Despite a year of languishing natural gas prices, Cabot Oil & Gas Corp. annual revenues for the first time surpassed $1 billion in 2012. Cash flow set records as proved reserves grew by 27% to 3.8 Tcf on organic growth that replaced 417% of record production. The Marcellus Shale gave much despite infrastructure challenges.

According to data from the state of Pennsylvania, Cabot had 15 of the top 20 producing Marcellus wells in the state last year. The company’s cumulative production from the play has reached 500 Bcf in four years of activity. Gross production is hovering around 1 Bcf/d and reached a record 1.038 Bcf/d during one 24-hour period last year, the company said. And there’s more to come.

“Our team, in conjunction with our service partners, has done a tremendous job making a step change in our Marcellus operations during 2012,” said Cabot CEO Dan O. Dinges. “We have thousands of locations in front of us along with ongoing infrastructure expansion plans in place to aid with this continued momentum.

“While we derive value from each of our plays, the Marcellus continues to be the primary contributor to our recent success.”

Overall, all-source finding cost was 87 cents/Mcfe last year, but it was 49 cents/Mcf in the Marcellus, Dinges told analysts Friday during an earnings conference call.

The company’s 41 wells completed and brought online in the Marcellus last year have a 13.9 estimated ultimate recovery (EUR) average. Cabot has 10 wells in the play with EURs higher than 20 Bcf.

“In addition, Cabot continues to de-risk its acreage with the recent post-completion flowback results from a pad location on the farthest eastern edge of its acreage position, which are consistent with the Zick area wells,” the company said. “These wells represent a nine-mile step-out from the company’s Zick area and are currently waiting on pipeline, which is scheduled to arrive in the fourth quarter as planned.” Last year Cabot also cut costs for Marcellus well stimulation, reducing costs per stage by 15-20%.

Cabot isn’t the only producer faring well in the Marcellus. For instance, Southwestern Energy Co. also is making its way there despite low gas prices (see Shale Daily, Feb. 22).

Cabot’s overall production also set a record of 267.7 Bcfe, an increase of 43% over 2011, the second consecutive year of a more than 40% increase. Revenues were $1.2 billion.

Net income last year was $131.7 million (63 cents/share) compared to $122.4 million (59 cents/share) in 2011. Excluding special items, adjusted income was $138.9 million (66 cents/share) compared to $139.2 million (67 cents/share) in 2011, with the decrease due mainly to a change in the treatment of deferred income taxes.

Natural gas price realizations, including the effect of hedges, were $3.67/Mcf, down 18% compared to 2011. Oil price realizations, including the effect of hedges, were $101.65/bbl, up 12% compared to 2011.

For this year Cabot’s $1 billion capital plan remains unchanged from prior guidance, with about 65% allocated to the Marcellus, 30% to oil initiatives in Texas and Oklahoma and the remaining 5% to new opportunities. The capital program is expected to be fully funded by cash flow while generating 35-50% production growth and double-digit reserve growth, Cabot said.

In the Eagle Ford Shale, Cabot said its 400-foot downs-pacing program continues to be successful, maintaining a range of EURs between 350,000 and 500,000 boe per well, depending on lateral length. Cabot said it continues to see improvements in EUR per lateral foot as the company refines its lateral placement and completion techniques.

In the Pearsall Shale, to date nine wells have been drilled with five wells producing, four wells completing or waiting on completion and three wells drilling. “We continue to refine the process of determining the best place to land the laterals in the prospective interval,” said Dinges. “This exploitation project, like the Marmaton before it, requires considerable engineering to optimize cost and well performance.”

In the Marmaton formation, three extended-reach horizontal wells with laterals of about 9,500 feet have an average EUR of 230,000 boe with drilling costs between $4.3 million and $4.5 million, Cabot said. The average initial production rate from the three wells has been 792 boe/d with a 90% oil cut. “This rate does not match our best well in the play, but the profile has been flat after inclining for a period of time,” said Dinges. “We are cautiously optimistic about the well performance and based on the first full year of our Marmaton program we are seeing returns that are consistent with our Eagle Ford program.”