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FINAL TRANSCRIPT

May. 07. 2009 / 10:00AM, GDP — Q1 2009 Goodrich Petroleum Earnings Conference Call

CORPORATE PARTICIPANTS

Gil Goodrich
Goodrich Petroleum — Vice Chair, CEO

Robert Turnham
Goodrich Petroleum — President, COO

David Looney
Goodrich Petroleum — EVP, CFO

CONFERENCE CALL PARTICIPANTS

Ronnie Isman
- Analyst

Crystal Choi
- Analyst

Joe Magner
Tristone Capital — Analyst

Richard Tullis
Capital One Southcoast — Analyst

Ron Mills
Johnson Rice — Analyst

Ellen Hannan
Weeden & Co. — Analyst

Mike Salia
- Analyst

PRESENTATION

Operator

Good day, ladies and gentlemen, and welcome to the Q1 2009 Goodrich Petroleum earnings conference call. My name is Lisa and I will be your coordinator for today. At this time all participants are in a listen-only mode. We will be facilitating a question-and-answer session towards the end of today’s conference. (Operator Instructions). I would now like to turn the presentation over to your host for today’s conference, Mr. Gil Goodrich, Vice Chairman and CEO of Goodrich Petroleum. Please proceed, sir.

Gil Goodrich - Goodrich Petroleum — Vice Chair, CEO

Good morning, everyone, and welcome to our first-quarter 2009 earnings call. I’ll begin with introducing the Goodrich Petroleum team members here with me this morning, Robert Turnham, our President and Chief Operating Officer; David Looney, Executive Vice President and Chief Financial Officer; and Mark Ferchau, Executive Vice President Engineering and Operations.

We put out a press release after the close yesterday afternoon detailing our operations and first-quarter earnings. If you have not received a copy of that and would like one you may access it on our company website at www.GoodrichPetroleum.com, or call my personal assistant, Becky DeLatin, at 713-780-9494, she’ll be more than happy to fax or e-mail you a copy.



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FINAL TRANSCRIPT

May. 07. 2009 / 10:00AM, GDP — Q1 2009 Goodrich Petroleum Earnings Conference Call

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

I’d like to begin this morning with a few highlights from the first-quarter’s operations and recent activities. During the quarter our operations team again delivered strong sequential growth in net production volumes which grew by 7.5% sequentially over the fourth quarter of last year to approximately 76 million cubic feet of natural equivalents per day.

During the quarter we significantly ramped up our horizontal drilling activities, conducting drilling operations on 15 horizontal wells of which 12 were Haynesville Shale horizontal wells. An addition, we further expanded our Haynesville Shale drilling inventory in northwest Louisiana, adding approximately 40 net horizontal locations with the acquisition of approximately 3,400 net acres, which we believe to be extremely well located and highly prospective for the Haynesville. This acquisition also increases our net Haynesville Shale acreage position by approximately 5% to 66,500 net acres.

Finally, due to continued deterioration in natural gas current and [prop] months, and the ongoing uncertainty on the remaining near-term outlook, we believe it is prudent to further reduce our planned 2009 capital expenditures and ensure we preserve significant liquidity going into 2010. Thus we have announced a $70 million CapEx reduction for 2009 and a revised full-year budget of $230 million.

With continued growth robust drilling activity during the first quarter, where we conducted drilling operations on 24 wells and began the quarter with six operated rigs under contract and five non-operated rigs working, capital expenditures for the first quarter were approximately $87 million. As we will be reducing both our operated and non-operated rig count under the revised CapEx budget, full-year 2009 capital expenditures will be significantly front-end loaded.

As we announced on Tuesday, we have closed a restated credit agreement with our bank group which reaffirmed our borrowing base of $175 million. With approximately $78 million in cash and short-term deposits on hand at the end of the quarter and our revised 2009 capital plan, we believe we will be positioned to enter 2010 with no borrowings under our credit facility and plenty of flexibility to execute our strategy under a number of potential economic conditions and scenarios.

As I said at the outset, with sequential quarterly growth of 7.5% we are off to an excellent start to achieving another year of double-digit production volume growth. However, with the revised capital expenditure plan announced yesterday, we are also revising our full-year production growth forecast downward to annual growth of approximately 15% to 25% as compared to full-year 2008.

The value and benefit of our 2009 natural gas hedge position is very evident in our quarterly results. We recorded a gain in the quarter on our entire hedge position of $37 million, of which approximately $21 million were cash settlements we received during the quarter. The hedging cash settlements, or realized gains, led to another quarter of very strong cash flow with EBITDAX reaching $31 million.

In addition, the forward-looking benefit, or value of our hedge position as of March 31, was approximately $71 million giving us a forecasted full-year 2009 benefit from our hedges of approximately $92 million. While we are currently unhedged in 2010, we are closely monitoring the 2010 natural gas strip which closed yesterday at $6.15 per MMBtu, as well as taking note of the steep decline in natural gas directed rig count, which has fallen from its October 2008 peak of 1,620 active rigs, to last week’s [Smith bps] estimate of 743 active rigs which represents the idling of 877 gas directed rigs or a 54% decrease from the peak.

Like many others, we believe this deep decline will soon begin to impact domestic natural gas supply and play a key role in tightening the natural gas market as we move into the second half of this year. Therefore our approach to 2010 is one of patience and diligent following of market conditions with an eye towards beginning to build a 2010 hedge position at the appropriate time.



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May. 07. 2009 / 10:00AM, GDP — Q1 2009 Goodrich Petroleum Earnings Conference Call

Our revised budget for 2009 of $230 million continues to have approximately two-thirds of our planned capital expenditures, or $150 million, earmarked for Haynesville Shale horizontal drilling and development which will allow us to drill and participate in 30 to 35 gross wells during 2009. As of this morning we are well on our way toward that goal with drilling operations already conducted on 12 Haynesville horizontal shale wells during the quarter, bringing the total number of horizontal wells drilled to date and to reach total debt to 15.

In addition, we are currently drilling three Haynesville horizontals and expect to spud two additional wells later this month. Rob will provide you more details on production and test results in just a minute, but I will simply say that we are both pleased and encouraged by the early results we have seen thus far, and we have quite a few wells undergoing completion or in the very early stages of flow back which we expect to be reporting later this month. And with that I’ll turn the call over to Rob Turnham.

Robert Turnham - Goodrich Petroleum — President, COO

Thanks, Gil. We conducted drilling operations on 24 wells in the quarter of which 12 were horizontal Haynesville Shale with 18 wells added to production. Of the 18 wells added to production only two were horizontal Haynesville Shale wells. With two-thirds of our 2009 budget allocated to the Haynesville and with nine wells already drilled and waiting on completion, the percentage of future production volumes coming from the Haynesville will continue to grow leading to robust growth of 15% to 25% for the year even with our reduced CapEx budget.

With a revised budget of $230 million we now anticipate drilling approximately 46 gross, 29 net wells with 33 gross, 19 net being Haynesville wells. As to the Haynesville, our drill time on 4,500 foot laterals is currently estimated to take 38 to 45 days, but our full cycle time of spud to sales is taking a little bit longer than originally planned with a current estimate of 75 to 90 days depending on availability of pipelines and infrastructure. We expect the full cycle spud to sales time to drop as we ultimately conduct more infield drilling operations.

As to our take-away capabilities for the Haynesville with Bethany-Longstreet and Longwood, Chesapeake markets our gas for a fee and in return our gas is sold with theirs under existing transportation agreements and we have no midstream infrastructure expenses. In East Texas we have in place the infrastructure needed to handle our initial Haynesville production from the Beckville and Minden fields with any additional increase in capacity being paid for and installed by a third-party midstream companies.

On acreage cost in the play, when applying the proceeds from our Chesapeake transaction we have a $2,500 per acre credit which leaves, for the most part, our completed well cost only when calculating a finding and development cost for Haynesville wells. As to cost, we continue to see reductions across the board with 25% to 50% savings.

Focusing some on our core areas the Bethany-Longstreet, Caddo and DeSoto Parishes of Louisiana where we are 50% owners with Chesapeake and Plains, we reported our branch 11H-1 at 15.3 million per day and are currently flowing back our ROTC 1H-1 and Branch 2H-1 with completion operations commenced on our Bryan 25H-1 and Wallace 36H-1 wells. We expect to report results on these wells along with our initial horizontal Haynesville Shale wells in East Texas once production rates have been established.

At Longwood and Northern Caddo Parish we participated for a 17% interest in the Exco-Sharp 1H-1 well which had an initial production rate of 8.6 million cubic feet per day from a 12 stage frac. The well is approximately 1 mile north of our Percy Sharp 7H-1 which had an eight stage frac that tested at 5.1 million cubic feet per day.

We’ve completed a third well in the field, the Bohnert 28H-1 and are waiting on a pipeline connection which we estimate to be hooked up within 30 days. We are encouraged by the improved results from the Sharp 1H-1, although we do not currently have plans to spud any additional wells in the field in the second half of 2009.



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May. 07. 2009 / 10:00AM, GDP — Q1 2009 Goodrich Petroleum Earnings Conference Call

A meaningful acquisition that Gil mentioned earlier in the Haynesville, we executed two separate agreements to farm in approximately 3,400 net acres in Northwest Louisiana. The acreage acquired is located in two separate areas of Caddo and DeSoto Parishes. A portion of the acreage is located within the Bethany-Longstreet field and Northern DeSoto Parish and the remainder is located in the Greenwood-Waskom field in Central Caddo Parish. The Greenwood-Waskom field, for your information, is situated north of Bethany-Longstreet and south of Longwood.

This acquisition adds over 60 gross, 40 net potential horizontal Haynesville locations and we believe the acreage is very well located and highly prospective based on offset activities. In fact, a portion of the block sits between our Holland and Graham wells at Bethany-Longstreet which tested at 14.5 million a day and 11.5 million a day respectively. We anticipate drilling the initial well on each of these blocks within six months.

As Gil mentioned, this acquisition increases our net Haynesville Shale acreage position by approximately 5% to 66,500 net acres which is exclusive of our Angelina River trend acreage. In East Texas at Beckville Minden we had hoped and expected to have results on the Lutheran Church 5H-1 well, but had been delayed due to coil tubing problems. We expect to have the coil tubing removed and resume fracking operations before long and we’ll issue a release on the well once we have a sustained production rate.

We are currently flowing back our J.K. Williams 7H well and expect to release production results on the wall within the next two weeks. We’ve completed our KF Carter A2-B2 well, a Cotton Valley Taylor Sand horizontal well in which we have a 100% interest in 4 million cubic feet per day. We are currently drilling two additional Haynesville Shale horizontal wells in the field — the Taylor Sealey 3H and the Beard Taylor 1H and two additional Cotton Valley Taylor Sand horizontal wells, the GT Waldrop 5H and the AB Taylor 3H.

In the Angelina River trend, as announced on the press release, we completed four co-mingled Travis Peak Pettet wells with an average initial production rate of 5 million cubic feet per day as well as a James Lime horizontal well which had an initial production rate of 7.3 million cubic feet per day. There are no additional Travis Peak, Pettet or James Lime horizontal wells planned for the remainder of 2009. With that I would like to now turn it over to David Looney to walk you through the financials.

David Looney - Goodrich Petroleum — EVP, CFO

Thank you, Rob. Reported revenues for the first quarter of $28.5 million were based on average prices of $4.11 per Mcf of gas and $33.50 per barrel of oil. On gas our average price was approximately $0.44 below the average Henry Hub price during the quarter which is within our historical target range of $0.50.

On oil, which represents only about 5% of our total revenues, we realized a wider basis than usual off of WTI Cushing prices during the quarter due primarily to a pricing basis change implemented by one of our former primary purchasers of crude and liquids. We’d expect this number to return to the more historical levels of $3 to $5 below WTI going forward.

I’d like to emphasize here that these prices do not include the impact of $21 million in realized gains on our commodity derivative portfolio during the quarter as none of our derivatives are designated as hedges for accounting purposes. Thus all of our hedging gains, realized and unrealized, are reported below the operating income line in our financial statements as presented under GAAP. Again for the quarter, we had a realized gain of $21 million on our gas hedges and an unrealized gain of $16 million on those same hedges.

Looking at cash flow, our EBITDAX for the first quarter was approximately $31 million. Discretionary cash flow, defined as net cash from operations before changes in working capital, was $27.7 million for the quarter. As a reminder, both EBITDAX and Bcf were positively impacted by the $21 million in realized gains on the derivative contracts we just talked about.



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FINAL TRANSCRIPT

May. 07. 2009 / 10:00AM, GDP — Q1 2009 Goodrich Petroleum Earnings Conference Call

Our capital expenditures booked during the first quarter totaled $87.2 million, as Gil mentioned. However, as often happens given the timing of our well program and payment obligations, we actually paid for a total of $103 million in capital expenditures during the quarter which will show up on our cash flow statement in our 10-Q to be released later today.

This is essentially the unwind of the capital expenditure accrual we had built up at year end 2008; you may recall that we disclosed 2008 capital expenditures of $380 million, but on our cash flow statement at year end we had only paid for $363 million and this difference was essentially paid in the first quarter of this year.

Thus when you compare the $27.7 million in discretionary cash flow with this $103 million outflow, and after taking into account some other working capital changes, you’ll see that our cash position decreased by approximately $69 million from $147 million at year end to $78 million at March 31.

Focusing on the expense side of the income statement, our lease operating expense in the quarter was approximately $9 million or $1.32 per Mcfe on a unit basis, which is down slightly from the $1.35 per Mcfe rate in the first quarter of 2008 and down almost $0.07 per Mcfe from the rate in the fourth quarter of 2008.

We expect LOE cost to continue to trend downward as we recognize the full benefit of our saltwater disposal projects as well as having a greater percentage of our production coming from the Haynesville Shale play, which is expected to have lower salt water disposal and compression charges.

Production and other taxes for the quarter totaled $1.5 million, or $0.22 per Mcfe of production, versus $1.3 million or $0.24 per Mcfe for the prior year period. The per-unit expense is lower due primarily to lower commodity prices, but higher than it otherwise would have been because the ad valorem tax expense accrued during the quarter is based on our preliminary estimate of 2009 ad valorem taxes, which may not fall as much as commodity prices have fallen in the first part of the year.

Transportation expenses totaled $2.6 million in the first quarter or $0.38 per Mcfe of production versus $1.9 million or $0.36 per Mcfe in the first quarter of 2008. Once again this is well within our expected range of $0.35 to $0.40 per Mcfe.

DD&A totaled approximately $33.7 million for the quarter or $4.94 per Mcfe of production versus $25.1 million or $4.76 in the first quarter of 2008. As a reminder, the DD&A rate for the first quarter of 2009 is a function of our year-end 2008 reserve report.

The rate did increase sequentially from the $4.11 per Mcfe in the fourth quarter of 2008 and this was due primarily to negative revisions of proved developed reserves resulting from the lower prices used in the year-end 2008 reserve report compared to those used in the midyear 2008 reserve report. Based on our calculations these revisions accounted for approximately 70% of the rate increase from the fourth quarter of 2008 to the first quarter of this year.

As we’ve previously stated, Haynesville Shale reserves comprise less than 2% of our total year-end 2008 proved reserves, thus there was virtually no impact on our DD&A rate during the first quarter of 2009 due to the Haynesville Shale program. While we do not expect the Haynesville Shale program to have any impact on the DD&A rate in the second quarter of 2009, we fully expect the last half of the year to begin to reflect our efforts in this area. Based on our receiving a midyear reserve report which will be used to adjust the second half of the year DD&A rate if appropriate.

Our exploration expense totaled $2.2 million for the first quarter or $0.33 per Mcfe versus $2 million or $0.38 per Mcfe in the first quarter of 2008. And as a reminder, the majority of this number, or $1.5 million, is a non-cash charge which is the amortization of our undeveloped leasehold position.

Our G&A expense was $7.1 million for the first quarter, or $1.04 per Mcfe of production, versus $5.4 million or $1.03 per Mcfe in the first quarter of 2008. Of the $7.1 million, $1.6 million or 22% of the total was a non-cash expense related to stock-based compensation. The primary reason for the higher absolute dollar expense amount was due to the Company’s approximately



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May. 07. 2009 / 10:00AM, GDP — Q1 2009 Goodrich Petroleum Earnings Conference Call

28% headcount increase year over year. Sequentially versus the fourth-quarter G&A was up only slightly and this was due primarily to a number of annual expenses which occur in the first quarter of each year.

As many of you have no doubt noticed, the first quarter was significantly impacted by a new accounting rule known as FSP APB 14-1. While I have no intention of getting into the intricate details of this new accounting pronouncement, suffice to say it impacts the accounting for the convertible senior notes we issued in December of 2006 which $175 million notes account for approximately 70% of our total debt portfolio. As such, you’ll see adjustments to our current period and prior period debt levels, equity accounts, deferred taxes and interest expense.

Essentially the new principle requires us to calculate interest on the adjusted balance of these convertible notes at a much higher rate than the coupon rate, in our case 8.5% versus the 3.25% coupon. The difference between the interest expense calculated using this higher rate versus the actual coupon is entirely non-cash. As such, during the quarter we recognized an additional $1.8 million in non-cash interest expense as a result of our adoption of this principle. And we would expect this level of non-cash interest expense to recur and increase slightly each quarter until December of 2011.

Similarly, the carrying value for this debt on our books decreased from the original $175 million to approximately $154 million at March 31, 2009 but it will ultimately accrete back up to the $175 million level by the same December 2011 date which is the first put date under the terms of the agreement. I’ll be happy to answer any questions regarding this accounting change at the end of the call.

Finally, we reported net income applicable to common stock of $1.6 million in the first quarter after deducting $1.5 million in preferred dividends. This compares quite favorably to a net loss applicable to common stock for the first quarter of 2008 of $27 million.

Turning now to the balance sheet, we disclosed in our earnings release yesterday, and both Gil and Rob have mentioned, our capital expenditure budget for 2009 has been reduced to $230 million. As this budget was very front end loaded, of which $87 million was accrued and spent in the first quarter, we expect the $78 million of cash on hand on our balance sheet at March 31 to carry us through the remainder of the year without needing to draw on our bank credit facility.

This cash combined with our strong hedge position and increasing production profile should allow us to exit 2009 with $10 million to $15 million in cash and short-term investments and nothing drawn out our bank facility. While this is obviously subject to change due to many factors, we’re fully committed at this point to closely manage the outflow of funds for the remainder of this year and into 2010.

As I’m sure you no doubt saw, we closed on our new bank facility earlier this week and we now have the flexibility to continue our aggressive yet measured development of our asset base well into 2012 and beyond. We were extremely pleased with the reception we received in the bank market and look forward to expanding those relationships in the future. With that I’d now turn it back over to Gil for some closing comments.

Gil Goodrich - Goodrich Petroleum — Vice Chair, CEO

Thank you, David. While we are moderating our pace of development with the announced reduction in 2009 capital expenditures to ensure we preserve ample liquidity as we go into 2010, we are also prepared to resume a more aggressive development plan at this time as market conditions dictate.

in addition, we are confident we can deliver double-digit production volume growth in 2009. With only 5% of first-quarter production volumes coming from Haynesville Shale wells and with approximately 7 additional Haynesville Shale horizontal wells already completed and just beginning flow back or soon to be completed, we are anticipating another quarter of solid



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May. 07. 2009 / 10:00AM, GDP — Q1 2009 Goodrich Petroleum Earnings Conference Call

sequential growth and meaningful Haynesville Shale reserve growth during 2009. That concludes our prepared remarks and I’ll now turn it back over to the operator for questions.

QUESTIONS AND ANSWERS

Operator

(Operator Instructions). [Ronnie Isman].

Ronnie Isman - Analyst

Good morning, guys. What are you seeing right now in terms of well costs in the Haynesville?

Robert Turnham - Goodrich Petroleum — President, COO

Yes, Ronnie, this is Rob. We’ve seen a pretty dramatic drop in cost, really on the completion side more than anything. I think we have historically been averaging $8 million. If you look at the wells that we’ve drilled in the past, we’ve seen pressure pumping, the stimulation portion of that AFE dropped pretty dramatically over the last two to four months.

Our current AFC estimate is about $7 million. It depends on the number of stage fracs obviously. We’re currently planning for 10 stage fracs, at least in our better areas and potentially 12 stage fracs in some of the other areas which would increase the cost by probably $250,000 per well.

Ronnie Isman - Analyst

And do you guys have color as to why the Sharp 1H-1 well was so much better than the [Percy] Sharp well?

Robert Turnham - Goodrich Petroleum — President, COO

The first obvious reason is that they had 12 successful frac stages performed, pumped to completion. On the Percy Sharp well we only had eight that were pumped to completion. Other than that there was a little bit more fluid pumped in the Exco well than our will there on the Percy Sharp. But other than that I think it was just execution with that frac and getting all 12 stages off.

Ronnie Isman - Analyst

Thank you, guys.

Operator

[Crystal Choi].

Crystal Choi - Analyst

Good morning. Going back to the Exco-Sharp well just a second ago, does that change your view I guess of the overall Longwood field area at all?



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May. 07. 2009 / 10:00AM, GDP — Q1 2009 Goodrich Petroleum Earnings Conference Call

Gil Goodrich - Goodrich Petroleum — Vice Chair, CEO

Good morning, Crystal, this is Gil. It certainly is encouraging and positive. I would say to follow-up to the previous question, we don’t see anything geologically or in the rocks that’s any different between the two areas, so we do tend to think that it’s more in the completion and the things that Rob mentioned.

So, yes, the bottom line is we’re certainly much more encouraged about the area than we were. We would not have written it off by any means before and this gives us some added emphasis to get back up there. Although as Robert mentioned in his prepared remarks, we don’t have any additional wells planned there this year. But hopefully some time in ‘10 we’ll get back up there and drill some additional wells.

Crystal Choi - Analyst

Okay. And can you refresh my memory on what kind of benefits you’re seeing I guess from both the saltwater disposal system and having your contribution from Haynesville wells? I’m trying to get a sense of how I should think about LOE for the rest of the year?

David Looney - Goodrich Petroleum — EVP, CFO

Yes, Crystal, this is David. Certainly in the first quarter of this year I would say given that, as we mentioned, less than 5% of our production from Haynesville — virtually no impact in the first quarter due to the Haynesville production. The saltwater disposal, obviously we’ve had a number of ongoing programs which have at various points in time brought down the saltwater disposal cost in those particular fields.

I think we’ve really just now completed most all of those projects that we were intending to complete. And at the end of the day that will have some impact overall, maybe $0.05 to $0.10, who knows, on the whole. And then as we move into more and more production coming from Haynesville, I think that’s where you’re likely to see the greater reductions in cost. But again, that’s not going to show up until the Haynesville really starts to become a meaningful piece of our overall production.

Robert Turnham - Goodrich Petroleum — President, COO

And, Crystal, this is Rob. I might add on the Haynesville none of us know for sure, but we’re modeling certainly less than $0.10 an M. If we get a 6.5 Bcf tight curve well or the LOE on these Haynesville wells, it all depends on volumes. And then what we do know is that we have less saltwater disposal and no additional compression needs. As you start baking in two-thirds of our CapEx budget being spent on those wells and they’re coming in at a much reduced LOE we would expect that number to continue to fall once we get more critical mass of Haynesville wells.

Crystal Choi - Analyst

Great. Thank you.

Operator

Joe Magner.



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May. 07. 2009 / 10:00AM, GDP — Q1 2009 Goodrich Petroleum Earnings Conference Call

Joe Magner - Tristone Capital — Analyst

Good morning. I just wanted to walk us through some of the details of the $70 million CapEx reduction. I think at various points in time you’ve talked about [fuel and] different portions of that out, just curious what was actually taken out?

Robert Turnham - Goodrich Petroleum — President, COO

This is Rob, I’ll take a shot at that and Gil may want to pipe in. We pulled one rig out of the Chesapeake joint venture, we had been running three, pulled one out for the second half of this year, they were fine with doing that and it allows us to reduce the CapEx primarily at Bethany-Longstreet. As you know, that acreage is basically held by production, we have no lease exploration issues there and therefore a lot of time to drill wells there.

On the operated side, as we said, we’re going to reduce down to two operated rigs. We really have no additional Travis Peak vertical, James Lime horizontal wells planned. We also are expecting to defer completion on four or five wells in East Texas into 2010 where we see higher gas prices. So it’s really a combination of slight reduction in non-operated activity, but a bigger reduction on the operated side.

And in addition, Beckville Minden where we’re spreading these Haynesville wells out drilling wells, probably right now we expect 80% to 85% of that acreage is already held by production and we have plenty of time to hold the remainder over the next couple of years. So really no lease expiration issues.

We just worked our way back from baking in the strip prices for our unhedged volumes, trying to determine at what CapEx level we would ensure that we get into 2010 with some cash and nothing borrowed on our revolver and then cut accordingly and have the luxury of doing that just with our staggered rig contracts.

Joe Magner - Tristone Capital — Analyst

And then there was an acreage acquisition wedge in that budget. Is that still in there for now or have you peeled some of that back from your plans?

Robert Turnham - Goodrich Petroleum — President, COO

We still have a plug number in there. When you look at our revised inventory chart it will still have $31 million of leasehold and other expenses — that other would include various cost across miscellaneous projects as well as infrastructure and as well as leasehold. So the leasehold acquisition number is much lower than that, probably $12 million to $15 million, and then it’s just the rest is a plug number to cover any unforeseen cost overruns or infrastructure expenses.

Joe Magner - Tristone Capital — Analyst

Okay, thanks for that. And then I think you guys have been out talking about the impact of cutting CapEx back to around 250, you were still expecting 25% growth — year-over-year growth forecast. The pullback to 15 to 20, can we assume that that is the impact of some of the delay completions and some of the timing issues to get some of these wells turned online?

Gil Goodrich - Goodrich Petroleum — Vice Chair, CEO

Hi, Joe, this is Gil. It is a couple of things. One is we said we (inaudible) $70 million out, so it gets to actually a $230 million number. So on the $250 million you gave with $25 million, I think we’re probably in the same ballpark there. And, yes, it is delaying some



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May. 07. 2009 / 10:00AM, GDP — Q1 2009 Goodrich Petroleum Earnings Conference Call

completions, kind of staggered us as we go through the year and preserving some capital so we’ve got the flexibility of wells those wells down and cased and ready to be completed at such point and time as we see market conditions improve.

So likely, as we currently sit, that means 2010, if things turn around before then it could be a little earlier than that. And I would just add one other thing that Rob didn’t mention is that we also in an agreement with our partners, EnCana and St. Mary down at Angelina River also agreed to shut down operations there at the end of the first quarter. So no additional vertical or James Lime wells horizontally planned to be drilled down there.

Joe Magner - Tristone Capital — Analyst

Okay, thanks for that. And can you discuss at all the magnitude of the impact on the reserve revision you saw in Q1 and whether — or I guess if the bulk of it was in pause or if there was any impact to the PDP?

Robert Turnham - Goodrich Petroleum — President, COO

Well as to DD&A, it was all on the developed side because we’re successful efforts and you can only use developed reserves. And it’s really just the difference between pricing for the most part — or the majority of the difference is pricing from midyear reserve to year-end reserve. And as David said, I believe that about 70% of the impact that we saw came from the price revisions or the revisions between those two reserve reports.

And then back on your previous question, just to clarify, I think you said 15% to 20% growth. We’re expecting 15% to 25% growth with the revised budget. So if you took the midpoint of both of those numbers, 20% would be based on $230 million versus 25% at $250 million and that seems about right to us.

Joe Magner - Tristone Capital — Analyst

Okay, thanks for that clarification. And then just two other wells that you had in your presentation in the Caddo Pine Island. There were a couple of wells up there that were either drilling or waiting on completion. Can you provide any update on those?

Gil Goodrich - Goodrich Petroleum — Vice Chair, CEO

Yes, Joe, this is Gil. We do have two additional wells which are down up there that would be our Hall 5H and our [Linear] well in conjunction with Matador Resources. We do have plans to begin completing those wells; we likely are going to do that in stages. I think the first one is likely going to be — start completion later this month and we’ll just take it in stages and flow it back a little bit and see how it looks and make some determination what we do there.

Joe Magner - Tristone Capital — Analyst

Okay, thank you.

Operator

Richard Tullis.

Richard Tullis - Capital One Southcoast — Analyst

Just to verify on the latest well cost for the Haynesville is the $7 million, that was the 10 stage completion that you were referring?



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FINAL TRANSCRIPT

May. 07. 2009 / 10:00AM, GDP — Q1 2009 Goodrich Petroleum Earnings Conference Call

Gil Goodrich - Goodrich Petroleum — Vice Chair, CEO

That’s right, Richard.

Richard Tullis - Capital One Southcoast — Analyst

Okay. And then the 12 stage would add perhaps another $250,000 or so?

Gil Goodrich - Goodrich Petroleum — Vice Chair, CEO

Our latest bid has really dropped dramatically to about $1.1 million as to the simulation portion of the completion. So on our 10 stage fracs, so that would be $110,000 per stage just for the stimulation, certainly need to add more — it’s probably $250,000 to $300,000.

Richard Tullis - Capital One Southcoast — Analyst

Okay. And then on the LOE associated with the Haynesville wells, I know you had mentioned about $0.10 that you’re modeling. Is that just for the first couple of years or is that long-term over the majority of the (inaudible)?

Robert Turnham - Goodrich Petroleum — President, COO

I think we think the blended average is going to be about $0.32 over the life of the well, the early years before compression are in that $0.10 range. Actually if you do the math it’s a good bit less than 10% in year one and I think Petrohawk and others will confirm that’s their modeling also. But as you add compression, and that is the big question, when does it occur; I think we have modeled in the third year, maybe at the start of the fourth year. It all depends on rate and pressures as to when that compression kicks in.

But that is when you would start to see the increase in LOEs, is when you have to layer in compression cost. It is really almost like a fixed LOE that goes up once the compressors are added.

Richard Tullis - Capital One Southcoast — Analyst

Okay. On the well cost, do you think we are pretty much close to the minimum there, or do you foresee another couple hundred thousand dollars that you could eek out of it?

Gil Goodrich - Goodrich Petroleum — Vice Chair, CEO

Richard, this is Gil. Two things, one is — just to make sure we’re all on the same page — the frac that we are talking about and the quotes we are given are resin-coated fracs. That is an important issue.

Secondly, we are really just beginning, I think, to see improvement on the cost side. Really within the last 60 days, we have really started to see I think meaningful improvements.

So our view internally is if gas stays in the $3.50 range and continues there, you are going to continue to see, albeit flattening, a continued decline in the gas directed rig count. So many things just don’t work at the current conditions, and the only thing that can give is the cost side of the equation. So we think there is still room to go there, unless and until the market for gas kind of turns around.



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FINAL TRANSCRIPT

May. 07. 2009 / 10:00AM, GDP — Q1 2009 Goodrich Petroleum Earnings Conference Call

Richard Tullis - Capital One Southcoast — Analyst

Okay, very good. Looking at your 42,000 or so net acres down in the southern part of the Haynesville play, or at least what some folks think is in the play, what are your thoughts on your acreage down there like Nacogdoches County, Angelina area?

Gil Goodrich - Goodrich Petroleum — Vice Chair, CEO

Very happy to see others begin to drill in that area and come to us, and our position down there is to watch the play unfold. We do have some data from a couple of wells that we have drilled on our surprise prospect and other older wells in the area that give us comfort that at least on a significant percentage of that acreage, the Haynesville is developed; looks to be on the order of a couple hundred feet in thickness. And we would certainly encourage others to continue to drill in our direction.

Richard Tullis - Capital One Southcoast — Analyst

Okay. And then finally, not to get too detailed, but how do you think you will report the wells in progress now? I know you have three flowing back, three completing. Will you just wait and do your three flowing back at the same time or —?

Gil Goodrich - Goodrich Petroleum — Vice Chair, CEO

I think we will take them one at a time and see how — we have an obligation on both sides of the equation. And when we feel like there is some material piece of information that is in our possession, we typically put it out for public consumption. So I hate to say anything more than that. As the data comes in, we will put it out appropriately.

Richard Tullis - Capital One Southcoast — Analyst

Very good, thanks a bunch. Appreciate it.

Operator

Ron Mills.

Ron Mills - Johnson Rice — Analyst

Good morning. Just to follow up on one of Richard’s questions. The Angelina River area, Rob, can you break down that 42,000 acres between Surprise, Bethune, East Lake and the Cotton/Cotton South areas?

Robert Turnham - Goodrich Petroleum — President, COO

Yes, let’s start with Surprise where we have the three wells that have penetrated, that’s kind of a net 2,900 net acres for us. If you look at the Cotton prospect, which would it be Nacogdoches County along the river, we’re probably I would say 12,000 net acres there, don’t hold me to it, but the gross is roughly 24,000, we have 40% of that roughly.

And then the remainder would be I guess Cotton South is probably another — I would say it’s a little bit less than that, probably 10,000 acres. And then the remainder would be over at what we call Bethune and East Lake which is probably the closest acreage that we have. I’d have to get the exact number, but that would be I would say somewhere in the 10,000 or 12,000 net acres.



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FINAL TRANSCRIPT

May. 07. 2009 / 10:00AM, GDP — Q1 2009 Goodrich Petroleum Earnings Conference Call

Ron Mills - Johnson Rice — Analyst

Okay. And I think we had talked in the past or you had mentioned in the past about some of your early completions in Bethany-Longstreet and the difference in terms of some of the completion and different choke sizes and what that may lead to potential shallower declines. I’m just curious how on the Graham and Holland wells, now that you have a little bit more production history, how the production from those wells has held up and how they’re tracking relative to that 6.5 p type curve?

Robert Turnham - Goodrich Petroleum — President, COO

Yes, it’s still way early on the EURs and obviously it will depend on Netherland Sewell’s analysis and then what we think. But as I’ve kind of mentioned to others, we did a grab where we flowed back on a reduced choke size of 2,064 that came in at 11.4 million a day, it was basically flat for the first couple of weeks and averaged about 9.2 million a day on the first 30 days.

And if you look at our tight curve that we include in our presentation, that would be a flatter initial decline than what we’ve projected. The 2464’s choke well, the Holland, came in at the higher rate, but followed more similarly to that decline curve. At the end of the day your initial decline rate will be tight fitted to the tight curve that will ultimately spit out what that EUR will be.

So we’re still experimenting with choke sizes. In the better areas no question you can choke the wells back and kind of help maintain your pressure drop and hopefully ultimately increase your EUR. On the areas that have less porosity and permeability we think you need to go ahead and open the choke up a bit to unload the well. We are seeing a little bit flatter curves in those areas, as are other companies. And just do a lack of (technical difficulty) permeability the more open choke appears to me more applicable there.

Operator

Ellen Hannan.

Ellen Hannan - Weeden & Co. — Analyst

Good morning. I just had a quick question for you on in your Chesapeake joint venture, what’s the flexibility that you have? Are you — are either one of you able to either propose and/or step out of a well or could you describe that? And also I just wanted to ask, are you paying any fees to terminate any rigs?

Robert Turnham - Goodrich Petroleum — President, COO

Good morning, Ellen, both good questions. Hopefully we’ve detailed this before but we’ll be happy to do it again. We specifically built into our agreement with Chesapeake kind of barriers or governors on both ends and that is we did not want to be where we did not have the ability to propose wells in the event they might want to be more active somewhere else.

So, yes, we have the ability to propose wells to them with an election period. And if they elect to not participate we have the opportunity to take that half interest and drill the well ourselves. So we’re protected there.

On the other side it was important to us that we were not run over like a herd of cattle with 100 (technical difficulty) at one time. So we proposed and they agreed to a development committee process whereby we meet quarterly and that committee sets the budget for the following quarter. And without both parties’ agreement that budget cannot exceed $50 million gross for both parties.



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FINAL TRANSCRIPT

May. 07. 2009 / 10:00AM, GDP — Q1 2009 Goodrich Petroleum Earnings Conference Call

So we’re covered; the maximum number of wells that could be proposed to us in the agreement would equate to a gross of $200 million per year and we’d have half of that, so $100 million. And so where we were in terms of reducing from three rigs to two rigs was really by mutual agreement between the two parties.

As to your second question, yes, we have two rigs, Ellen, that will roll off under normal contract terms the very end of July and then one August the 1st. We have another one that runs until December. I think someone here will probably correct me, one of those rigs will run pretty close to the mid-summer termination; the other one we will release a bit early and pay a fairly modest fee.

And then the one that runs through December we will likely release it, I think in our current modeling it’s either in August or September, and pay a fee probably in the neighborhood of $1 million or so. That would save us a substantial amount of CapEx from there on until the end of December.

Ellen Hannan - Weeden & Co. — Analyst

Right, thanks for that reminder. Thanks.

Operator

Ron Mills.

Ron Mills - Johnson Rice — Analyst

Rob, just in East Texas you’ve had a number of recent wells over the course of the past month showing better results, particularly in Southern Harrison and Northwest Panola County. Are you hearing of any different completion techniques? It sounds like some of the recent ones announced this morning have more frac stages. Any thoughts in terms of how you’re completing your wells in Beckville Minden in terms of number of stages and what your lateral length is?

Gil Goodrich - Goodrich Petroleum — Vice Chair, CEO

Yes, Ron, this is Gil. As we said in the release, we’re currently flowing back our J.K. Williams well. It was — don’t hold me to the exact number — 4,400, 4,500 feet of lateral length. We broke that up and actually did 13 stages on it. We are comfortable saying that we are pleased with the mechanics of the frac in terms of putting it away. And it was a resin coated frac and we’re beginning flow back now.

Ron Mills - Johnson Rice — Analyst

And is it something where the Texas play may lend itself to having more frac stages than Louisiana, at least potentially based on the different rock qualities?

Gil Goodrich - Goodrich Petroleum — Vice Chair, CEO

I think the main driver there is twofold — it’s the length of the laterals and I don’t see that being unique to Texas or Louisiana, I think in both cases getting out 4,400, 4,500 feet makes sense and you’re seeing that.



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FINAL TRANSCRIPT

May. 07. 2009 / 10:00AM, GDP — Q1 2009 Goodrich Petroleum Earnings Conference Call

The next question is, how much do you break each interval down to? And we’ve typically been staying around 300 to 350 feet per stage. And others have experimented initially with bigger intervals, some may ultimately want to go to smaller intervals and the idea of going in smaller intervals you get more frac intensity per stage.

Ron Mills - Johnson Rice — Analyst

But in your initial wells you’ll plan on sticking with that 300 to 350 feet —

Gil Goodrich - Goodrich Petroleum — Vice Chair, CEO

Yes.

Ron Mills - Johnson Rice — Analyst

Frac length?

Gil Goodrich - Goodrich Petroleum — Vice Chair, CEO

Yes, that’s our current thinking and plan.

Ron Mills - Johnson Rice — Analyst

All right, thank you very much.

Operator

[Mike Salia].

Mike Salia - Analyst

Sorry if I missed it, but did you see where you’re planning to run the two operated breaks in the second half of the year?

Robert Turnham - Goodrich Petroleum — President, COO

Yes, Mike, this is Rob. We’re going to keep it in Beckville and Minden where we’re drilling both Haynesville horizontals and we still have plans for a couple of additional Cotton Valley Taylor Sand horizontal wells.

Mike Salia - Analyst

Okay. And then on the J.K. Williams and the Lutheran Church, can you say where the costs are on those? And then do you expect, as you get into a development mode, to get in that $7 million range over there as well?



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FINAL TRANSCRIPT

May. 07. 2009 / 10:00AM, GDP — Q1 2009 Goodrich Petroleum Earnings Conference Call

Robert Turnham - Goodrich Petroleum — President, COO

Yes, again it all depends on the number of stages. But as Gil just said, we had 13 stages on the J.K. Williams, so obviously that cost is going to go a little bit higher than what we had projected at $7 million on a 10-stage frac. So right now if you want to just be conservative, put a couple hundred thousand dollars per stage of frac and rig time and other goods and services on top of that. So that would get us — we don’t have all our costs in yet, we’re still flowing the well back. But $7.5 million, $7.6 million under that kind of calculation.

So, we’ll see. We just need to continue to work on those costs. If we’re successful in fracking less stages then we’ll get back to that $7 million range. But more than likely, if this 13-stage frac works and we’re able to get 4,500 feet on each well and in some cases we not may not be able to do that just due to acreage or mechanical issues. But at that level obviously that yields a higher number of stages and we’ll spend a little bit more than the $7 million.

Mike Salia - Analyst

Okay. And in Angelina it sounds like you’re happy to just watch others drill the Haynesville down there, no plans to — I think you had at one point talked about maybe drilling a few horizontal Haynesville wells yourself down there, but has that been nixed?

Robert Turnham - Goodrich Petroleum — President, COO

No, we’ve never really talked about that or at least planned for that. We initially set out to drill vertical wells and ultimately the plan would be to go horizontal. But at this point in time we have so much on our plate and our CapEx budget is set and the play is early. We feel like and hear the play is coming our way with encouraging results on the EOG Gammage well. And we’re just going to take a kind of wait and see approach on that acreage. If it comes closer to us that will help derisk it and then at some point we’ll test it.

Mike Salia - Analyst

That makes sense. Lest one for me is, with that your production guidance now is any of that dependent on Haynesville production from East Texas?

Robert Turnham - Goodrich Petroleum — President, COO

Oh, yes, sure, that’s still — a big portion of our CapEx budget is coming from East Texas. Except for the handful of wells we’re talking about deferring into 2010, the rest of the volume growth is going to come from both East Texas and our Chesapeake joint venture.

Mike Salia - Analyst

Thank you very much.

Operator

Ladies and gentlemen, that concludes today’s presentation. I would now like to turn the conference back over to Mr. Goodrich for closing remarks.



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FINAL TRANSCRIPT

May. 07. 2009 / 10:00AM, GDP — Q1 2009 Goodrich Petroleum Earnings Conference Call

Gil Goodrich - Goodrich Petroleum — Vice Chair, CEO

Thank you. We appreciate your participation this morning and very much look forward to reporting second-quarter results to you later this summer.

Operator

Thank you for your participation in today’s conference. This concludes the presentation. You may now disconnect. Good day.

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