Cabot Oil & Gas (COG) announced last week that it struck a gusher on its first horizontal well drilled in the Haynesville Shale in East Texas. However, with natural gas prices melting faster than spring ice on a pond — due to end of winter and warmer spring weather — the company could be forced to choke-off production volumes.

The King G.U. #1 (69 percent working interest), drilled in St. Augustine County, Texas, is currently producing at 19 million cubic feet (Mmcf) per day, according to Cabot chairman and chief executive officer Dan Dinges. Similar finds in nearby wells, however, suggest a dramatic decline in reservoir metrics. For example, in November 2009, Devon Energy (DVN) announced an average continuous 24-hour initial production flow rate of approximately 30.7 million cubic feet of natural gas equivalent per day from a Haynesville stake. After the first 90 days, the production curve had fallen some 90 percent to about three million cubic feet per day.

Cabot’s asset portfolio is spread principally between low-risk/long reserve-life (27 years) Appalachian assets (Marcellus Shale) and high-volume/rapid-payout (estimated reserve life of 13 years) prospects in the Gulf Coast (East and Southeast Texas).

Management forecasts that current annual production of 103 Bcfe (95% natural gas) from developed wells will decline at estimated rates of 20 percent and 12 percent during 2011 and 2012, according to the 2009 annual earnings filing with the SEC. Given an admitted shortage of hydraulic frac crews in Texas, combined with uncertainty in production curves, Cabot is focusing 69 percent, or $403.6 million, of its 2010 capital budget on expanding takeaway pipeline capacity and ramping up production at its core Marcellus holdings in Susquehanna county, PA, principally through drill-bit activity.

Demonstrated improvements in drilling efficiencies have led to drill-bit finding costs in the Marcellus of only $0.51 per Mmcfe, almost half the costs in East Texas. Chief executive officer Dinges also told energy analysts on Cabot’s fourth-quarter 2009 earnings call that well costs in Marcellus have stayed relatively constant between $3.5 million and $3.8 million, depending on the length of laterals and the number of stimulation stages. Helping keep a lid on costs, too, was a 69 percent reduction in completion time to an average of 21 days.

Depletion rates in the Northeast are less dramatic than those in the Haynesville Shale, with 2009 wellhead completions in the region yielding an IP average of 7.5 million per day and a 30-day average of 6.9 million cubic foot per day. Of significance, too, with predictable flow rates, estimated ultimate recovery has increased from 4.5 Bcfe to north of 5.5 Bcfe per well.

Despite its focus on Marcellus, Cabot has ambitious plans for its East Texas prospects, with participation in up to 12 additional Haynesville wells, with varying working interests (ranging from seven to 52 percent), during 2010. The company has budgeted about $181 million of capital funds for this region.

But other stuff is happening that could derail the company’s ambitious drill program this year. At the New York Mercantile Exchange, the May 2010 contract for natural gas settled at about $3.869 per million Btu last week — lower than Cabot’s estimated total cost of $4.55 - $5.05 per Mmcfe.

With only some 19 percent of 2010 production hedged (at an average price of $9.34), and natural gas prices unlikely to push higher until the colder weather of November approaches, Cabot will likely need to take on more debt (at present, 30.8% of total capitalization) — or slash its drill-bit ambitions this year. Another choice would be to simply choke-off capacity at more costly (but productive) wellheads like the Haynesville strike until market fundamentals — supply/demand imbalances — improve.

 

Buck