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FINAL TRANSCRIPT

Mar. 13. 2007 / 11:00AM, GDP — Q4 2006 Goodrich Petroleum Earnings Conference Call

CORPORATE PARTICIPANTS

Gil Goodrich
Goodrich Petroleum — Vice Chairman, CEO

Rob Turnham
Goodrich Petroleum — President, COO

David Looney
Goodrich Petroleum — EVP, CFO

CONFERENCE CALL PARTICIPANTS

Ellen Hannan
Bear Stearns — Analyst

Robert Lynd
Simmons & Co. — Analyst

Richard Moorman
Capital One Southcoast — Analyst

Ron Mills
Johnson Rice — Analyst

Brian Kuzma
JPMorgan — Analyst

Steve Burnham
Pritchard Capital Partners — Analyst

Nic Van Broekhoven
Foyer — Analyst

PRESENTATION

Operator

Good day, ladies and gentlemen, and welcome to the Goodrich Petroleum fourth-quarter 2006 earnings conference call. My name is Tonya and I’ll be your coordinator for today. At this time all participants are in listen-only mode. We will be facilitating a question-and-answer session towards the end of today’s conference. (OPERATOR INSTRUCTIONS). As a reminder, this conference is being recorded for replay purposes. I would now like to turn the presentation over to your host for today’s call, Mr. Gil Goodrich, Vice Chairman and Chief Executive Officer. Please proceed.

Gil Goodrich — Goodrich Petroleum — Vice Chairman, CEO

Good morning, everyone, and welcome to the fourth-quarter and full-year conference call of Goodrich Petroleum. I’d like to begin by introducing the management team members with me here in Houston this morning — Rob Turnham, our President and Chief Operating Officer; David Looney, our Executive Vice President and Chief Financial Officer; Mark Ferchau, Executive Vice President, Director of Engineering & Operations; and Jim Davis, our Senior Vice President in charge of Engineering & Operations.

If for some reason you have not received a copy of the earnings release we put out this morning, you may obtain one via our website at www.GoodrichPetroleum.com or you may call my personal assistant, Becky [DeLatin] at 713-780-9494 and she’ll be happy to fax you a copy.


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Mar. 13. 2007 / 11:00AM, GDP — Q4 2006 Goodrich Petroleum Earnings Conference Call

We would also like to make everyone aware that the comments that we make this morning and answers to questions that we may give during this teleconference call may be considered forward-looking statements which involve risks and uncertainties and we have detailed those risks for you in our SEC filings.

To begin, 2006 was a tremendous year of progress for Goodrich Petroleum; a record pace of drilling resulted in 105 gross wells being drilled in 2006 with a 98% success rate. Our increased drilling activity allowed us to grow production volumes by approximately 82% year-over-year compared with 2005. Despite drilling approximately 10 new test wells in the Cotton Valley Trend on acreage outside of our core position in the trend where results did not meet our expectations, we nevertheless successfully grew our Cotton Valley Trend production volumes on a gross basis by approximately 125% during the year 2006 with an exit rate at year-end ‘06 of approximately 57.5 million cubic feet of gas equivalent or MCFE per day.

Since the end of the year and aided by two additional rigs that we added in the Cotton Valley Trend in the fourth quarter we have achieved further production volume growth since the end of the year and are currently producing gross Cotton Valley Trend volumes of approximately 61.5 million cubic feet of gas equivalent per day. The increased level of drilling activity also resulted in a record level of proved reserves at year-end of approximately 206 Bcf equivalent. At year-end our proved reserves were 90% natural gas, 43% developed and 84% were related to the Cotton Valley Trend.

Like our peers, our year-end reserves were calculated using December 31, 2006 SEC mandated pricing of approximately $5.63 per MMbtu and $57.75 per barrel. Included in the year-end proved reserve calculation was a reserve revision of approximately 46 BCFE due to lower natural gas prices at year-end when compared with the prior year. Also included in the year-end reserve were further revisions due to engineering and performance of approximately 30 Bcfe. After adjusting for or excluding the revisions due to price, proved reserves at year-end would have been approximately 252 Bcfe or in line with our internal estimates and projections for year-end proved reserves.

Looking at all-in finding and development cost, we had approximately $269 million in capital expenditures during 2006. Included in this number is approximately $17 million related to undeveloped leasehold acquisitions and facility related cost. After excluding leasehold and facility related cost and excluding reserve revisions due to price, reserve additions totaled approximately 95 Bcfe for an all-in finding and development cost of approximately $2.66 per Mcfe.

Focusing solely on the Cotton Valley Trend, we incurred drilling, development and reserve acquisition capital expenditures during the year of $217 million. Again, excluding reserve revisions related to price in the Cotton Valley Trend reserves, Cotton Valley reserves increased by 99 Bcfe resulting in an all-in finding and development cost for the Cotton Valley Trend of $2.19 per Mcfe.

Record levels of production also increased revenues to record levels with revenues growing by approximately 67% to just over $116 million for the year and approximately $30 million for the fourth quarter of 2006. Our operating and net income numbers were both negatively impacted for the quarter and the full year by a year-end reserve impairment of approximately $25 million and a significant charge to exploratory drilling of approximately $8 million related to a deep exploratory well in the Bayou Bouillon field in South Louisiana.

Of the impairment charge of approximately $25 million approximately two-thirds were related to properties in the South Louisiana area. Adjusting for these extraordinary items operating income amounts would have been positive for both the fourth quarter and full year.

To complete the strategic shift we started in 2003 and to allow us to focus 100% of our effort and our capital on the Cotton Valley Trend we previously announced our plans and an agreement to sell substantially all of our assets in South Louisiana for approximately $100 million with an effective date of July 1, 2006. We have granted the buyer additional time to complete their due diligence and we currently expect to close the transaction prior to the end of this month with our current estimates of net proceeds to the Company after adjustments for revenue and costs since July 1, 2006 to be approximately $80 million.


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Mar. 13. 2007 / 11:00AM, GDP — Q4 2006 Goodrich Petroleum Earnings Conference Call

In addition to the transaction in South Louisiana in an effort to enhance our financial flexibility, in December 2006 we issued $175 million of convertible notes which are noncallable until December 2011. They carry a 3.25% annual coupon and are convertible after the five-year period into our common stock at approximately $66 per common share. Proceeds from these transactions coupled with anticipated cash flow from operations and our existing senior credit facility provide us with the financial flexibility to execute our strategy and plans for 2007.

While we continue with a very active vertical drilling plan in the Cotton Valley Trend with nine rigs currently drilling vertical wells, we have also initiated a plan to test the economics and viability of horizontally drilling in the Cotton Valley. In October of last year we spud the J.K. Williams #1-H well which was designed to drill a horizontal lateral in the lower Cotton Valley sand section for a lateral distance of approximately 3000 feet. We subsequently drilled the well to total depth with a lateral displacement of approximately 2600 feet and successfully fracture stimulated four of six planned stages or 66.7% of the lateral using the Packers Plus Open-Hole design.

After flow back of the frac fluids production reached 3.3 million cubic feet of gas a day. Subsequent to the initial production rate the well’s performance has declined in the first couple of weeks and averaged approximately 1 million a day for the first 30 days of production. The well has now been on line for approximately 60 days and production has been relatively flat since that time and we are currently producing approximately 1 million cubic feet of gas per day. While water production from the well has continued to trend downward, current water production is approximately 500 barrels of water per day or four to five times a typical vertical Cotton Valley well in this area.

Our second horizontal test, the A. Jones #1-H, is located several miles south of the J.K. Williams in Panola and Russ counties, has been drilled to total depth with a lateral displacement of approximately 2650 feet and appears to have stayed completely within the target sand for the entire lateral. We will be experimenting with some different completion techniques and procedures in an effort to both reduce cost and improve results and we would be happy to discuss those with you during the Q&A. Completion operations on the A. Jones #1 will begin this week.

Our third horizontal well in the Cotton Valley sand is located east of the Carthage field in Caddo and DeSoto Parishes of the Bethany-Longstreet field. Our C. Graham #3-H well is currently drilling horizontally with excellent shows in the lateral section and we expect to reach TD on that well in approximately 10 days.

As we move forward in 2007 we will stay committed to our strategy of building value through the aggressive development of our assets by drilling approximately 95 planned vertical wells in the Cotton Valley Trend; continue to test the viability of the horizontal drilling in the Cotton Valley; participate in our initial horizontal well in the James Lime formation in Nacogdoches County on our cotton prospect; and we will test several 20-acre spaced wells on a vertical basis in the Cotton Valley Trend to test the economics and viability of further down spacing which if successful could add significant unproven reserve potential and value to our existing acreage position.

With that I’d like to turn it over to Rob Turnham for a more detailed review of our operating results.

Rob Turnham — Goodrich Petroleum — President, COO

Thanks, Gil. We continue the active development of our Cotton Valley Trend acreage with 19 new Cotton Valley wells added to production during the quarter with an average 8.4 gross or 5.3 net wells added that produced for the entire quarter. We actually added less average wells in the quarter due to the fact that we only had a little over six rigs — to be precise 6.4 rigs running in the Cotton Valley Trend for the entire quarter or four net rigs when applying our working interest in the wells being drilled due to releasing rigs in the third quarter and waiting on the new build rigs that have slowly come into our inventory. And by the way, two of those rigs came in late January and the third one in February and we’re currently running nine rigs.


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Mar. 13. 2007 / 11:00AM, GDP — Q4 2006 Goodrich Petroleum Earnings Conference Call

Another reason we added fewer wells during the quarter and therefore we didn’t the production growth we were hoping for was that our working interest and net revenue interest on the wells we added were lower than in the past due to our increased activity at Bethany-Longstreet where we own a 70% working interest and 49% net revenue interest as well as Angelina River where we own an average 50% working interest, 38.5% net revenue interest.

Our average working interest on the wells added during the quarter was 63% and the average net revenue interest on wells added during the quarter was 47%, which is down a good bit over our historical averages. For example, in the fourth quarter we averaged 98% working interest and 66% net revenue interest in the quarters prior to the fourth quarter.

When blending in the results we’ve now drilled 133 gross wells, 103 net wells producing for the quarter ending December 31, and our average blended working interest is now 86% in those wells with an average net revenue interest of 63%. We had 144 wells producing as we exited the quarter and since the end of the quarter we’ve added an additional 14 producing wells bringing the total wells producing to 158 with nine waiting on completion. That brings our total to 167 wells drilled with a 99.5% success rate in the trend. I believe, as Gill mentioned, we drilled one well in Harrison County, Texas as a stepout to our core Cotton Valley acreage that was a completion failure and noneconomic.

Net production volumes in the quarter were essentially flat to the third quarter at approximately 4.3 Bcf equivalent or 46.6 million cubic feet equivalent per day, primarily again due to adding fewer net wells in the Cotton Valley during the quarter as was just explained. Our commodity mix was 83.5% natural gas, 16.5% oil with 76% of the volumes coming from the Cotton Valley Trend.

Gross Cotton Valley production volumes of 54.5 million cubic feet equivalent per day came from an average 133 wells producing for the quarter or a little over 400 Mcfe per day per well. When applying our net to that, our net Cotton Valley sales volumes were 33.1 million cubic feet equivalent per day which came from an average 103 net wells or approximately 320 Mcfe per day per well net to the Company.

Moving on to capital expenditures, our capital expenditures for 2006 totaled $269 million with $217 million spent on Cotton Valley drilling and acquisition; $17 million being spent on leasehold acquisition and facility work; $31 million on non Cotton Valley activities primarily being south Louisiana; and $4 million on miscellaneous items. We drilled 105 wells with a 98% success rate companywide and, as Gil stated, we had a Cotton Valley drilling and acquisition finding and development cost of $2.18 approximately.

We have budgeted $275 million of capital expenditures in ‘07 with $245 million of that allocated towards drilling and completion costs in the Cotton Valley Trend; $30 million on leasehold acquisition, low pressure gathering system, facility work and other miscellaneous items.

Again, readdressing a couple of issues on reserve revisions, of the 30 Bcfe of revisions due to performance, approximately 17 Bcfe occurred in the Cotton Valley Trend primarily in the Southwest portion of our North Minden acreage where a tight curb analysis had been performed on the year-end ‘05 reserves and other outlying areas.

One additional point on reserves — as you may have been in Gil’s quote in the press release, if you apply year-end reserves at current prices including all revisions we would have had about 262 Bcfe of proved reserves which certainly is in the area that we were expecting to achieve when we began the program in early 2006. And with that I’d like to turn it over to David Looney who will walk you through the financials.


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Mar. 13. 2007 / 11:00AM, GDP — Q4 2006 Goodrich Petroleum Earnings Conference Call

David Looney — Goodrich Petroleum — EVP, CFO

Thank you, Rob. In the interest of time I’m going to walk you through changes in the various line items for the fourth quarter only, but will be happy to address any full-year questions you might have during the Q&A portion of the call. Reported revenues for the fourth quarter of $30.8 million were based on average prices of $6.54 per Mcf and $57.42 per barrel received.

In the quarter our remaining oil hedges were deemed ineffective due to lack of appropriate correlation to the NYMEX contract, thus for the first time our oil revenues did not include the impact of settled hedges; that amount is now included in the gain or loss on derivatives not qualifying for hedge accounting elsewhere on our income statement which is the same place our gas hedges have shown up since late 2004.

On oil our average price represented a basis of $2.74 off of the NYMEX average daily price of $60.16 during the calendar quarter. As to gas, our differential was approximately $0.09 below the average Henry Hub price for the quarter of $6.63 which is primarily a function of the high BTU content of most of our gas. While much of our gas has an approximate $0.50 basis versus Henry Hub, the BTU content brings the price more in line with that index.

As mentioned before, beginning in the fourth quarter all of our commodity derivatives, both gas and oil, are required to be accounted for using mark to market accounting; thus we’re required to show the effect of our natural gas hedging, both realized and unrealized, in a separate line item as well as now including our oil hedges in that same line item. For the quarter we reported a net gain on derivatives not qualifying for hedge accounting of $3.5 million which includes an unrealized gain on the mark to market of future contracts of $3.8 million and a realized loss of approximately $300,000 on our settled hedge contracts during the quarter.

Looking at cash flow, our EBITDAX for the fourth quarter was approximately $18 million or $0.72 per basic share. Discretionary cash flow, defined as net cash from operations before changes in working capital, was $14.2 million for the quarter or $0.59 per share.

During the quarter we had several onetime non-cash charges that merit discussion. Number one, as Gil mentioned, we took a $7.9 million dry hole charge for the Bayou Bouillon well which was decisioned during December. We also took a $24.8 million charge for the impairment of certain properties as follows — the St. Gabriel field in South Louisiana was $13 million.

Many of you will recall that this was the Gueymard well in the St. Gabriel field which we drilled in the first quarter of 2006 where this well was originally thought to be a good well with very meaningful preliminary reserves. However, as the year progressed we had numerous completion issues with the well and we ultimately determined that the reserves accessible from our existing well bore were insufficient to support the costs that we had on the books for the field in total which was approximately $13 million.

The Plumb Bob field in South Louisiana also experienced a $1.9 million impairment charge. And as Gil mentioned, two fields in East Texas, the Gilmer and Blocker fields accounted for $8.4 million in impairment expense. These are two outlying yields located in different counties from our Beckville, Minden and Angelina River Cotton Valley Trend acreage. And in these two fields we drilled several marginally successful wells that were unable to carry the full drilling and completion cost associated with the fields.

And in other various fields we incurred impairment expense of approximately $1.5 million. As a result we reported a net loss for the quarter of $22.4 million or a $23.9 million loss applicable to common stock after preferred dividends.

Focusing on the expense side of the income statement, our lease operating expense in the quarter was approximately $7.5 million of which approximately $1.3 million, or roughly $0.32 per Mcfe, related to the filing charges. Number one, during the quarter we recognized an incremental $766,000 to fully account for our presumably final insurance claim related to Hurricane Katrina. Unfortunately our final agreement with underwriters resulted in a larger loss than we had previously estimated.


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Mar. 13. 2007 / 11:00AM, GDP — Q4 2006 Goodrich Petroleum Earnings Conference Call

Number two, we also incurred approximately $590,000 in workover expenses during the quarter, mostly associated with the installation of gas lift equipment and replacement tubing in certain of our Cotton Valley Trend wells. Had it not been for these two items, our LOE per Mcfe would have been approximately $1.44, roughly comparable to the rate achieved in the third quarter. As it stands our LOE per Mcfe for the quarter was actually $1.76 with our south Louisiana properties accounting for almost 50% of the total LOE expenses in the quarter which resulted in an LOE per Mcfe for those South Louisiana properties of approximately $2.94 per Mcfe for the quarter.

Obviously the pending sale of the most of our South Louisiana assets will help us keep this expense item lower in the future. Additionally, as we have discussed on previous calls, the upcoming activation of our new Low Pressure Gathering System servicing the North Minden and Beckville fields will be a big help in managing our LOE going forward. Of our current salt water disposal expenses, well over 50% are related to truck hauling charges alone. And once this system is fully functional, in the second quarter of this year, the amount of salt water we will actually be transporting via truck will be significantly reduced if not entirely eliminated in some areas.

Transportation expenses continued their slight decline from the third quarter coming in at $1.1 million versus $1.2 million in the third quarter. Moving forward we have significantly streamlined certain of our gathering and transportation arrangements in East Texas and we expect this expense to average in the $0.25 to $0.30 range over time.

DD&A totaled approximately $15.5 million for the quarter or $3.63 per Mcfe versus $3.30 in the third quarter. As we’ve stated before, this year’s DD&A rate, i.e. the 2006 rate, is a function of last year’s reserve report and the breakdown of production coming from our various fields. The new DD&A rate for 2007 will be based upon the independent engineering report we just recently received and has not yet been determined.

Our exploration expense totaled $9.9 million for the fourth quarter or $2.31 per Mcfe driven largely by the dry hole charge at Bayou Bouillon which we’ve already discussed. Of the remaining amount, amortization of our undeveloped leasehold costs, which we amortized over a three-year period, accounted for approximately $1.6 million. Our G&A expense was $5 million for the quarter or $1.15 per Mcfe versus $4.3 million or $1.00 per Mcfe in the third quarter of this year. Of the $5.0 million, $2.1 million, which is roughly $0.49 per Mcfe, was a non-cash expense related to stock based compensation.

As a rapid growth company with a high stock price volatility, the growth of this expense item is not expected. However, the Company is keenly focused on its overall G&A expenses as we move into 2007.

Looking at the balance sheet for a moment — as many of you know and as Gil referenced, we completed a major financing during the fourth quarter, our $175 million convertible notes offering. As we received the proceeds in the initial week of December we completely paid off our second lien term loan of $50 million and essentially paid off the bank revolver for a brief period of time. However, due to our normal funding requirements and the closing of a roughly $6 million acquisition around the same time, we ended the month and the year with $26.5 million outstanding on our bank revolver for a total year-end debt number of $201.5 million.

The bank borrowing base stood at $150 million at year-end leaving us with over $123.5 million in availability at that date. The borrowing base is set to be redetermined at the end of this month and, while the sale of our South Louisiana properties will clearly reduce the amount somewhat, we do expect the reserve gains which we booked during the second half of 2006 to make up a significant part of that difference.

We’ve entered into 2007 with a $275 million capital budget and between our expected cash flow from operations, proceeds from the South Louisiana asset sale, and availability under the bank revolver we expect to have ample funds available to support that program. And with that I’ll now turn it back to Gil for some closing comments.


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Mar. 13. 2007 / 11:00AM, GDP — Q4 2006 Goodrich Petroleum Earnings Conference Call

Gil Goodrich — Goodrich Petroleum — Vice Chairman, CEO

Thank you. I will conclude by saying that we are very aware that there is significant improvement yet to be made in our operations and operational performance and we are redoubling our efforts to further reduce costs incurred in the field, both in capital expenditures and lease operating expenses. And we will not be satisfied until these costs are recorded at materially lower amounts.

We do believe, however, and as a rapidly growing company with a recently acquired and very broad acreage position, it is incumbent upon us to continue to drill wells and test areas we will have to add production facilities and infrastructure if successful and therefore continue to experience relatively higher costs than if we were to only drill wells in the mature areas of our acreage.

In addition, we have acreage which will need to be tested in order to maintain the acreage and, while we will concentrate on infield drilling with the majority of our rigs under contract during 2007, we will continue our efforts to prove up additional reserves and thereby enhance the net asset value of the Company for the benefit of all of our shareholders.

We also clearly recognize that as a resource play company we are in a margin play and keeping costs as low as possible while maximizing our realized natural gas prices is critical to the success of our strategy and we will continue to actively hedge our natural gas position and work hard to reduce cost going forward. As such and in addition to the 2007 hedges, we recently added to our hedge position by layering in approximately 19 million MMbtu — 19,000 MMbtu or 19 million a day for calendar year 2008 at a net price to the Company of approximately $8.00 per Mcf. Which significantly locks in our rate of return and allows us to continue to execute our development strategy.

That concludes our prepared remarks and we’ll be happy to try to answer any questions that you may have. And I will now turn it back over to the operator.

QUESTIONS AND ANSWERS

Operator

(OPERATOR INSTRUCTIONS). Ellen Hannan, Bear Stearns.

Ellen Hannan — Bear Stearns — Analyst

David, a question for you — just a follow-up on the hedges, that was going to be my question, $19 million a day. Is that a collar or a swap?

David Looney — Goodrich Petroleum — EVP, CFO

The hedge that Gil referenced for 2008 is actually a physical contract, so you can think of it as a swap.

Ellen Hannan — Bear Stearns — Analyst

Okay. That’s for 2007 or 2008?

David Looney — Goodrich Petroleum — EVP, CFO

2008.


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Mar. 13. 2007 / 11:00AM, GDP — Q4 2006 Goodrich Petroleum Earnings Conference Call

Ellen Hannan — Bear Stearns — Analyst

Have you made any changes so far to your ‘07 hedging program?

David Looney — Goodrich Petroleum — EVP, CFO

The only thing we’ve done which will be referenced in the Q, is we did unwind our 400 barrel a day oil collar which had a floor of 60 and a ceiling of around 76 I believe, 76.50, and we will be booking a gain on that of slightly less than $1 million.

Ellen Hannan — Bear Stearns — Analyst

Okay, thanks. And operationally, Gil or Rob, my question is you’re going to spud your initial attempt in the James Lime, what’s your running room in that particular if that’s successful?

Gil Goodrich — Goodrich Petroleum — Vice Chairman, CEO

It’s very broad, Ellen. We’ve got about 48,000 acres associated with the Cotton prospect, there are number of James horizontal wells that were drilled probably 10 to 15 years ago, none of which appear to be fracture stimulated, so if successful we’ve got lots of room to run there.

Rob Turnham — Goodrich Petroleum — President, COO

And Ellen, this is Rob. I might add, as you know, in our updated presentation we do have a slide with a map that shows where those previously drilled James Lime wells were drilled on our acreage but not fracture stimulated.

Ellen Hannan — Bear Stearns — Analyst

Okay. Just one more for me. The 20 acres spacing, when do you expect to begin that program and how many wells do you think that that encompasses out of the 95 that you planned for this year?

Gil Goodrich — Goodrich Petroleum — Vice Chairman, CEO

Ellen, just like our horizontal wells, we view this as something that needs to be tested and to drill a handful of those wells to see what kind of variability and application we have. We do intend to start that initial 20 acre spaced well somewhere between 30 and 60 days from here. It all depends on when we get the administrative application approved by the railroad commission which oversees all of the regulatory items. We are offsetting a well in an area that we’ve had some very nice wells and we intend to try to monitor where the frac goes on the 20 acres spacing to determine if we have any communication or not.

What set this up, obviously there are a number of operators out there in East Texas doing it with — as well as Northeast Louisiana, with some good success who have claimed that they’ve not seen any communication. So we’re hopeful that that works. Obviously if it does work and you have no communication you would double the number of locations where it’s perspective with the same finding and development cost.

Ellen Hannan — Bear Stearns — Analyst

Great, that’s it for me. Thanks.


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Mar. 13. 2007 / 11:00AM, GDP — Q4 2006 Goodrich Petroleum Earnings Conference Call

Operator

Robert Lynd, Simmons & Co.

Robert Lynd — Simmons & Co. — Analyst

Good morning. Just wanted to talk a little more on the number of locations. Your press release mentioned that you have 1900 possible locations in inventory in the Cotton Valley Trend. By possible are you referring to the possible reserve category? Because your recent presentations said you had over 2300 risk locations there.

Rob Turnham — Goodrich Petroleum — President, COO

Robert, you’ve caught on exactly. As we discussed, we had some revisions and certainly underperformance of certain wells drilled in certain areas. And what we are doing is going to high grade our acreage and take some of the — a portion of our North Minden acreage as well as some of these outlying areas and basically say — at these current prices with current costs that those areas we’re not going to be drilling in and therefore we’re going to take it out of the inventory.

The 1900 locations, if you combine our proved and probable locations you certainly get in excess of the 1900 on a revised basis once we’ve high graded this acreage. We currently — and you’ll see on an updated presentation — we currently have 1621 gross probable possible well locations to go with our proved locations. Again, we have quite a bit of upside there if things work. We’ve only put in a portion of our Angelina River acreage. And again, as I said, we basically risked our North Minden acreage to take into effect current economics.

Robert Lynd — Simmons & Co. — Analyst

Thanks, that’s helpful. And if we could move to the horizontal well, your J.K. Williams well, it looks like the decline over the first month was a bit higher than I expected, something like 70%. Is this in line with your expectations, your model and is this something that we should in our type curve or [Taylor] sand horizontal, should we move that type of decline into our model?

Gil Goodrich — Goodrich Petroleum — Vice Chairman, CEO

Robert, this is Gil. Clearly the well has declined faster than what we had anticipated going in. We felt like that to move the needle we would need something materially in excess of 2 Bcf of gas. If we got to 2.5 to 3 Bcf, we felt like it would be a meaningful change and something that would warrant considerably more stepout and testing. Clearly at 1 million a day for the first 30 days, which is really commensurate with the average of our vertical wells, it has underperformed relative to its cost.

That being said, there is some reason to begin to conclude that this thing is a little bit flatter on its decline. As I said, we’re out about 60 days now and we’re still producing at or about at the average of the first 30 days which would be something materially better than a typical vertical well.

So I think the answer, at least internally, is we’re going to have to get on down the road here a little bit, not only with this well but the other two that we either have drilled or are drilling, to see how they perform, to see what the difference between the three wells is and, most importantly, to see how they perform over time. There are some wells out there — the C.W. Resources well west of us in Overton for example came online in April of ‘06 at about 1.6 million a day and it has essentially averaged 1.5 to 1.7 million a day for each of the months since then up and including December of ‘06.

So by having that additional lateral and therefore exposure to the reservoir, it is too early for us to conclude, but certainly reasonable that the decline profile will look different over time.


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Mar. 13. 2007 / 11:00AM, GDP — Q4 2006 Goodrich Petroleum Earnings Conference Call

Rob Turnham — Goodrich Petroleum — President, COO

And Robert, this is Rob. Just to elaborate on that, what’s suppressing the gas is the water. And certainly we have higher water volumes than we anticipated. If the water continues to fall we would hope that that may create some flatness in the curve.

Robert Lynd — Simmons & Co. — Analyst

Got you, that’s helpful. Gil, you limited to this in your prepared remarks, but can you kind of talk about what you’re going to do differently with the stimulation of the second horizontal well you’re drilling?

Gil Goodrich — Goodrich Petroleum — Vice Chairman, CEO

Sure. I guess two things. One, from a cost standpoint, Robert. As I have said before, we did some things that would be more in the research and development category on the first well. We pumped a high viscosity cross-linked gel with a very high dollar resin coated profit and a very high pump rate. And we frankly are scratching our heads as to where all the water is coming room. All of the vertical wells around us don’t produce anything like this amount of water and we have essentially fraced into the same section as all those vertical wells. So it’s still a bit of a puzzle and a mystery to us.

But we think perhaps that we have created a little bit of excess high growth with that higher viscosity fluid. So one of the things that we’re doing which is also going to save us a considerable amount of money, probably in the order of $700,000 to $1 million of completion cost, is go with a lower viscosity, what we call the 500 series gel, and we will pump that at slower rates and use a typical low dollar sand profit in there. And we think that the combination of those two things should help us control the frac growth a little bit more effectively.

Whether or not that makes a material or a meaningful difference in terms of the performance we’ll just have to wait and see. It certainly will in terms of the cost.

Robert Lynd — Simmons & Co. — Analyst

Okay, thank you. That’s all I had, gentlemen.

Operator

Richard Moorman, Capital One Southcoast.

Richard Moorman — Capital One Southcoast — Analyst

I just wanted to cover off — I think guidance going forward would be a little helpful on the operating side. Just trying to understand, once the new facility infrastructure is in place — you know, right now it sounds like South Louisiana has been the largest driver for the cost and obviously rising water. Do you have a feel for what you would guide cotton Valley after the assets are out of the mix from South Louisiana?

David Looney — Goodrich Petroleum — EVP, CFO

Yes, Richard, this is David. As we look at it we certainly have some goals that we’d like to achieve there I think. Frankly it’s not going to happen overnight, but we expect that when we get some of these things in place like the Low Pressure Gathering System, etc., I think on our forecast we’d certainly like to see something south of $1.00 on an Mcfe basis for LOE.


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FINAL TRANSCRIPT

Mar. 13. 2007 / 11:00AM, GDP — Q4 2006 Goodrich Petroleum Earnings Conference Call

Richard Moorman — Capital One Southcoast — Analyst

And you think that could happen as early as the third quarter then once the facilities are in?

David Looney — Goodrich Petroleum — EVP, CFO

That’s probably not a bad target.

Richard Moorman — Capital One Southcoast — Analyst

Okay, super. And I guess on the capital side, I know you’ve got your budget out there and obviously this is a constantly moving target with service costs, but you’ve now had the new wells or the new rigs on for a little while, do you have a feel for what your average well cost is going to be going forward?

Gil Goodrich — Goodrich Petroleum — Vice Chairman, CEO

Richard, this is Gil. Good morning. I’ll try to answer that. I would say that like others that we have seen reporting recently, we are seeing kind of 10 to 15% decreases in rig rates. Without mentioning the contractor’s name, we do have a contract in front of us today; it would be 1000 horsepower rig working in East Texas at about 17.5 a day with considerably more advantageous clauses into that contract than would be typical. That’s a material movement. That rig probably in 2006 would have averaged about 22.5 a day.

So while we’re coming up upon a number of redeterminations and we expect to be getting better rates on those, until we actually get there and put those rigs to work it’s a little difficult for us to say. On the fracing and pressure pumping charges, we signed a one-year contract, which has been our practice, with Schlumberger. They give us 28 dedicated frac days per month which is critical to us executing our strategy.

Those costs — we locked in — our ‘06 contract was locked in in December of ‘05; we probably benefited quite a bit during the course of ‘06 as prices were going up because we had a fixed contract. It came back down and we were effectively able to replace that contract with an ‘07 contract at roughly the same rate as the ‘06 contract. So I don’t expect to see any material change there.

All of that being said, we still think we’ll be at about 2.2 to $2.3 million on average per Cotton Valley Trend well. And hopefully if we can over time convert more and more of the fleet to something on the order of 17 or 17.5 a day we may be able to drive that down into the low $2 million range.

Richard Moorman — Capital One Southcoast — Analyst

Super. And in the DD&A side, I know — reluctant to maybe give anything too firm here, but I do want to — maybe if you can walk through the sale implication here. It sounds like if all goes well the first quarter will still reflect South Louisiana as an operating asset and I presume the DD&A rate would still be effective, then I’m wondering maybe, David, after first quarter what happens here to the treatment and, first of all, have I got first quarter correct?

David Looney — Goodrich Petroleum — EVP, CFO

Yes, Richard. A couple of things as I referenced, the DD&A rate that was used in 2007 is going to be driven by the reserve report which we just received. And the way that works obviously is we have to go in, look at the reserves that are attributed on a proved


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Mar. 13. 2007 / 11:00AM, GDP — Q4 2006 Goodrich Petroleum Earnings Conference Call

developed basis only, the reserves that are attributed to each field and what costs we have assigned to those specific fields and that’s how you determine the rates to be used for the units of production method.

As Gil referenced, we do have South Louisiana properties that will essentially stay under our management, if you will, until later this month. So effectively that’s going to essentially be on our watch, if you will, for most of the first quarter. Going forward from that what you will see will be a DD&A rate that’s going to be driven exclusively by the costs and the reserves that we have attributed to the Cotton Valley properties.

As we discussed in here, in this conference call, obviously the reserves that we are able to book on an SEC basis using those SEC prices are obviously lower than what we would otherwise hope. So we just don’t know at this point where the DD&A rate is going to break out. There are a number of companies who go the way of doing a midyear reserve report for example and using that to reset your DD&A rate at midyear.

And we may very well be in a position given where we are size wise and our experience in this particular trends that we’d feel confident in doing that and that’s something that we’re going to be looking at over the next several weeks as to whether or not we do that. If we do that then that would obviously, again, have implications and potentially change the rate from midyear going forward.

Richard Moorman — Capital One Southcoast — Analyst

Okay, that’s fair. Thank you. And I guess in terms of drilling activity — conceptually you have a large number of I’d say third party interest in your wells this year, or a larger percentage I guess than last year. Is it fair to think about that the same each quarter or can you see right now like happened maybe in the fourth where you’ll be preferentially drilling lower interest wells in any given quarter?

Rob Turnham — Goodrich Petroleum — President, COO

Richard, this is Rob. Due to favorable results primarily, both at Bethany-Longstreet and Angelina River where our results have been very good of late, we’ve dedicated two rigs to each of those areas and Bethany-Longstreet has a 70% working interest and we have a blended 50% working interest at Angelina River. Although we have earned 100% of about 2100 acres by virtue of our partner — our joint venture partner going non consent on it.

We are going to keep those two rigs running full time. There’s a chance we’ll have a third rig running in both of those areas. So yes, we will be basically splitting those rigs up in areas that have less than 100% working interest. But we feel like with the nine rigs running by virtue of what you’ve seen in guidance on the first quarter of this year versus fourth quarter of last year, the nine rigs make a big difference.

What happened to us in the fourth quarter was that combination of basically six rigs running and the majority of that being in Bethany-Longstreet and Angelina River. So we feel like with the added rigs and the results we’re seeing at those two fields that you’re going to see production volume growth and I think the first quarter will kind of give you a good example of that.

Richard Moorman — Capital One Southcoast — Analyst

Super. And then my last question around that, the sequential growth you seem to be on track for in the first quarter you mentioned in the press release perhaps 15% in the Cotton Valley. Do you think that’s a reasonable number going forward here, 15% a quarter?


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FINAL TRANSCRIPT

Mar. 13. 2007 / 11:00AM, GDP — Q4 2006 Goodrich Petroleum Earnings Conference Call

Gil Goodrich — Goodrich Petroleum — Vice Chairman, CEO

Richard, this is Gil. We’re taking things a quarter at a time here. If we can continue to execute our strategy we certainly expect to see very robust growth. As Rob mentioned, going from six rigs to nine is certainly a meaningful change. We feel really good about where we are in the first; whether or not we’re going to be in double-digit territory for the second quarter, it’s really too early for us to tell. But we certainly expect and are forecasting we’ll be up meaningfully second over first.

Richard Moorman — Capital One Southcoast — Analyst

Okay. And then just — why don’t I follow that through, then last thought really. So you’ve got more rigs going in by January and so I’m hoping that’s going to be more rates — a higher rate in the second quarter. Also your facility work underway, when do you think that will have a potential boost to your production rates?

Gil Goodrich — Goodrich Petroleum — Vice Chairman, CEO

The facility work?

Richard Moorman — Capital One Southcoast — Analyst

Yes, the piping that you’re doing in terms of —

Gil Goodrich — Goodrich Petroleum — Vice Chairman, CEO

Low Pressure Gathering System?

Richard Moorman — Capital One Southcoast — Analyst

Right on.

Gil Goodrich — Goodrich Petroleum — Vice Chairman, CEO

We believe that we will see some improvement from all of the wells that will be serviced by that system, Richard. I think we would probably caution you that our internal projection is more of a flattening than an absolute increase in volumes and we would expect that to be kind of phased in during the course of the second quarter. We’re not expecting to see any big material onetime jump, but over the course of the second quarter we think that we will see a better floor underneath our existing base of production in that area.

Richard Moorman — Capital One Southcoast — Analyst

That sounds good. Anything to reduce those declines has got to be a good thing. Thanks for all the help, guys, and good luck in the second quarter.

Operator

Ron Mills, Johnson Rice.


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Mar. 13. 2007 / 11:00AM, GDP — Q4 2006 Goodrich Petroleum Earnings Conference Call

Ron Mills — Johnson Rice — Analyst

Good morning, guys. Rob, can you just add a little more information on this year’s drilling of in-fill drilling relative to — I’m assuming more — it’s going to be more PUD related drilling than 2006. Can you just give an idea, of the 95 wells how many will be directed towards PUDs versus reserve adds?

Gil Goodrich — Goodrich Petroleum — Vice Chairman, CEO

Ron, this is Gil. A comment I wanted to make earlier and probably this is a good time to make it, is one of the things that has come out of us now having drilled a little over 160 wells is that while there is a lot of similarity from Cotton Valley well to Cotton Valley well they’re not all exactly equal. And the 160 wells has led us into high-grade areas where we’ve seen the better results and low-grade those where we’ve seen lower results.

Neither the impairment nor any of the change in the inventory chart means that we are giving up on acreage at this point in time. We simply are saying that based on what we’ve seen thus far in those areas and under the current commodity prices, particularly the mid $5.00 range at year-end and the current cost structure, those are going to be lower priority areas for us. So the 160 plus wells is allowing us to really start focus and concentrate in more in-field development work and get away from the necessity where we’ve been in the past of needing to drill wells to form units and convert acreage from non held by production status into held by production status.

So we are looking at something on the order of two-thirds of our drilling activity this year would be more in-field in nature and in and around areas in which we’ve seen our best results. That still is a very broad area, it covers probably two-thirds or more of the entire 40,000 acres of Minden and all of the Beckville area. It also includes our block at Bethany-Longstreet as well as the Cotton South Angelina trend area.

So kind of a long winded answer to your question. Yes, we do plan to drill some PUDs this year. My guess is that’s probably going to be on the order of 20 to 25% of the total, 25 I think would be on the high-end. But it also depends on how events unfold and evolve over time and where our opportunity mix is at any given point in time. And our drilling schedule is something that we look at at least weekly around here and we’re moving things according to where we’re seeing our best results.

Ron Mills — Johnson Rice — Analyst

Okay. And in terms of the reserves that you reported, can you add any color? I know — I think last year you had said that your average booking per location was roughly a Bcf per well. Where did the numbers come out this year? Understanding of course that it varies across different portions of the field, but as you look at the place statistically was there any change in Netherland, Sewell’s average well recovery estimate?

Rob Turnham — Goodrich Petroleum — President, COO

Ron, this is Rob. No, we’re averaging just a hair under a Bcf off of this year-end reserve report and of course that varies from area to area. I think the number is 975 million cubic feet or thereabouts. So even though they certainly were conservative with us and we were fighting price issues we still came in at about where we were. Many of our areas are in excess of a Bcf, but the blend came out to be approximately 1 Bcf.

Ron Mills — Johnson Rice — Analyst

Okay. And I missed the number — I can’t remember who asked, but what you now think your average well costs out in the Cotton Valley?


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FINAL TRANSCRIPT

Mar. 13. 2007 / 11:00AM, GDP — Q4 2006 Goodrich Petroleum Earnings Conference Call

Rob Turnham — Goodrich Petroleum — President, COO

That’s going to depend on Angelina River versus core acreage. The last AFE that we prepared for an Angelina River well was about $3.1 million versus what we had been spending certainly was north of $3.3 million. And we have two rigs running in that area and our interest is varied. But as Gil suggested on our core Cotton Valley acreage, we’re certainly helpful of being in the $2.2 million range.

It depends on as we layer these rigs in at the lower rates that certainly will help. And we’re also focusing on drill time and certainly in some areas, whether we — for example, at Angelina River — whether we continue to go as deep as we have on certain wells. But those are our goals. We need to bake in these new service costs and hopefully we’ll achieve those.

Gil Goodrich — Goodrich Petroleum — Vice Chairman, CEO

And I might just add one thing. As to the $3.1 million AFE in the Angelina River, Netherland, Sewell was at a little over 1.3 Bcf average EUR for those wells. So that gives you a comparison of the cost versus the difference in the EURs down there.

Ron Mills — Johnson Rice — Analyst

Okay. And in terms of the horizontal cost, I know you’re doing a lot of let’s call it R&D on your initial handful of horizontal wells. But is the expectation still that those wells will cost roughly $5 million?

Rob Turnham — Goodrich Petroleum — President, COO

Yes, we think, Ron, that they’ll average out to be about $5 million. Again, we’ve drilled three of them, that’s in the range the AFE. The first one we did, as I said, put some incremental R&D cost on there. But about 5 is still a good number.

Ron Mills — Johnson Rice — Analyst

Okay. And the hope is still that you end up with kind of 3 Bcf plus per well?

Gil Goodrich — Goodrich Petroleum — Vice Chairman, CEO

Well, we would love to end up with 3 Bcf plus. What we’ve said is if we’re averaging about a 1 Bcf with a vertical well and it’s costing us 2.2 to $2.3 million, then anything over about 2.3 Bcf, 2.25 or 2.3 Bcf becomes a net positive for us. So if we can start seeing meaningful numbers that we feel comfortable with that would be in the 2.5 to 3 range, that would be meaningful change for us and you’d see us moving forward with more horizontals.

Rob Turnham — Goodrich Petroleum — President, COO

And Ron, the same holds true for 20 acre spacing. We just need to get a handful of both horizontal and 20 acre spaced wells to determine what’s the best economic way of draining the most acreage from our acreage — draining the most gas from our acreage.

Ron Mills — Johnson Rice — Analyst

Okay. And where are you planning on focusing your initial 20 acre activity?


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Mar. 13. 2007 / 11:00AM, GDP — Q4 2006 Goodrich Petroleum Earnings Conference Call

Rob Turnham — Goodrich Petroleum — President, COO

There’s a well over on our eastern portion of our North Minden acreage. It’s in an area that we’ve had nice vertical wells. We know exactly what the geology should look like and it’s a 20-acre offset to one of our good wells in that area. So if that works and we don’t see communication it clearly will work on other wells that maybe don’t have the same estimated ultimate recoverable reserve.

Ron Mills — Johnson Rice — Analyst

And then what are the regulatory steps involved with the 20-acre activity? I know (multiple speakers)

Rob Turnham — Goodrich Petroleum — President, COO

Any time you down space you basically file an application and notify the offset operators. In this case it should just be an administrative issue in that we’re not asking for less distance off of a common lease line. We’re basically asking for less distance between well bores — and Gil may want to elaborate a little bit on that.

Gil Goodrich — Goodrich Petroleum — Vice Chairman, CEO

As to the first area that we’re going into, Ron, we are the offset operator in that we surround acreage. So it really is more of an administrative function of getting it passed. In other words, we need no outside approvals other than just the state.

Ron Mills — Johnson Rice — Analyst

Okay.

Gil Goodrich — Goodrich Petroleum — Vice Chairman, CEO

(multiple speakers) operators, they’re going to approve that anyway. It’s just if they don’t have drainage on their acreage then it’s more acceptable to approve it, even if you have to solicit their interest.

Rob Turnham — Goodrich Petroleum — President, COO

And I might just add that this is really a research and development project in that we’ve only drilled a couple of wells even on 40 acres across our entire block. Most of our wells that we’ve drilled thus far, the 160 plus, have been very widely spaced, many of them miles or a mile or miles apart. So this is not — we’re not going to 20 (indiscernible) necessity to say we’re going to start drilling on 20s. We need to, we’re just trying to determine that economic viability and what it might mean to the future impact and therefore value of our acreage.

Ron Mills — Johnson Rice — Analyst

Okay. One last thing on that then in terms of that you’re not needing to hold leases really. And with the 20 acres obviously —where do you stand in terms of lease expirations? Are you facing any significant expirations this year or next?


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Mar. 13. 2007 / 11:00AM, GDP — Q4 2006 Goodrich Petroleum Earnings Conference Call

Gil Goodrich — Goodrich Petroleum — Vice Chairman, CEO

No, we really aren’t, which is not to say that we don’t have any little places where we might need to renew some leases. But basically, Ron, our entire or essentially all of our Minden block has now been converted to held by production status. I believe all of our Beckville block has been converted to held by production status. Our Bethany-Longstreet block, which is about 22,000 acres, is one large farm-out whereby if we drill one well every 120 days we maintain that. That entire block is being held by production from some very shallow low-volume gas wells. So we’ve got really no issues there at all.

At Cotton South we are continuing with an active program and doing everything we can to step out and prove that area and convert that into held by production status. And as Rob said earlier, we plan to have two to three rigs down there. So we should achieve that goal during calendar year 2007. We have taken on a couple of new areas, one of which we announced a few months ago which is Alabama Bend which has some time requirements on it. We’re going to drill our first well there in the second quarter and if successful then we would need to move forward with I believe it’s one well every 90 days over there to maintain that entire block.

We also have just recently entered into an agreement which expands our Angelina River acreage by a good bit, acreage primarily just east of our Cotton South block and that also will have I think about a 90-day continuous drilling obligation on it. So with having two to three rigs down there we see no problem with that. And again, over in Alabama Bend which is in Bienville Parish kind of east of the Elm Grove field, if we’re successful there we will have to give some real thought to how we dedicate a rig or rigs to developing it up.

Rob Turnham — Goodrich Petroleum — President, COO

And Ron, let me add one more thing. I hate to keep jumping in on top of what Gil is saying, but what we also know is that Alabama Bend, what he’s talking about there, we have nothing in our drilling inventory allocated to that. So with or without success that certainly won’t affect our inventory. And the same holds true at Cotton where we have our James Lime. There’s no value given to either the Travis Peak or the James Lime or the Deep Bossier well which is currently there attempting a completion on. So plenty of areas where we do have some minimal exposure on acreage, we have no inventory — any drilling inventory in there or inventory charge.

Ron Mills — Johnson Rice — Analyst

All right. Thank you, guys.

Operator

Brian Kuzma, JPMorgan.

Brian Kuzma — JPMorgan — Analyst

Good morning. I’ll make this quick. What was your pretax PV10 number at year-end?

David Looney — Goodrich Petroleum — EVP, CFO

The pretax PV10 number, Brian, we hadn’t released yet. Obviously we’ll be filing the K within a matter of days. And as we sit here I don’t have that number in front of me, to be honest with you.


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Mar. 13. 2007 / 11:00AM, GDP — Q4 2006 Goodrich Petroleum Earnings Conference Call

Brian Kuzma — JPMorgan — Analyst

Okay. And then, we were kind of talking about it earlier, but what do you expect the net revenue interest to be going forward in 2007?

Rob Turnham — Goodrich Petroleum — President, COO

That’s a good question. I think I said our blended average I believe was 60 something percent, 63% through December 31. That’s probably a reasonable estimate at this point in time. Again, the driving force is how many 40 or 50% wells we drill at Angelina River versus 100% wells there. So I would use that in that that’s kind of an average blended interest. And again, that would go with an 86% average working interest.

Brian Kuzma — JPMorgan — Analyst

Okay. And then finally, when we’re thinking about Cotton Valley wells in let’s say the North Minden area, and we’re expecting an average recovery of 0.8 or 0.9 Bs, what’s the distribution look like around that in terms of variability? Like how many of the wells will be less than half a B?

Gil Goodrich — Goodrich Petroleum — Vice Chairman, CEO

This is Gil. We have a few wells in particularly the kind of southwest portion of the block that would be less than a half a Bcf. Maybe one that’s in the 300 million range — I can’t remember exactly. Some of which were kind of early stage fraced. We don’t know how much that may have impacted those wells. That being said, we do clearly have an area in there where for whatever reasons our results have not been as good and have been somewhat less than half a Bcf.

We’ve also seen other areas obviously which have been materially greater than a Bcf and that’s helped drive that average. We have attempted in the presentation that’s going up on the website today to adjust and account for that to kind of cordon off those areas that we say under current or certainly year-end prices and current costs, those areas will take a back burner to us. It’s not that we’re giving up on them, but take a back burner to some of the other areas.

Brian Kuzma — JPMorgan — Analyst

So should we be expecting the average recovery to go up then as you cut back on these?

Gil Goodrich — Goodrich Petroleum — Vice Chairman, CEO

Well, we certainly hope so. Absolutely. We’re focused every single day on where can we maximize production and maximize reserve additions. And so we’re hoping that the more information — the more wells we drill the more information we have, the more information we have the better site selections we can make and that the wells that we’ll be drilling in ‘07 on average will have better EURs than the wells we’ve drilled heretofore.

Rob Turnham — Goodrich Petroleum — President, COO

And Brian, in that inventory chart however you’ll see that what we used — first of all we cut back a number of locations at Minden for that very reason that Gil just described, the southwestern portion at current prices is not something we want to do. But we still use the average net reserve per location off of the year-end reserve report to factor that into the number of locations on the inventory chart to come up with that probable and possible reserve exposure. So yes, we’re hopeful to increase that by drilling in these areas, but we still use the averages when we determine the 2P and 3P reserves.


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Mar. 13. 2007 / 11:00AM, GDP — Q4 2006 Goodrich Petroleum Earnings Conference Call

Brian Kuzma — JPMorgan — Analyst

Thanks, guys. That’s it for me.

Operator

Steve Burnham, Pritchard Capital Partners.

Steve Burnham — Pritchard Capital Partners — Analyst

I have two quick unrelated questions. Do you have a pro forma Cotton Valley only proved reserves for year-end? And also, your cash position at the end of the year? Thanks.

Rob Turnham — Goodrich Petroleum — President, COO

Yes, Steve. This is Rob. The pro forma year-end Cotton Valley reserves based on the non SEC case — the case that we talked about it being at 262 Bcfe is 227 Bcfe relative to Cotton Valley only and that’s spread out. I do not have the SEC proved reserves — it is 84% of the total, that’s a good point. 84% of the 206 Bcfe would be the SEC Cotton Valley reserves. But we would argue that certainly at current prices, if you’re looking at our drilling inventory certainly the proved reserves, the 227 would be more applicable. And what was your second question?

Steve Burnham — Pritchard Capital Partners — Analyst

Balance sheet cash at the end of the year?

David Looney — Goodrich Petroleum — EVP, CFO

Steve, this is David Looney. We had about $6 million of cash on the balance sheet and, as I mentioned, our debt was $201.5 million.

Steve Burnham — Pritchard Capital Partners — Analyst

And you have the preferred stock, the series B right — and there is no serious A any more?

David Looney — Goodrich Petroleum — EVP, CFO

That’s right. Series A was paid off, $112.5 million of series B.

Steve Burnham — Pritchard Capital Partners — Analyst

Thank you.

Operator

Nic Van Broekhoven, Foyer.


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Mar. 13. 2007 / 11:00AM, GDP — Q4 2006 Goodrich Petroleum Earnings Conference Call

Nic Van Broekhoven — Foyer — Analyst

Just one question. Do you have 2P and 3P numbers?

Rob Turnham — Goodrich Petroleum — President, COO

Yes, and you’ll see that on this inventory chart which will be on our page 19. When you add in the proved reserves of 227 you come up with about 1.2 trillion cubic feet of total proved probable and possible reserve exposure once we risked that Minden acreage. That’s broken out 944 Bcfe of probable — risked probable and possible reserve exposure to go with the 227 Bcfe of proved.

Nic Van Broekhoven — Foyer — Analyst

Okay.

Gil Goodrich — Goodrich Petroleum — Vice Chairman, CEO

This is Gil. I just might add that all of the 2P and 3P numbers are internal estimates. We do try to mirror off of the reserve engineering report, but those are not outside engineered numbers, those are internal estimates.

Nic Van Broekhoven — Foyer — Analyst

Okay. And then do you expect any of the insiders to be back in the market now that the price has come back to about the levels where you guys were buying last year? Now that the stock price has come back down to the level that you were buying around last year, do you expect any more insiders to be increasing their stake?

Gil Goodrich — Goodrich Petroleum — Vice Chairman, CEO

That’s a wonderful hypothetical question, so I can only answer that by saying we’ll see what the market does and where it goes (multiple speakers).

Nic Van Broekhoven — Foyer — Analyst

That’s $30 though?

Gil Goodrich — Goodrich Petroleum — Vice Chairman, CEO

It’s still a hypothetical question. I mean every insider makes their investment decisions based on where they are at any moment in time. So I would not be surprised if we see a two handle that there isn’t some more insider buying. As I tried to say, we are committed to this strategy, we believe in it, we certainly recognize that it’s not a $5.00 gas play at current cost in the field.

If it goes to a $5.00 gas play costs are going to have to drop significantly. But at $8.00, which we’ve just layered in for 2008, it’s a pretty attractive play and we and the other insiders are committed to that strategy. We believe very much in it and if for some reason the market doesn’t believe that I thank you very may well see insiders in the market picking up shares.


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FINAL TRANSCRIPT

Mar. 13. 2007 / 11:00AM, GDP — Q4 2006 Goodrich Petroleum Earnings Conference Call

Nic Van Broekhoven — Foyer — Analyst

Thank you.

Operator

Ladies and gentlemen, this now concludes the Q&A session. I’d like to turn it back over to Mr. Gil Goodrich for closing remarks. Please proceed.

Gil Goodrich — Goodrich Petroleum — Vice Chairman, CEO

Well, just a final comment obviously. There are a lot of things in the quarter and in the full year that we did not like. We’re very aware of those things; we’re moving forward to address them. But the core Cotton Valley is continuing to work for us so we’re continuing with our strategy of hedging, working to reduce costs and we’re confident that we sit here a year from now production volumes will be materially higher and reserves will have grown at a pretty attractive pace. So we thank you for your participation and look forward to our first-quarter call with you in a few months. Thank you.

Operator

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

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