or have locked in price contracts.
One of the smaller Wyoming producers boasts it has 85% of its production locked in at an average price of $6.12/Mcf. “That’s higher than the Henry Hub is right now.” And there’s not much to indicate that the lower prices are cutting into exploration and development for future production. That company is just embarking on a major new drilling program.
Tulsa-based Williams, which has a lot of Rockies production, has firm transportation contracts to ensure its gas gets to market. That and hedging add up to about 93% of Williams’ U.S. gas getting better than Rockies prices (see separate story).
And, “while we are shutting in production, we are not saying right now that we’re cutting back on drilling activity,” another Rockies producer told NGI. “We’re still counting on REX [the Rockies Express Pipeline] being on time, and so far they’re on schedule. There’s just no reason to sell gas at $1.80 to $2, which is the price right now at Opal, when we could possibly get $6-$7 four or five months from now,” he said.
A spokesman for Calgary-based EnCana dismissed reports that it has curtailed production in the Piceance Basin and in Jonah Field in southwestern Wyoming. “We have established basis hedges to reduce the risk” of low prices, spokesman Alan Boras said. The second-quarter average basis hedge was 67 cents/MMBtu, which allowed EnCana to sell its gas for more than $5, he noted.
Some producers outside of the Rocky Mountains are curtailing production. Oklahoma-based Chesapeake Energy Corp. last week said it planned to reduce its natural gas output by roughly 125 MMcf/d, or about 6% of the company’s current net production, in response to low gas prices. The production cut would be focused in the Fort Worth Barnett Shale, South Texas, Deep Haley and Anadarko Basin areas (see related story).
The depressed price for Rocky Mountain gas is due to “an accumulated problem of gas storage levels rising faster than you’d like; producers were impacted by all of the LNG [liquefied natural gas] imports in the early summer; and there has been a very mild cooling season in most parts of the country. As a result, there has not been much in the way of air conditioning load,” Olson said.
“I think it’s mostly a lack of immediate demand coupled with lack of storage in the Rocky Mountains and lack of surplus takeaway capacity where producers can export” their gas to midwestern and eastern markets, he noted.
Olson expects the market for Rocky Mountain gas to significantly improve in January, when the second leg of the mammoth REX is scheduled to be completed. This leg, which will extend to Missouri, will provide Rocky Mountain producers with 1.5 Bcf/d of takeaway capacity.
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