With most U.S.-based exploration and production (E&P) companies weighted 70% or more to natural gas, “taking advantage of pricing disparity toward natural gas liquids [NGL] continues to lead E&Ps to process more of their gas,” Madison Williams & Co. analyst Andrew Coleman said Friday.
“Every day is a day closer to gas rebalancing,” said Coleman, who took over as senior E&P research analyst for the private investment firm in May. “Some two years on from gas prices peaking, we are still watching for production to roll over. Rig counts aren’t helping, as management teams continue to drill to hold acreage. But given the growth of the NGL market, allocation of horizontal rigs to oil plays, a falling forward curve, and depressingly negative sentiment, maybe this time it will occur.”
Gas storage has put a floor on gas prices in the short term, he noted.
“Entering the shoulder season, gas storage looks tight in the western U.S. Still, the West accounts for only about 15% of total storage volumes. While the early part of the summer was warmer-than-normal — outside of a few states along the Gulf Coast — on a degree day basis, the country has trended at near-normal levels. So with gas storage not expected to test the limits of storage, we feel the bottom of gas pricing has firmed.”
The gas rig count “likely” peaked in August at around 1,650 rigs (55% horizontal and 40% oil), he said. “Ongoing backlog issues associated with access to stimulation equipment may ultimately limit how quickly this new production gets to market in some basins. Footage drilled, which we feel is a better normalized predictor of industry activity, is also rising.”
Today “feels like a repeat of rig activity between 1982 and 1986,” said the analyst. “Fortunately, higher underlying declines in North American basins (e.g., shales) may prove to be enough of a great equalizer for supply side-questions. If not, at some point over the next 12 to 24 months — without a pronounced supply decline or a pick-up in demand — it could get ugly.”
At $4/MMBtu gas prices, “many plays” generate internal rates of return (IRRs) under 40% before tax (under 25% after tax) even though finding and development costs remain attractive, which highlights “the disconnect between cash returns and accounting metrics. Delays in stimulating wells would also affect IRRs. Once key shale acreage has been held by production, drilling programs are expected to slow, but that might not occur until 2011 at the earliest.”
If ethane rejection dampens enthusiasm in the natural gas liquids market (see related story), “producers might cut back,” said Coleman. “Some 24 months after commodity prices peaked in July 2008, gas investors are still waiting for a sign that reported declines are meaningful and occurring.”
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