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Goodrich Petroleum Corp. (NYSE:GDP)

Q3 FY08 Earnings Call

November 6, 2008, 11:00 AM ET

Executives

Patrick E. Malloy III - Chairman of the Board

Walter G. Goodrich - Vice Chairman and CEO

Robert C. Turnham, Jr. - President and COO

David R. Looney - EVP and CFO

Mark E. Ferchau - EVP and Director of Engineering and Operations

Analysts

Subash Chandra - Jefferies

Ellen Hannan - Weeden & Co

Scott Wilmoth - Simmons & Co

Kim Pacanovsky - Collins Stewart LLC

Ronald Mills - Johnson Rice & Co

Sven Del Pozzo - CK Cooper & Co

Monroe Helm - CM Energy Partners

John Freeman - Raymond James

Dan McSpirit - BMO Capital Markets

Operator

Good day ladies and gentlemen and welcome to the Goodrich Petroleum Third Quarter 2008 Earnings Conference Call. My name is Jen and I will be your coordinator for today. [Operator Instructions] As a reminder this call is being recorded for replay purposes. I will now turn the presentation over to your host for today’s conference Mr. Gil Goodrich, Vice Chairman and Chief Executive Officer. Please proceed sir.

Walter G. Goodrich - Vice Chairman and Chief Executive Officer

Thank you Jen. Good morning everyone and welcome to our third quarter 2008 earnings conference call. I’d like to start by introducing the Goodrich Petroleum team members that are with us here today, starting with Pat Malloy the Company’s Chairman of the Board; Rob Turnham President and Chief Operating Officer; David Looney Executive Vice President and Chief Financial Officer; and Mark Ferchau our Executive Vice President Director of Engineering and Operations.

We issued a press release on the third quarter call yesterday after the close. Hopefully you’ve had a chance to review that. If you have not you can access one on our website at www.goodrichpetroleum.com or feel free to call my assistant Becky DeLatin [ph] at 713-780-9494.

As is our practice we would like to remind everyone that comments we may make and answers we may give to questions during this teleconference may be considered forward-looking statements, which involve risks and uncertainties and we have detailed those for you in our SEC filings.

This morning we are pleased to announce earnings and operational results. We believe the third quarter results and financial statements illustrate not only the success we have had in creating value for our shareholders but more importantly demonstrates the strength of our balance sheet and the significant amount of financial flexibility we currently enjoy, as well as illustrate our path to creating additional shareholder value in 2009.

Our reported record net income of $195 million was positively impacted by both the net gain resulting from our $172 million sale of undeveloped leasehold interests into a joint venture for the Haynesville Shale and the benefit of our strategic hedging position, which resulted in a non-cash gain of approximately $83 million in the quarter.

On closing the Haynesville Shale joint venture transaction and our follow-on equity offering of approximately 3.1 million shares in July, we paid off the entire amount of outstanding indebtedness under our senior credit facility, and ended the third quarter with approximately $224 million in cash and short-term investments; and a current net debt to capital ratio of just under 4%.

After the delivery of our midyear reserve report, our bank group indicated that our reserves at mid year which stood at 422 Bcfe of crude reserves would likely result in a borrowing base in excess of $200 million. However, given the current strength of our balance sheet, cash on hand and lack of expected borrowing requirements in 2009, as well as our desire to minimize unnecessary fees and documentation; we elected to maintain our current borrowing base at $175 million.

The full amount of the borrowing base will be re-determined by our bank group in the first quarter of next year after completion and delivery of our year-end 2008 reserve report. The combination of cash on hand and our existing borrowing base provide us approximately $400 million in available capital and liquidity. Consequently the strength of our balance sheet has us uniquely positioned to execute our strategy throughout 2009 and likely through 2010, without the need for any incremental capital.

During the quarter net production volumes averaged 69 million cubic feet of gas equivalents per day, which was near the low end of our previous guidance after adjusting for the estimated volumes curtailed in the aftermath of hurricane Ike, with such curtailment volumes meeting or slightly exceeding the high end of our original estimates.

Rob will provide you additional color on third quarter production and our outlook going forward in a few minutes. Additionally, David will provide a more detailed analysis of our third quarter revenue and expenses shortly. I would only comment that the incremental production growth we reported… with the increment production growth, we reported strong oil and natural gas sales which again exceeded $60 million in the period.

Third quarter operating income was $158 million, which includes the net gain from the proceeds received upon closing the Haynesville Shale joint venture. If we were to exclude the impact of the gain from the joint venture, operating income would have been approximately $12.1 million or $0.34 per basic share.

Operating income was also positively impacted by a meaningful decrease in per unit DD&A expense in the quarter. Our success with the drill bit in the first half of this year reduced overall refining and development costs, which were reflected in the mid year reserve report and resulted in a sequential per unit reduction in DD&A expense of 13%, when compared to the second quarter of this year.

The combination of production volume growth and our ongoing cost reduction efforts helped lower overall per unit operating expenses by approximately $0.73 per Mcfe compared to the year ago period.

Turning to cash flow EBITDAX, while down slightly due to lower commodity prices on a sequential basis compared to the second quarter of this year, grew robustly when compared to the same period a year ago to approximately $41 million, excluding the gain from the Haynesville Shale joint venture, which represents a 116% increase over the third quarter of 2007.

Hedging continues to be an integral part of our strategy, as we believe protecting our shareholders against as much downside natural gas price risk as possible, and protecting near-term cash flow is both important and prudent. With natural gas prices declining significantly during the third quarter, the benefits of our hedging strategy are illustrated by the reported non-cash gain on our hedging position in the quarter of approximately $83 million.

Moving to our current and forward-looking operational activity and plans, our horizontal Haynesville development is well underway with four Haynesville Shale horizontal wells currently drilling, on joint acreage in Northwest Louisiana. Further, we anticipate five Haynesville horizontal wells will have reached total depth by the end of the year and either be completed in producing or have run production casing and be ready to be completed.

While our capital expenditures will always follow results in the field, our initial expectation is that approximately 60% of our 2009 capital expenditure budget will be dedicated to horizontal drilling and development, of the Haynesville Shale, in both our 50% working interest joint ventures in Northwest Louisiana and our 100% owned acreage in Panola and Rusk counties of East Texas.

Finally, I would like to address our capital plans for 2009. With our very deep multi-year inventory of development projects and the excellent condition of our balance sheet, we are, as I mentioned earlier, uniquely positioned to execute an aggressive capital plan and to adjust the amount, timing, and allocation of our 2009 budget, based on prevailing market conditions and results in the field.

However, we believe the current market conditions call for a cautious approach. Consequently, our Board has recently approved a preliminary 2009 capital expenditure budget of $300 million, which represents an approximate 15% reduction in CapEx compared to 2008. With the preliminary capital budget approved by our Board and the increased prominence of the Haynesville Shale and our development plans, we are currently estimating net company production volumes will grow in excess of 2008 production, by approximately 30% to 40% during 2009.

I would now like to turn it over to Rob Turnham.

Robert C. Turnham, Jr. - President and Chief Operating Officer

Thanks Gil. The third quarter results set many records at Goodrich Petroleum as Gil has highlighted but was also very much a transitional quarter from an operational standpoint.

Our drilling program continued at a slightly reduced pace to previous quarters and our completions were down by 34% from the previous quarter, as we only completed and tested 23 wells in the third quarter versus 35 in the second quarter.

The reduction in number of wells completed during the quarter was driven by a number of factors. First, we conducted drilling operations on 38 wells during the quarter, down from 46 wells in the second quarter, as our non-operated activity was less primarily at Angelina River.

Second, we drilled five vertical wells during the quarter that normally would have been completed, but are either waiting to be reentered for horizontal development in the Haynesville Shale or are awaiting on third-party pipelines.

And third, we commenced horizontal development in the Haynesville Shale, which will lengthen the cycle time on completions. For the fourth quarter production will also be impacted by our reduced completion activity primarily driven again by longer cycle times for horizontal wells with 18 to 22 wells scheduled to be completed during the quarter. Even with the reduced completions in the fourth quarter, we are still guiding towards 4% to 9% sequential growth.

Of the 38 wells in which we conducted drilling operations during the quarter 15 were in Angelina River, with 12 being Travis Peak wells and three being James Lime horizontals, eight at Minden, one at Beckville, four at South Henderson, seven at Bethany Longstreet, and three at Caddo Pine Island.

We are on pace to drill 140 to 150 wells in 2008 and our drilling plans will continue to be focused on higher rate of return areas, as we transition into a higher percentage of wells drilled horizontally, which for 2009 will include the Haynesville, James Lime, and Cotton Valley Taylor sand objectives

Focusing on some of our core areas; At Bethany-Longstreet and Longwood and Caddo and DeSoto Parishes of Louisiana, which two fields comprise our Chesapeake joint venture. We have three non-operated rigs currently drilling Haynesville Shale horizontal wells. At Bethany-Longstreet our Holland 17H-1 was spud on September 22 and the Dorothy branch 11H-1 was spud on October 29.

Our expectations are for approximately 45 day drill times for our Haynesville wells and another 15 to 30 days to complete, with results from the initial well delayed slightly to around the middle of December due to installation of the necessary infrastructure.

At Longwood we spud the Percy Sharp 7H-1 on October 18. All three of these wells have expected laterals of approximately 4,000 feet and we own a 50% working interest in each.

We’ve also drilled a vertical Haynesville Shale well at Longwood the Lona Johnson 21-1. We own a 50% interest in the Chesapeake joint venture of approximately 39,000 gross acres.

At Caddo Pine Island in Caddo Parish Louisiana where we have a joint venture with Matador Resources, we have drilled and logged our Lanier 16-1 well a vertical well that encountered 287 feet of pay in the Haynesville Shale. We have plans to reenter that well and drill horizontally in the first quarter of 2009.

We are currently participating in the drilling of the Hall 5H-1 well, which was originally drilled vertically but reentered to drill horizontally on October 15 with a planned lateral of approximately 3,800 feet.

We are also participating in our fifth vertical well in the field the Balco Farms 7-1, which spud on October 12. Our current plans to reenter each of the vertical wells drilled in the field to drill horizontally over the next two to six months.

At Caddo Pine Island which is the Matador joint venture, we own a 50% interest in approximately 5,800 gross acres.

Moving over into East Texas at Beckville, and Minden, and Panola, and Rusk counties, we have drilled five vertical wells in the fields and expect to commence drilling our initial horizontal Haynesville Shale well, the Lutheran Church 5H-1 later this month.

We have commenced operations on our initial Cotton Valley Taylor sand horizontal well in the field the GW Waldrop 3H in which we own a100% working interest with a targeted lateral of approximately 3,000 feet. At Beckville Minden we own 100% interest and approximately 39,000 acres.

Moving to South Henderson, which is in Rusk County Texas just south and a little bit west of our Minden Beckville block, we’ve drilled and completed a Haynesville line vertical well our Robert Youngblood No. 8 with a initial production rate of 1 million cubic feet per day. We own a 100% working interest in the well and have plans to drill a horizontal well in the lime in 2009.

For those on the call not familiar with the geology of the Haynesville line, which is sometimes called the Cotton Valley line sits right below the Haynesville Shale. At South Henderson we own 100% interest in approximately 10,500 net acres. In the Angelina River Trend we completed three James Lime horizontal wells in the quarter with an average initial production rate of 7.5 million per day.

We are currently drilling our Estes 4H-1 well a well in the middle of our Cotton South prospect area in which we will own a 100% working interest. We’ve also drilled two new discoveries in the Angelina River Trend on our Surprise prospect the Grigsby No. 1 and Lilly No. 1 wells. Both wells encountered the James Lime and Travis Peak perspective.

We are currently drilling two additional vertical wells on the prospect our Tucker No. 1 which we are taking to the Haynesville Shale will be the first well that we have taken in the Haynesville Shale in the Angelina River Trend, as well as our Hill No. 1 which is targeting the James Lime and Travis Peak but could be taken to the Haynesville if we are successful in the Haynesville with the Tucker No. 1 well.

Completion of our Surprise prospect wells has been delayed due to lack of pipelines but we expect the wells to be online and producing later this year. We own a 50% interest in the wells and 6,000 acres in the Surprise prospect area and 41,000 net acres overall in the Angelina River Trend.

Looking out into 2009, as Gil stated earlier, we have set a capital expenditure budget of $300 million, which is a 15% reduction from 2008 but which still allows us to grow production volumes by up to 40%. We feel the reduction in CapEx budget is prudent at this time, due to current commodity price issues. But if we see commodity prices improve or costs continue to drop, thereby improving our margins, we may readdress the budget at a future time.

The allocation of the budget to our many different plays will also be fluid and with success we can increase our allocation to the Haynesville Shale. As we sit now, we are budgeting 76 wells for 2009, with approximately 60% of the budget being spent in the Haynesville Shale of which approximately 50% is allocated to our Chesapeake joint venture.

The remaining current allocation as we sit today is 25% of the budget in the Angelina River Trend, drilling Travis Peak and horizontal James Lime wells, 7% spent on the Cotton Valley with an emphasis on Cotton Valley Taylor sand horizontals, and approximately 8% allocated to potential leasehold acquisition in infrastructure expense.

With this allocation and the combination of a favorable hedge position and current expectations of softening service costs, we expect very attractive margins in 2009, while we drill out of cash flow and available cash while still growing volumes by up to 40%.

With that I’d like to turn it now over to David Looney to walk you through the financials.

David R. Looney - Executive Vice President and Chief Financial Officer

Thank you Rob. While, I’ll certainly address the two major items highlighted by Gil in a minute the gain on sale and the derivatives gain, I did want to proceed through the income statement as usual.

So we’ll start with reported revenues for the third quarter of 2008 of $60.4 million, which were based on average realized prices $9.14 per Mcf for gas and $117.65 per barrel for oil. On gas you’ll recall that we had 28.5 million cubic feet a day sold under physical contracts at a fixed price of just above $8.56 during the quarter, which helped to cause our realized price to come out to an approximately $0.08 above the average Henry Hub price for the quarter.

Going forward we continue to expect our average differential on non-fixed price volumes to be a deduct from the Henry Hub price of anywhere from $0.20 to $0.50 per Mcf. On oil, we realized an average basis of approximately $0.60 off of WTI Cushing prices during the quarter.

As Gil mentioned the mark-to-market of our gas hedges resulted in a gain on the income statement this quarter totaling $83.5 million the majority of which was unrealized. During the quarter we actually had realized losses on our gas derivative portfolio totaling $1.6 million and as of September 30th, we were in a net asset position of approximately $13 million on our gas hedges. For more specifics about our hedge position, I would refer you to our website or to our 10-Q, which should be filed later today.

Looking at cash flow. Our EBITDAX for the third quarter of 2008 increased, by 114% to $41.1 million versus $19.2 million for the prior year’s period. Similarly, discretionary cash flow, defined as net cash from operations before changes in working capital, increased to $38.6 million for the quarter, after adjusting for the tax impact of the previously mentioned gain on sale of deep rights in North Louisiana, versus $17.1 million during the third quarter of 2007.

In calculating DCF this quarter, you have to be careful to add back the current portion of our tax provision, which is solely related to the gain on sale, since the standard DCF calculation only adds back the deferred portion of the income tax provision.

Focusing on the expense side of the income statement, our lease operating expenses in the third quarter were approximately $8.2 million or $1.29 per Mcfe on a unit basis versus $5.2 million or $1.22 per Mcfe in the third quarter of 2007 and $7.7 million or $1.26 per Mcfe in the second quarter this year.

LOE per Mcfe for the third quarter of this year was negatively impacted by the loss of approximately 300 million cubic feet equivalent of production during and immediately after hurricane Ike. Nonetheless for the first nine months of the year the company has averaged LOE of $1.30 per Mcfe versus an average of $1.37 per Mcfe during the same period of 2007. Given the recent trend of rising oil fuel costs earlier this year we think this is a solid achievement in this environment.

For the current quarter we don’t expect to see any material changes in this per unit expense. No change will likely occur until new saltwater disposal facilities are in place and fully functional in our North Minden field and the Cotton South area of the Angelina River Trend, which is not expected to occur until sometime later in the fourth quarter.

Production and other taxes of $2.1 million for the third quarter of 2008 included production tax of $1.7 million and ad valorem tax of $0.4 million. Production taxes were net of $0.9 million of tight gas sand credits we booked for our wells in the State of Texas during the quarter. By comparison our third quarter production and other taxes on a unit basis were up almost slightly from the $0.30 per Mcfe in the third quarter of ‘07 to $0.33 per Mcfe in the current quarter. When you compare this to our revenue of $60.4 million this net production and other tax line item of $2.1 million, continues to be a very attractive 3.5% of total revenues which is the same as last quarter.

Transportation expenses total $2.2 million in the third quarter of 2008 or $0.35 per Mcfe versus $1.7 million or $0.40 per Mcfe in the third quarter of ‘07. As we’ve mentioned on previous calls our current production mix results in a fairly level range of per Mcfe transportation expenses, anywhere from $0.35 to $0.40 on a regular basis. This quarter we happen to come in at the low end of that range.

DD&A totaled $26.4 million for the third quarter of 2008 or $4.17 per Mcfe versus $20.4 million or $4.77 per Mcfe in the third quarter of 2007. And we calculated the first and second quarter 2008 DD&A rates using the December 31 2007 reserve information and this quarter’s number was calculated based on the mid year reserve report as Gil had previously mentioned.

We continue to see a decline in our overall DD&A rate as being a good example of how the development of our asset base is becoming more cost effective over time.

Exploration expenses for the third quarter of this year were slightly higher on an absolute basis over the prior year period of $2.2 million, but on an Mcfe basis they were down to $0.33 per Mcfe from $0.41 per Mcfe in the third quarter of last year.

Amortization of undeveloped leasehold costs which is the non-cash item was $1.7 million of this total during the third quarter of the year. As a reminder, as new areas are developed and proven successful the resulting acreage costs are then transferred to the proof producing category and included in the DD&A rate.

G&A expense increased on an absolute dollar basis to $6.2 million in the third quarter of 2008 from $5.1 million in the third quarter of ‘07 but did experience a 17% decrease on a per Mcfe basis to $0.98 per Mcfe during the third quarter of this year versus $1.18 per Mcfe during the third quarter of last year.

Stock-based compensation expense, which is again a non-cash item amounted to $1.4 million for the current quarter or approximately 23% of the total expense.

Our income statement this quarter shows a very large roughly $146 million gain on the sale of assets, as an offset to the operating expenses as previously discussed. As most of you know this gain was primarily associated with the sale of a portion of our deep rights in North Louisiana.

This resulted in a significant change in our tax position, whereby we are now highly likely to utilize the vast majority of our previously unused net operating loss carry-forwards when we file our 2008 federal income tax return. The planned utilization of approximately $62 million of these NOL carry-forwards allowed us to otherwise reduce the statutory tax provision by approximately $25.5 million this quarter, which resulted in a net Federal and State tax provision totaling approximately $42.1 million on our income statement. Of this amount we’ll likely have to pay federal and state taxes on a current basis totaling approximately $12.7 million with the remaining $29.4 million being deferred indefinitely.

Finally when you roll all the above items together for the three months ended September 30 2008 we reported net income applicable to common stock of $194.9 million or $5.50 per basic share, on total revenue from continuing operations of $60.4 million, which compares with a net loss applicable to common stock of $23.6 million or $0.94 per basic share, on total revenue from continuing operations of $27.3 million for the three months ended September 30 2007.

You will note that due to the large net income achieved this quarter we’re showing a diluted share count and diluted EPS number for the first time in several quarters. The primary difference between basic and diluted shares in our case is the inclusion of all of the possible shares, which could convert as a result of our convertible preferred and convertible notes outstanding, which would be approximately 6.2 million shares in total. I’d further point out that neither of these instruments is currently in the money with respect to the conversion price which is $31.36 on the preferreds and $65.94 on the convertible notes.

Also, regarding our share count; although the accounting rules do not allow us to include any benefit from the transaction, our cap call we entered into in December of 2007 could possibly return as many as 1.6 million shares over the three settlement periods, which run from May of 2009 until May of 2010, depending upon where our stock price settles during those periods.

Lastly I remind you, that when calculating diluted earning per share the new rate must be adjusted by adding back the preferred dividends and the aftertax interest expense associated with the convertible notes accrued by the company during the quarter, which in our case totaled approximately $2.6 million for those two items in the third quarter of this year.

Turning now to the balance sheet; our September 30th, balance sheet shows the impact of both our July equity offering in our transaction with Chesapeake on the North Louisiana deep rights. Needless to say Goodrich Petroleum has never been in a stronger liquidity position as we currently find ourselves. Having approximately $224 million of cash and short-term investments on the balance sheet and zero outstanding on our senior revolving credit facility, we have approximately $400 million of total liquidity at present.

As you likely saw in our press release, and as Gil referred to earlier, we elected to keep our borrowing base at $175 million, given the current bank market conditions and the likelihood that we won’t be needing to draw anything on our facility for well over a year.

Although our proved developed reserves alone grew by over 45% from the end of the year to the mid year reserve report, and the majority of our banks did in fact indicate that a normal borrowing base calculation would have yielded a number in excess of $200 million, we did not think that now was the time to in essence put our banks to the test. As a result we requested that the borrowing base stay at $175 million.

We’re confident that by the time we really need to fund into our revolver again our proved reserves will be at a significant enough level to more than support our projected borrowing needs in the 2010 and 2011 timeframe.

With that I’ll now turn it back to Gil for some closing comments.

Walter G. Goodrich - Vice Chairman and Chief Executive Officer

Thank you, David. We are currently taking a more cautious approach regarding our 2009 plans, we will as we always have continue to evaluate and analyze all market conditions, including those for future natural gas prices, drilling rigs, goods and services, as well as the debt equity, acquisition and divestiture markets with an eye towards adjusting our plans as warranted. So that we can continue to grow underlying shareholder value at an aggressive yet prudent pace.

That concludes our prepared comments and I’ll turn it back over to Jen now for questions.

Question and Answer

Operator

Thank you sir. [Operator Instructions] Our first question comes from Subash Chandra with Jefferies.

Subash Chandra - Jefferies

Hey, good morning guys. For your budget for next year is there a well count number, either gross net or preferably both?

Robert C. Turnham, Jr. - President and Chief Operating Officer

Yes. Subash, this is Rob. We’re estimating 76 wells to be drilled next year and then I believe in my remarks I gave kind of percentages of where those wells would be. So that would be gross number of wells.

Subash Chandra - Jefferies

Okay. So obviously a bit more expensive wells, a fewer number but higher reserve potential?

Robert C. Turnham, Jr. - President and Chief Operating Officer

Yes. Exactly and then higher production rates obviously.

Subash Chandra - Jefferies

Right.

Robert C. Turnham, Jr. - President and Chief Operating Officer

So I think part of my comments that 60% in the Haynesville Shale, 50% of that being with the Chesapeake joint venture, which obviously is a net 30% of the total. So if you want to elaborate on that just give me a call.

Subash Chandra - Jefferies

Sure.

Robert C. Turnham, Jr. - President and Chief Operating Officer

I’ll try to give you a more accurate net number.

Subash Chandra - Jefferies

Sure. And then late this summer or early this autumn we talked about some of the sort of pending infrastructure projects out of the Haynesville stuff that was sort of making its way through open season and so on. What’s an update as far, as you know on, those projects and if you can sort of give us an idea of what is coming up near term versus long term or what might have been canceled or delayed?

Robert C. Turnham, Jr. - President and Chief Operating Officer

Yes Subash. We’re observing just like you are obviously regency has an expansion of their North Louisiana system, we understand a pretty good incremental daily volume set to be on line kind of mid-’09 momentum. Our M2 has sold their interest in the Haynesville connector to DCP, which I believe they’re in the process of firming up their plans to add capacity also. But as far as we know both of those systems are on pace and being developed and on time table of adding additional capacity I think first phase by middle of ‘09, and then additional volumes by the end of that year.

My recollection on volumes is roughly half of a Bcf a day by each, kind of, mid-’09 going all the way up to a combined 3 3-1/2 Bcf a day by the end of 2010 but I would suggest Regency and certainly DCP would have a better handle on the current progress.

Subash Chandra - Jefferies

Okay. And last one for me the number of rigs you have working non-operating in the Haynesville, what’s the distribution of horsepower?

Robert C. Turnham, Jr. - President and Chief Operating Officer

Yes. Most of our rigs that we’re using currently whether it’s our rigs over in East Texas or the Chesapeake rigs are kind of 1,200 to 1,500 horsepower rigs with large pumps and top drives and for example one of the wells our Holland 17H-1 is currently drilling, I believe that’s a 1,200 horsepower rig and it’s worked very well in the drill of that well.

Subash Chandra - Jefferies

Terrific. Thank you.

Robert C. Turnham, Jr. - President and Chief Operating Officer

Thank you.

Operator

The next question comes from Ellen Hannan with Weeden Institutional.

Ellen Hannan - Weeden & Co

Good morning. Just a couple of questions for me. Could you remind us on the Chesapeake joint venture, what the terms are of their carry? Is there a specific dollar amount that they committed to spend or a specific time period over which they have to spend it?

Walter G. Goodrich - Vice Chairman and Chief Executive Officer

Good morning Ellen. This is Gil. No, there’s not a hard commitment to a specific number of dollars or wells. We have an agreement that we will earmark something along the lines of 20 to 25 wells in 2009. We actually have a meeting coming up here in a couple weeks. We’ll refine that a bit but we built into the agreement the feature that either party could propose wells. So if the pace goes a little bit slower than we would like we’ve got the ability to propose wells and conversely they could do the same. Plus the feature of a quarterly budget development committee that will budget the plans for the field and that budget cannot exceed $50 million gross, which would include both parties. So the most that can get proposed to us in a given year would be about $100 million net and that’s kind of what we’ve earmarked in our budget plans.

Ellen Hannan - Weeden & Co

Okay. Thanks. And in terms of… if you’ve mentioned this I apologize when do your rigs come off contract and when are you looking at renewals in terms of day rates?

Walter G. Goodrich - Vice Chairman and Chief Executive Officer

That’s a great question. Part of our strategy Ellen, is try to be, to include a blended rolling average of rig termination. So that we’re not having them all terminated at the same time. I believe we have one in December, we have one in January, we have one in April, one in July and one in August and we’ve got one that we’re... actually a couple we’re facing right now. So part of our process in putting our 2009 budget together was really to look very hard and scrub on the non-op expected activity and therefore rationalize the exact number of operated rigs and we will run in to next year probably at four to five rigs as we enter 2009 and if our non-op partners propose and drill all the wells that we currently anticipate, we would probably see that scaling back to maybe four by the middle of next year.

Robert C. Turnham, Jr. - President and Chief Operating Officer

Ellen this is Rob. Also what we’re doing is taking opportunity to improve on the quality of our rig fleet or at least add rigs that are capable of drilling horizontally. When we’ve been running an eight rig program roughly five of those eight rigs were capable of drilling horizontally and we would expect by mid year of ‘09 to have all four or maybe five rigs capable of drilling horizontally.

Ellen Hannan - Weeden & Co

Great. Any early indication as to what your day rates are going to look like for the ones that are coming up for renewal now in terms of change year-over-year?

Walter G. Goodrich - Vice Chairman and Chief Executive Officer

Day rates?

Ellen Hannan - Weeden & Co

Yes.

Walter G. Goodrich - Vice Chairman and Chief Executive Officer

Well we’re frankly waiting for the dam to break if you will. Obviously, we have seen only minor incremental reduction in rig rates. We think with the current CapEx environment that we’re looking at across the next year, we’re going to see some improvement there. At Goodrich we have talked with a number of contractors about some sliding scale, kind of collars if you will on the day rate, depending on where natural gas futures land and we may be entering into a couple contracts of that nature here shortly, that we think would be a win-win such that as natural gas futures strip on a 12-month basis reduces, we could realize lower day rates on our rigs.

And obviously as this future strip goes up and therefore our ability to hedge future volumes enhances, we would actually be willing to pay a little bit more. So right now I’d say the rig that Rob characterized for Haynesville horizontal are probably in the $19,000 to $21,000 a day range today.

Ellen Hannan - Weeden & Co

Great. Thank you. Just one last question for me. I don’t know whether you’ve had a chance to look at this. Devon on their call yesterday talked about some Haynesville lime vertical wells in their Stockman Field in the Carthage area that were looked to be extraordinarily prolific at least on an IP rate and only costing a little over $5 million to drill and complete. Any thoughts on what you might see in terms of the Haynesville lime? You did mention that you’ve drilled one and might be looking at a couple of others?

Walter G. Goodrich - Vice Chairman and Chief Executive Officer

Yes. Outstanding numbers posted by Devon yesterday at Stockman. No question about that. We are looking into that. Can’t Ellen at this point say exactly what the porosity is in that particular section and how much porosity may be driving those kind of IPs. As Rob mentioned our well here, we just tested recently at South Henderson, which does have lime probably running in the 10% to 12% porosity range, tested at a little over a million a day.

So we haven’t seen anything yet that looks to us like a $20 million a day type opportunity in the lime, but we do have lime present and gas bearing over a large portion of our acreage and we certainly will be looking at the Devon results closer, and as Rob mentioned, I think we do have plans for a horizontal well in the lime later in 2009.

Ellen Hannan - Weeden & Co

Great. That’s it for me. Thank you.

Robert C. Turnham, Jr. - President and Chief Operating Officer

Thank you.

Operator

The next question is from Scott Wilmoth [ph] with Simmons & Company.

Scott Wilmoth - Simmons & Co

Hey guys. Quick question. Could you guys give me a little insight on things you might have learned from the Chesapeake JV and how you’re going to apply those to other areas?

Robert C. Turnham, Jr. - President and Chief Operating Officer

Well I’ll take a stab at that Scott. This is Rob again. I mean obviously one of the big benefits of doing the Chesapeake joint venture was not only selling off a piece of your acreage and getting a nice bit of money for it, but with the expertise that they bring to the table, we do have quarterly development committee meetings. We do exchange information relative to our acreage and our plans for our wells. Probably wouldn’t get into too much detail relative to that or to be disseminated to the public. Certainly the best ways to drill and complete these wells, we’re taking advantage of their experience and expertise.

We do feel like there’s an optimum way of completing these wells. It does appear that ceramic proppant or resin coated sand works best. It does appear that slightly larger diameter pipe both 7-5/8 in the vertical and 5-1/2 in the lateral does allow you to pressure up, break down the formation and get more effective fracs. It doesn’t mean you can’t use slightly smaller pipe but that’s something that seems to be working very well for Chesapeake. So there are a number of things that we’re learning and will be able to apply to our East Texas acreage.

Scott Wilmoth - Simmons & Co

Okay. When looking at ceramic proppant are you guys seeing any shortages that are delaying completions? I know we heard some thing from some other operators in the area?

Robert C. Turnham, Jr. - President and Chief Operating Officer

Certainly tight. We are... of course Chesapeake as the operator of the joint venture is handling that. We don’t expect to be waiting around to complete our wells, although the material is somewhat tight. We do feel like that’s going to loosen up a bit over time. We’re aware of Carbo Ceramics joint venture with Halliburton to I believe expand the capacity of their manufacturing of that proppant. I believe there’s some Russian proppant coming in that will also work and then the big question is does resin coated sand work as well as the ceramic proppant over time? It does. There is more sand obviously available but we’ll need to get some experience on that before really determining what the maximum or what the best route is to frac these wells.

Scott Wilmoth - Simmons & Co

Okay. And then my last question just trying to get some visibility on year-end reserves. I know it depends a lot on gas prices and drilling results, but with the JVs and Haynesville results, what are you guys looking at booking year-end and possibly what does that do for DD&A in ‘09?

Walter G. Goodrich - Vice Chairman and Chief Executive Officer

Yes. This is Gil. I’ll take that. I mean obviously we have a practice of never getting in front of our reservoir engineers. So we’ll make that determination as to what our year-end reserves might look like. As we said, relative to Haynesville we do anticipate having something on the order of five or six horizontal wells down, which should be able to be booked and included in the year-end proved reserves.

So we’re very pleased with what we saw in the first half of the year with the significant, as David mentioned, 45% increase in proved developed reserves and a nice increase in overall proved reserves and we think though we got a little bit slower activity for the things, the reasons that Rob outlined earlier, a little bit slower activity. In the second half we do expect to see continued improvement in the absolute amount of proved and proved development serves.

Scott Wilmoth - Simmons & Co

Okay great. That’s all I have thanks.

Operator

The next question is from Kim Pacanovsky with Collins Stewart LLC.

Kim Pacanovsky - Collins Stewart LLC

Good morning everyone.

Robert C. Turnham, Jr. - President and Chief Operating Officer

Hi Kim.

Kim Pacanovsky - Collins Stewart LLC

Hi. Is the rig schedule that you laid out for the Haynesville, I think last quarter’s call, has that been altered at all or is that still looking good?

Robert C. Turnham, Jr. - President and Chief Operating Officer

Well I’ll take a stab at that. Actually it’s accelerated a little bit, in that we in essence have four rigs running right now, three in the Chesapeake joint venture, and one on the Matador joint venture Caddo Pine Island. Our plans for ‘09 are pretty consistent with what we’ve always said, which is basically scaling up to four rigs running on the Chesapeake acreage and then running two rigs on our 100% owned acreage in East Texas.

So, I would say it’s basically the same as we laid out. You’ll see some timing differences based off of rigs, but pretty much we’re right on the same path that we laid out.

Kim Pacanovsky - Collins Stewart LLC

So when will those I guess three additional rigs come in?

Walter G. Goodrich - Vice Chairman and Chief Executive Officer

Let me jump in Kim and try to take a stab at this. What we tried to convey is that we’re very pleased and excited about the jump start we now have with five or six wells down by the end of the year. We obviously are anxious to get those wells online and see some results. Our plan is to try to get those wells completed, we’ll continue with development but if we see the results that we fully anticipate, we’ll probably see an increase in activity as we go through the course of 2009.

Kim Pacanovsky - Collins Stewart LLC

Okay.

Walter G. Goodrich - Vice Chairman and Chief Executive Officer

And as Rob alluded to earlier in his comments, potentially even an increase in the allocation of Haynesville wells if results match our anticipation.

Kim Pacanovsky - Collins Stewart LLC

Okay. And what is your anticipation? I mean what kind of rates are you building into the guidance that you have right now?

Robert C. Turnham, Jr. - President and Chief Operating Officer

Well we’ve taken a little bit less the midpoint that many of the companies who have wells online are producing seems to be kind of in that 6 to 6-1/2 Bcf. We’re not using that type curve for planning purposes. We’ve conservative that number a little bit more than that.

Kim Pacanovsky - Collins Stewart LLC

Rob I’m sorry. I’m talking about IP rates in the production…?

Walter G. Goodrich - Vice Chairman and Chief Executive Officer

Well again that goes with your reserves.

Kim Pacanovsky - Collins Stewart LLC

Okay.

Robert C. Turnham, Jr. - President and Chief Operating Officer

What I’m telling you I guess is we’re not using the same type of curve…

Kim Pacanovsky - Collins Stewart LLC

Okay.

Robert C. Turnham, Jr. - President and Chief Operating Officer

...which in our estimate I think would have an IP of 8 million a day for a 6 Bcf type well. We’re using something less than that and we’ll tell if that gives us some leeway. The numbers and the rates of return work very well in this play at 3.5 to 4 Bcf per well and we do expect variability not that we’ve see anything that would tell us that we’re going to get that type of reserve per well but we try to… from a budgeting standpoint conservative our production estimates and feel like that serves us well.

Kim Pacanovsky - Collins Stewart LLC

Okay. And for the wells… for the first wells in the program what kind of costs are you looking at? I mean, I know you haven’t gone through and completed anything yet but…

Robert C. Turnham, Jr. - President and Chief Operating Officer

Yes. $7 million to $7.5 million.

Kim Pacanovsky - Collins Stewart LLC

$7 million to $7.5 okay. And at Angelina River that one well was a fabulous well at about $13 million a day. Are you drilling a longer lateral there? What’s responsible for that?

Robert C. Turnham, Jr. - President and Chief Operating Officer

Variability.

Kim Pacanovsky - Collins Stewart LLC

Okay.

Robert C. Turnham, Jr. - President and Chief Operating Officer

Yes. We are tweaking with our completions. The average length of lateral, in some cases we’re drilling 6,000 feet in the lateral. It does vary a little bit but I’m not sure we can put our finger on the length of lateral as dictating the IP rates.

So, right now we’re just continuing to spread our wells out, get a broad sampling. We do still expect kind of a 2 Bcf type play maybe 2-1/2 in some areas and, but we do expect variability across the board.

Kim Pacanovsky - Collins Stewart LLC

Okay. And also what’s the status of the water disposal there and can you give us some guidance for LOE for 2009?

Robert C. Turnham, Jr. - President and Chief Operating Officer

Yes. I’ll follow up with that one also. There has been a delay. In fact, I think David touched on LOE per unit of $1.29 in the fourth quarter. Frankly that LOE per unit would have been much lower with the added production that we had to shut in through hurricane Ike.

However we have been delayed on getting the saltwater disposal at Angelina River Trend, Minden and then a portion of Bethany-Longstreet. Those are scheduled to be in and up and running early first quarter. We had hoped to have it running in the fourth quarter and there’s been delays in the field, but beginning in January and staggered through the first quarter we do expect saltwater disposal systems to be in place in those three areas.

Kim Pacanovsky - Collins Stewart LLC

Okay. Any guidance on the costs after they are in place from the second quarter on?

Robert C. Turnham, Jr. - President and Chief Operating Officer

Well we clearly think LOE per units going down, not only because of saltwater disposal but because as we...

Kim Pacanovsky - Collins Stewart LLC

Production yes.

Robert C. Turnham, Jr. - President and Chief Operating Officer

…as we bring Haynesville wells on they have much less produced water and therefore a much lower LOE per unit. So, we’ve previously guided without work overs we’d be down in the $1 per Mcf range and certainly feel like once we get these saltwater disposal systems up and running, and Haynesville wells on line, we should be able to hit that number if not improve on it.

Kim Pacanovsky - Collins Stewart LLC

Okay great. Thanks a lot guys.

Robert C. Turnham, Jr. - President and Chief Operating Officer

Thank you.

Operator

The next question is from Ron Mills with Johnson Rice.

Ronald Mills - Johnson Rice & Co

Not much left, but on… just as you look at East Texas lots of infrastructure in the area but as you ramp activities later this month and throughout ‘09 in East Texas can you… what sort of infrastructure additions are you going to have to make to be able to tap into the export capacity?

Robert C. Turnham, Jr. - President and Chief Operating Officer

Yes. For us at Goodrich Ron, not a whole lot. One of the benefits is we’re talking about drilling these Haynesville horizontals on our Minden-Beckville block. I don’t know the exact count but we’re probably pushing 200 wells we’ve drilled across that block in the last four years or so. So we’ve already done an awful lot in terms of putting in facilities infrastructure, flow lines, gathering systems etceteras. Most of which by and large are capable of handling the gas that we’ve been producing from the Haynesville. So nothing from a micro standpoint on our acreage that we really see there of any importance at all.

Ronald Mills - Johnson Rice & Co

Okay. And it sounds like at least in the press release in the Angelina River Trend you’re going to drill your first well down to the Haynesville. Which one of your project areas in the Angelina River is that? I’m just trying to get a sense as to where it’s located relative to Traywick [ph] and….

Robert C. Turnham, Jr. - President and Chief Operating Officer

It would be on what we call the Surprise prospect. It’s a fairly new acreage position for us. I think it’s up close to around 6,000 gross acres and it’s located about five miles southeast of the Traywick field and if you’re familiar with Cabot’s announced well, they drilled in Haynesville would be… roughly about five miles southeast of there. So it would be the northern most acreage position we have in Angelina River.

Ronald Mills - Johnson Rice & Co

Okay. And just from a timing standpoint would you all expect the $300 million budget as it sits today at least to be spent relatively evenly throughout the year or should that build a little bit as you add the last one to two rigs at some point in the first or second quarter?

Robert C. Turnham, Jr. - President and Chief Operating Officer

Yes. No. It looks to us to be fairly evenly as we sit here today, Ron.

David R. Looney - Executive Vice President and Chief Financial Officer

Just to kind of repeat of that $300 million we’re currently allocating about $25 million for potential leasehold acquisition and infrastructure. So obviously that could move. We could spend less there and a little bit more on the drilling side, but that’s our best guess.

Ronald Mills - Johnson Rice & Co

Okay. And what would it take for you all to… I mean you all are going to revisit it regularly I’m sure, but given the outlook where you probably still have sitting on a cash position at year-end with that sort of activity level, what are some of the bogies you’d be looking for to suggest a ramping in that CapEx budget?

Robert C. Turnham, Jr. - President and Chief Operating Officer

A significantly improved debt and credit market for one, some life that might come back into the equity markets two, natural gas futures prices particularly the 2010 strip and that probably is number one on the list actually but certainly that would be an important factor. So, and as we alluded to earlier, our results, if we’re meeting or exceeding these and therefore cash flow is improving above our expectations, we certainly would be prepared to ramp up accordingly.

David R. Looney - Executive Vice President and Chief Financial Officer

Yes Ron. I might add based on our balance sheet we have no intentions of going to the equity market obviously any time soon and have the ability to get all the way through 2009 without even pulling on our revolver. So that’s really not an issue but certainly if the market heals on the gas price environment and we see the types of results that Chesapeake and Petrohawk and others have been doing the beauty of the play is that, its a high margin play and your break-even point for Haynesville wells, our estimates say that comes at midpoint are less than $4 for the Haynesville. So you’re not going to see us slowing down. You could see us ramping up in this play versus other more marginal plays.

Ronald Mills - Johnson Rice & Co

All right guys. I appreciate it.

David R. Looney - Executive Vice President and Chief Financial Officer

Thanks.

Operator

The next question is from with Sven Del Pozzo with C.K. Cooper.

Sven Del Pozzo - CK Cooper & Co

Yes. Good morning.

Robert C. Turnham, Jr. - President and Chief Operating Officer

Hi Sven.

Sven Del Pozzo - CK Cooper & Co

I’d like to have a better idea of how the Haynesville program is going to replace the Cotton Valley Trend program over time and basically I’m trying to model out by well, I wonder if you can give me an idea of the schedule of how you’ll drill and complete the Haynesville wells over the course of 2009. You say, you’ll have about five or six down by year-end and then I’m wondering how many you might drill in the first quarter and the second quarter, so I can kind of model out my production specifically from the Haynesville.

Robert C. Turnham, Jr. - President and Chief Operating Officer

Yes. I would I think as Gil or David has said before kind of a smooth CapEx plan for 50% of our activity would be in Haynesville. I would break that out smoothly over each quarter. We’re expecting kind of 45 day drill time and 15 to 30 days to complete. So if you just spread 50% of our $300 million budget that would be $150 million over the full year. I would use kind of that $7 million $7.5 million CapEx number and then assume the timing of that that we just talked about. That would be probably as good as we could give you at this point in time.

As far as replacing Cotton Valley we clearly are allocating our budget certainly for 2009 with only about 7% being spent in the Cotton Valley and frankly the majority of that is Cotton Valley Taylor horizontal wells and of course with success there we could reallocate and drill more horizontals but that’s our current expectation for ‘09.

The one benefit for our acreage is that one we got in early and two we spread wells out so that now most of our acreage is held by production with no time constraints on it. So under the right scenario we don’t expect to ignore or leave behind the Cotton Valley but we have time to come back and get it at more attractive commodity prices but for now it’s certainly the influence and the transition for us is to be going a little bit more horizontally. But ultimately that inventory chart that we talked from, we feel like those reserves are there and we’ll ultimately capture it.

Walter G. Goodrich - Vice Chairman and Chief Executive Officer

I might just add one comment Rob touched on it and that is that with every one of these Haynesville horizontals we’ll be drilling vertically right through the Cotton Valley section. So in our mind we’ll be picking up on pipe reserves for the Cotton Valley with every well.

Sven Del Pozzo - CK Cooper & Co

Okay. And if there were no Haynesville program, how much would production increase next year devoting just 40% of your CapEx to the Cotton Valley Trend?

Walter G. Goodrich - Vice Chairman and Chief Executive Officer

I’m sorry you’re asking us a hypothetical that we’re just not prepared to answer this morning.

Sven Del Pozzo - CK Cooper & Co

Okay. And if you were… if you didn’t do any more drilling in the Cotton Valley trend or in kind of a blowdown scenario what might a depletion rate be? I’ve heard maybe 25% to 30% per year. I don’t know if you agree with that?

Walter G. Goodrich - Vice Chairman and Chief Executive Officer

Again, I mean in every point in time it’s going to be different. So we would hesitate to make some specific, if we shut everything down and quit drilling wells what our decline rates would be. What we’ve said is that initial wells when they come on typically decline 65% to 75% in their first 12 months and then go on fairly flat declines after that.

Robert C. Turnham, Jr. - President and Chief Operating Officer

But if you look at our runoff it’s clearly not as steep as you’ve described for our existing wells but I agree with Gil. We don’t have that data in front of us.

Sven Del Pozzo - CK Cooper & Co

Okay. All right. Thank you.

Robert C. Turnham, Jr. - President and Chief Operating Officer

Thank you.

Operator

The next question comes from Monroe Helm [ph] with CM Energy Partners.

Monroe Helm - CM Energy Partners

Most of my questions had been answered but I kind of had one on your bank lines. Just wondered if you could share with us what price decks the banks used in your last conversations with them when they said they might be willing to bump it up to $200 million?

David R. Looney - Executive Vice President and Chief Financial Officer

Yes. This is David, Monroe. The banks we have I guess five different banks in the group right now. BNP Paribas is our lead. Each of them had a little different price deck but essentially Paribas, I believe starts the exercise at $6.50 or $6.75. They’re actually in the midst of adjusting it right now and they take it down by $0.25 each year to $6. That’s their base case.

Monroe Helm - CM Energy Partners

Okay. Well thanks a lot for your comments and great results.

David R. Looney - Executive Vice President and Chief Financial Officer

Thanks Monroe.

Robert C. Turnham, Jr. - President and Chief Operating Officer

Thanks.

Operator

[Operator Instructions] Our next question is from John Freeman with Raymond James.

John Freeman - Raymond James

Hey guys.

Robert C. Turnham, Jr. - President and Chief Operating Officer

Hi John.

Walter G. Goodrich - Vice Chairman and Chief Executive Officer

Good morning John.

John Freeman - Raymond James

Most of my questions have been exhausted. The last thing that I was just going to touch on is just given that you’re currently in a position that you haven’t been, in recent memory of extremely clean balance sheet, no expiring kind of lease expirations to worry about, and given that the Haynesville as you all have mentioned looks like it will generate good enough returns at even below $4 gas.

What are the odds… and I know you’ve earmarked like $25 million for kind of leasehold and infrastructure, but it would seem like even though historically it hasn’t been you all’s kind of MO to acquire acres in some of the hot plays but you may be in a situation here as we go forward, just given commodities that pulled back.

A lot of guys got ahead of themselves, there may be some acres that’s kind of near some of your existing Haynesville acreage. What would be the odds of you all being more aggressive picking up some of that acreage?

Walter G. Goodrich - Vice Chairman and Chief Executive Officer

Well John, this is Gil. We’re certainly looking at those opportunities on a routine basis and if the right opportunity came along we would not be hesitant to give it a very thorough valuation. That being said we are… in this particular environment we are we’re extremely focused on our balance sheet, on our cash position, preserving that capital to continue to execute our strategy for as long as this bad weather market lasts.

So we’re certainly not going to step up. I mean very low probability we would step up and do something that significantly alters the strength of our balance sheet.

John Freeman - Raymond James

All right. Thanks guys, great quarter.

Robert C. Turnham, Jr. - President and Chief Operating Officer

Thank you John.

Operator

The next question is from Dan McSpirit with BMO Capital Markets.

Dan McSpirit - BMO Capital Markets

My questions have been answered. Good morning thanks.

Robert C. Turnham, Jr. - President and Chief Operating Officer

Hi Dan.

David R. Looney - Executive Vice President and Chief Financial Officer

Thanks Dan.

Operator

Ladies and gentlemen, as there are no further questions in the queue I will turn the call back to Gil Goodrich for closing remarks.

Walter G. Goodrich - Vice Chairman and Chief Executive Officer

Thank you Jen and we thank all of you for your participation this morning and we look forward to reporting our year-end results to you some time in the early New Year. Thank you.

Operator

Ladies and gentlemen we do thank you for your participation in today’s conference. This concludes your presentation and you may now disconnect. Have a great day. .

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Source: Goodrich Petroleum Corporation Q3 2008 Earnings Call Transcript

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