Current GDP Stock Info

Goodrich Petroleum (ticker: GDP) is an independent oil and gas exploration and production company with operations in the Eagle Ford Shale, Haynesville Shale and Tuscaloosa Marine Shale (TMS). Along with Encana (ticker: ECA), Goodrich has been a pioneer of the new TMS area in Louisiana and Mississippi.

Putting Their Money Where Their Mouth Is

On July 22, 2013, GDP announced the purchase of 66.7% working interest in 277,000 gross (185,000 net) acres in the Tuscaloosa Marine Shale for $26.7 million. The seller will retain the remaining working interest of 33.3% of operations and continues participating with GDP in the new acreage and assets. The seller was not disclosed.  At closing, GDP will hold 320,000 net acres in the TMS.  The properties were producing 750 BOPED gross which equates to approximately $54,400 per flowing BOEPD on a GDP net basis. As of July 19, 2013, GDP was trading at an enterprise value to trailing twelve months production of $88,464 per flowing BOEPD.

Prior to this acquisition, GDP had amassed its 135,000 net acres for approximately $245 per acre. Today’s acquisition, which more than doubled GDP’s footprint, was done at approximately $144 per acre.

Well Results Complement Acreage Purchase

GDP announced its third operated TMS well, the Smith 5-29H (90% WI), recorded a 24-hour IP rate of 1,045 BOE (96% oil). The well was drilled with a 5,400 foot lateral and completed with a 20-stage frac. The well is still flowing back frac water after six days, and GDP expects results to improve as it cleans up. The Smith is GDP’s second well in the play which has been drilled above the rubble zone. These recent results, along with the potential to reduce drilling costs from $13 million per well complements GDP’s aggressive lease expansion plans in the play.


Oil & Gas 360 caught up with Rob Turnham, president and chief operating officer at Goodrich Petroleum the day of the announcement. We were able to ask him a few questions about the learning curve in the TMS, as well as his efforts to reduce well costs.

OAG360: Rob – Goodrich is known and has proven to be an early entrant into emerging shale plays. After your third operated well in the TMS, how would you rate the learning curve compared to your East Texas and South Texas assets?

TURNHAM: “The learning curve is much quicker here mainly because of our experience that we’ve learned from all the other plays…whether it was Cotton Valley in East Texas, to learning in the Haynesville in Louisiana and Texas and then our Eagle Ford experience in South Texas. What we’ve been able to do is reach an optimum drilling and completion procedure that appears to be working really well and superior to the other well results—and frankly we’ve taken a lot of what we’ve learned in the oil play in the Eagle Ford and transferred it over there, but again adjusted that to more efficiently produce the rock in the Tuscaloosa which has its own characteristics.”

OAG360: We’ve seen considerable reductions in well costs as plays mature – for example, Bakken wells trending from more than $12 million down to $8 million. Do you have your own internal goal for where you’d like to see well costs in the TMS to eventually trend?

TURNHAM: “We think we’re going to take these well costs down from $13 to $10 million over time. You basically achieve that goal by reducing the number of drilling days. In essence, pick your landing zone, and find an area that drills really quickly that keeps you out of problems and then shave days off the drill time. For every day you can save it’s about $100,000 of savings while drilling the laterals. We expect that to continue. We’ve done that in every play on average between the Cotton Valley, Haynesville and Eagle Ford. We’ve been able to cut about 13 days of our drilling time and if you save 13 days here, you can take your completed well cost down from $13 million to call it $11.7 million. And the additional cost savings come from pad drilling; where you have multiple wells per pad, skidding rigs to save on time and mobilization and demobilization charges. And then you come back behind those wells that were drilled off of pads and simultaneously frac them using what we call zipper fracs. That alone—the pad drilling and zipper fracs – can save as much as $1.5 million per well depending on how many wells you drill off of that pad. And then once a play is proven, the next added leg to the stool is just service cost pressure. The more successful it is—the more equipment moves into the play. That increased capacity causes better competition and we tend to see reduced service costs once the play has been proven. We would expect to gradually drop those costs down to the $10 million range by virtue of all of those different ways to do that.”

June 2013 Interview with Rob Turnham at EnerCom’s London Oil & Gas Conference

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