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Goodrich Petroleum (GDP)
Q3 2012 Earnings Call
November 07, 2012 11:00 am ET
Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee and Member of Hedging Committee
Robert C. Turnham - President, Chief Operating Officer and Non-Independent Executive Director
Jan L. Schott - Chief Financial Officer and Senior Vice President
Michael Kelly - Global Hunter Securities, LLC, Research Division
Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division
Brian M. Corales - Howard Weil Incorporated, Research Division
William B. D. Butler - Stephens Inc., Research Division
Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division
Leo P. Mariani - RBC Capital Markets, LLC, Research Division
Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division
Dan McSpirit - BMO Capital Markets U.S.
Richard M. Tullis - Capital One Southcoast, Inc., Research Division
Steven Karpel - Crédit Suisse AG, Research Division
Pearce W. Hammond - Simmons & Company International, Research Division
Previous Statements by GDP
» Goodrich Petroleum's CEO Discusses Q2 2012 Results - Earnings Call Transcript
» Goodrich Petroleum Q1 2009 Earnings Call Transcript
» Goodrich Petroleum Corporation Q4 2008 Earnings Call Transcript
Walter G. Goodrich
Good morning, everyone, and welcome to our third quarter earnings conference call. With me on the call this morning is Pat Malloy, the company's Chairman of the Board; Robert Turnham, our President and Chief Operating Officer; Mark Ferchau, Executive Vice President, Engineering and Operations; and Jan Schott, Senior Vice President and Chief Financial Officer.
It's our practice to tell you that questions that we may give answers to and comments that we may make may be considered forward-looking statements, which involve risks and uncertainties, and we have detailed those for you in our SEC filings.
Growth in crude oil volumes, which grew by 15% sequentially, from 18% to 23% of total production on an Mcfe basis, versus the second quarter, resulted in both an increase in quarterly EBITDAX to $48 million and a further expansion of our operating cash margin, which increased to just over $6 per Mcf equivalent on adjusted revenue of $8.34 per Mcfe in the quarter.
At the end of the third quarter, we completed the previously announced non-core Cotton Valley asset sale in East Texas for approximately $95 million. After giving effect to the sale of the South Henderson property, as well as a reduction in the natural gas price forecast used by our senior bank group, the borrowing base under our senior credit facility has been affirmed at $210 million, giving us a total of unused borrowings plus cash on hand, or total liquidity, of approximately $113 million as we enter the fourth quarter. The closing of the divestiture of the South Henderson field provides a meaningful boost to our liquidity, and we will consider additional non-core asset sales and/or joint ventures in the Tuscaloosa Marine Shale or Pearsall Shale at the appropriate time to ensure we maintain ample liquidity and can again execute an aggressive oil-directed drilling program in 2013.
Given the recent relative improvement in natural gas prices, with current strip prices for 2013 just under $4 per Mcf, as well as discussions with our joint venture partner in the Haynesville Shale, we now plan to complete and frac approximately 13 gross or 11 net Haynesville Shale wells previously drilled but not yet completed. We expect these will -- wells will be completed during the first half of 2013, with all wells expected to be online and producing by the third quarter of next year. We estimate net capital expenditures of approximately $22 million to complete these wells. And if we use a $4 flat price assumption for 2013, we expect production from these wells will generate approximately $22 million in gross revenue during the calendar year 2013.
In the Eagle Ford Shale play, our drilling team achieved a marked and meaningful improvement in our average Eagle Ford wells drill time performance. Through refined drilling techniques, our team achieved a reduction in the average drilled-to-total-depth time of approximately 40%, or an average of 11 days, for our most recent Eagle Ford Shale wells. These are outstanding results. We congratulate our team. And the end result will be lower cost per well and an acceleration of wells drilled per rig and our modeling cycle times for 2013.
Our pad drilling strategy is ongoing, and while daily volumes remained somewhat lumpy when looked at on a quarterly basis, we are again projecting a further increase in crude oil production in the fourth quarter of approximately 20% over the third quarter of this year.
While we previously expected to rotate 1 Eagle Ford rig to the Tuscaloosa Marine Shale during the fourth quarter, we now plan to maintain 2 rigs running in the Eagle Ford into and through 2013. In addition, following the recent success of 2 new Pearsall Shale wells by other operators offsetting our approximate 10,000-net-acre Pearsall position, we are preliminarily planning our first 100%-owned Pearsall Shale test in the first quarter of 2013.
In the Tuscaloosa Marine Shale, where we have acquired approximately 134,000 net acres, we continue to make progress in de-risking and delineating the play. The drilling issues associated with this play and, therefore, higher well cost experienced to date have primarily been associated with wellbore stability issues or a well-defined, highly, naturally fractured geologic interval of approximately 10 feet within the TMS has had a tendency to slough or cave in to the lateral wellbore, especially when this wellbore is traversed at a high angle. There are a number of potential remedies, including: one, traversing the interval at a lower or a more vertical angle; two, drilling through the naturally fractured zone and setting intermediate casing over the interval; or three, landing the horizontal lateral above the fractured interval.
Our non-operated Ash 31H well has recently been drilled and successfully landed above the natural fractured interval. The well was drilled with a lateral length of approximately 6,600 feet through the TMS without significant drilling-related issues. Production casing has been set, and the well is now waiting on completion. Eliminating the wellbore stability issues and drilling issues, as it appears we have done on the Ash 31H, will result in meaningfully lower completed well costs in the TMS, and we are encouraged by these wells' drilling performance.
On the performance side, we remain very encouraged with well performance to date, with the oldest grassroots TMS completion now having been online and producing just over 11 months and 2 longer laterals having produced just over 5 months, including the Anderson 17H, in which we have a 7% working interest, which is producing over 300 barrels a day after 5 months online. We are continuing our development of the TMS at a measured pace, with approximately $14 million of net capital expenditures invested in the first 9 months of this year, or approximately 8% of total drilling and development CapEx through the third quarter. Production for these wells will begin to impact net oil volumes in the fourth quarter and as we enter 2013.