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Executives

Walter G. Gil Goodrich - Vice Chairman and Chief Executive Officer

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

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

Analysts

Joseph Magner - Tristone Capital Inc.

Richard Tullis - Capital One Southcoast, Inc.

Ronald Mills - Johnson Rice & Company

Ellen Hannan - Weeden & Company

Goodrich Petroleum Corp. (GDP) Q1 2009 Earnings Call May 7, 2009 10:00 AM ET

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.

Walter G. Gil Goodrich

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 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 (ph), at 713-780-9494. She will be more than happy to fax or email you a copy.

As is our practice we would like to remind every one 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 and net production volumes, which grew by 7.5% sequentially over the fourth quarter of last year to approximately 76 million cubic feet of natural gas 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 Hayneville Shale's horizontal wells.

In 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 past 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 $70 million CapEx reduction for 2009 and a revised full year budget of $230 million.

With continued 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 expenses for the first quarter were approximately $87 million.

As we'll be reducing both our operated and non-operated rig count under the revised CapEx budget full year 2009's 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've 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 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 of 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 lead 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 drip which closed yesterday at $6.15 per MMbtu. As well taking note of the steep decline in natural gas directed rig count, which has fallen from it's October 2008 peak of 1,620 active rigs to last week's Smith Bidd's 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 steep 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 act towards beginning to build a 2010 hedge position at the appropriate time.

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 in our way towards 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 depth to 15.

In addition, we are currently drilling three Haynesville horizontals and expect to start 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 had 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 will turn the call over to Rob Turnham.

Robert C. Turnham, Jr.

Thanks, Gil. We conducted drilling operations on 24 wells in the quarter of which 12 were horizontal Haynesville Shale wells with 18 wells added to production.

Of the 18 wells added to production only two were horizontal Haynesville Shale wells. The 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 the 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 spread to sales is taken a little bit longer than originally planned with the current estimate of 75 to 90 days depending on availability of pipelines and infrastructure.

We expect the full cycle spread to sales trying to drop as we ultimately conduct horizontal drilling operations. And so our takeaway capabilities for the Haynesville at Bethany, Longstreet and Longwood Chesapeake markets are gas for a fee and return on gas is sold with theirs under existing transportation agreements, and we have no midstream infrastructure expenses.

In East Texas we haven't placed the infrastructure needed to handle our initial Haynesville production from the Beckville and Minden fields with any additional increase in capacity, they pay for install by third party midstream company.

On acreage costs in the play when applying the proceeds from our Chesapeake transaction they have a $2,500 per acre credit which leaves on the most part are completed well costs only when calculating, applying a development costs 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 and Longstreet, the Caddo and DeSoto Parishes, Louisiana where we are 50% areas for 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 in Northern Caddo Parish, we participated for 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 one mile north of our Percy Sharp 7H-1 which had an eight stage frac that tested at 5.1 billion cubic feet per day. We've completed a third well in the field to Bohnert 28H-1 and awaiting our pipeline connection which we estimate to be hooked up within 30 days.

We're encouraged by the improved results from the Sharp 1H-1, although we did not currently had plans to spud any additional wells in the field in the second half of 2009. A meaningful acquisition that Gil mentioned earlier, in the Haynesville, we executed two separate agreements to form in approximately 3,400 net acres in Northwest Louisiana.

The acreage acquired is located in two separate areas of Caddo and DeSoto Parishes, the portion of the acreage located within the Bethany - Longstreet field in Northern DeSoto Parish, and the remainder is located in the Greenwood, Waskom field at Central Caddo Parish.

The Greenwood, Waskom field for your information, 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 perspective, based on offset activities. In fact, the portion of the block sits between our Holland and Graham wells at Bethany-Longstreet which tested 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 by 5% to 66,500 net acres which is exclusive of our Angelina River trend acreage.

In East Texas, the Beckville and Minden we had hoped and expected to have results in the Lutheran Church 5H-1, but a bit delay due to coil tubing problems. We expect to have the coil tubing removed and resume fracing 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. William 7H well and expect to release production results on the well within the next two weeks. We've completed our KF Carter A2-B2 well and Cotton Valley Taylor Sand horizontal well in which we have 100% interest at 4 million cubic feet per day.

We are currently drilling two additional Haynesville Shale horizontal wells in the field to Taylor Sealey 3H in the Bread 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 vertical (ph) 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 now turn it over to David Looney, to walk you through the financials.

David R. Looney

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 realize that wider base has been 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 would 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, if none of our derivatives are designated as hedges for accounting purposes.

Thus, all of our hedging gains realized and unrealized, or 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 and 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.

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 a $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 be unwind if the capital expenditure accrual we've 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 to 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 31st.

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 salt water 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 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 are falling 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, it's well within our expected range of 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 provisions, approve developed reserves, resulting from the lower prices used in the year-end 2008 reserve report compared to those used in the mid-year 2008 reserve report.

Based on our calculations, these provisions 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 '09 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 of our mid-year 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 at 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.

Primary reason for the higher absolute dollar expense amount was due to the company's approximately 28% head count 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 occurred 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 intension 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 will see adjustments to our current period and prior period debt levels, equity accounts, deferred taxes and interest expense. Essentially the new principal requires us to calculate interest on the adjusted balance of these convertible notes at a much higher rate of the coupon, 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 principal. 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 will be happy to answer 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 Robert 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 31st 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 to $15 million in cash and short-term investments and nothing drawn on our bank facility. 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 am sure you have no doubt saw we closed on a 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.

Walter G. Gil Goodrich

Thank you, David. While we are moderating our pace of development with the announced reduction of 2009 capital expenditures to ensure we preserve ample liquidity as we go we into 2010 we are also prepared to resume a more aggressive development plan at that 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 seven additional Haynesville Shale horizontal wells already completed and just beginning flow back or soon to be completed we're anticipating another quarter of solid sequential growth and meaningful Haynesville Shale reserve growth during 2009.

That concludes our prepared remarks. And I will now turn it back over to the operator for questions.

Question-and-Answer Session

Operator

(Operator Instructions). Your first question comes from the line of Ronny Iceman (ph). Please proceed.

Unidentified Analyst

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

Robert Turnham, Jr.

Yeah, Ronny this is Rob, and we've seen 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.

Current AFE estimate is about $7 million depends on the number of stage fracs. Obviously, we're currently are 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.

Unidentified 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, Jr.

Well, the first obvious reason is that they had 12 successful frac stages before prior to completion on the Percy Sharp well we only had 80 that were pumped to completion. Other than that there was a little bit more fluid cost in the Exco well than our wells there on the Percy Sharp. But other than I think it's just execution with that frac and getting all 12 stages off.

Unidentified Analyst

Thank you, guys.

Operator

Your next question comes from the line of Kistler Chow (ph). Please proceed.

Unidentified Analyst

Good morning.

Robert Turnham, Jr.

Good morning.

Unidentified Analyst

Going back to the Exco- Sharp well just a second ago, does that changed your view I guess of the overall Longwood field area?

Walter Goodrich

Well, hi, good morning, Kistler, it's Gil. It certainly is encouraging and positive I would say 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 kind of tend to think that length is more in the completion and the things that Rob mentioned.

So yes, in bottom-line we're certainly much more encouraged about the area than we were, we would not written off by any means before. This gives us some added access to get backup there, although as Rob mentioned in his prepared remarks we don't have any additional wells planned there this year. But hopefully sometime in '10 we'll get backup there and grow some additional wells.

Unidentified Analyst

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

David Looney

Yeah, Kistler it's David. I mean 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 Haynesville production.

The salt water disposal obviously we've had a number of ongoing programs which have at various points in time brought down the salt water disposal costs in those particular fields. I think we 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, Jr.

And Kistler, this is Rob. I might add on the Haynesville. None of us know for sure but we are modeling, certainly loss of $0.10 amount. And we get 6.5 Bcf tight curve well for the LOE on these Haynesville wells, it all depends on volumes and then what we do know is that we have less salt water disposal and no initial compression needs. And, so it just start baking in, two-thirds of our CapEx budget being spend on those wells, and they are coming in at a much reduced LOE, we would expect that number to continue to fall unless we get more critical mass of Haynesville wells.

Unidentified Analyst

Okay. Thank you.

Operator

Your next question comes from the line of Joe Magner. Please proceed.

Joseph Magner - Tristone Capital Inc.

Good morning. I just wanted to walk us through some of the details of the $70 million CapEx reduction. I think at various point of time you've talked about fewer different portions of that out, just curious what was actually taken out?

Robert Turnham, Jr.

Well, this is Rob. I will take a shot at that, Gil may more apply then. We pulled one rig out of the Chesapeake joint venture, we had been running three, pulled one out in the second half of this year. They were fine we were 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 expiration issues there.

And, therefore a lot of time to drill wells there. On the operating side, as we said, we're going to reduce down to two operating rigs. We really have no additional Travis Peak, vertical James Line 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.

But 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 has 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 did work our way back from baking the strip prices for our unhedged volumes, trying to determine at what CapEx level we will insure that we get into 2010 with some cash and nothing from our revolver, and then cut accordingly and have the luxury of doing that just with our staggered rig contracts.

Joseph Magner - Tristone Capital Inc.

And then there was an acreage acquisition where in that budget, is that sill in there for now? Or have you pealed some of that back from your plant?

Robert Turnham, Jr.

We still have a plus number in there. When you look at our revised inventory chart it will have still has 31 million of leasehold and other expenses that other will include various cost across miscellaneous projects, as well as infrastructure and as well as leasehold.

So the lease hold acquisition numbers much lower than that, probably 12 to $15 million. And then as just the rest is kind of a plug number to cover any unforeseen cost, overruns or infrastructure expenses.

Joseph Magner - Tristone Capital Inc.

Okay. Thanks a lot. And then, I think you guys have been talking about the impact of cutting CapEx back to around 250 or still expecting sort of 25% growth year-over-year growth forecast, the pullback to 15 to 20 is that can we assume that -- that is the impact of some of the delayed completions and some other timing issues, and some of the wells turned on line?

Walter Goodrich

Yes. Joe, this is Gil. It is couple of things. One is, we have said, we're knocking 70 million out, so gets exactly to $230 number. So from the 250 number you gave with 25, I think we're probably in the same ballpark there.

And yes it's delaying some completions kind of staggered as we go through the year and preserving some capital, so we've got the flexibility of having those wells down encased and ready to be completed, at such point in times as we see market conditions improve.

So likely as we currently said, that means 2010 I think it turnaround before then, it could be a little earlier than that. And I would just add one another thing that Rob didn't mention is, that we are also in an agreement with our partners EnCana and St. Mary down in Angelina River, also agreed to kind of shutdown operations there till the first quarter. So, no additional, vertical order James Line wells horizontally planted to be drilled down there.

Joseph Magner - Tristone Capital Inc.

All right, thanks for that. And can you just pass all the magnitude of the impact on the reserve provisions on Q1 and whether, or I guess if the bulk of it was in positive if there was any impact to the PDP?

Walter Goodrich

Yes. As to DD&A was all on the develop side, because we're successful efforts, so you can only use develops reserves, and it's really just the difference between pricing for the most part or the majority of the difference is pricing from mid-year reserve to year-end reserve. And as David said, I believe that is about 70% of the impact that we saw came come from the price provisions, order provisions between those two reserve reports.

And then back on your previous question, just to clarify, I think you said 15 to 20% growth, we are expecting 15 to 25% growth with the revised budgets. If you took the midpoint of both of those numbers, now 20% would be based on 230 million versus 25% at 250, and that that seems about right to us.

Joseph Magner - Tristone Capital Inc.

Okay. Thanks for that clarification.

Walter Goodrich

Thanks.

Joseph Magner - Tristone Capital Inc.

And then just, two other wells that you had in your presentation in the Caddo Pine, Allen area there are a couple of wells that were either drilling or waiting on completion. Can you provide any update on those?

Walter Goodrich

Yes. Joe, it's Gil. We do have two additional wells which are down out there, that would be our whole 5H and our near well in conjunction with Matador Resources. We do had plans to begin completing those wells, we likely are going to do that at a stage, as I think first one is likely going to be start completion later this month and we'll just kind of take up stages and flow back a little bit and see how it looks and make some determination what we do there.

Joseph Magner - Tristone Capital Inc.

Okay. Thank you.

Walter Goodrich

Thanks, Joe.

Operator

Your next question comes from the line of Richard Tullis. Please proceed.

Richard Tullis - Capital One Southcoast, Inc.

Just to verify on the latest well costs for the Haynesville the 7 million, double at the ten stage completion that you're referring?

Walter Goodrich

That's right, Rich.

Richard Tullis - Capital One Southcoast, Inc.

Okay. And then that twelve stage day and perhaps another 250,000 or so?

Walter Goodrich

With our latest bid, has really dropped dramatically to about $1.1 million as to the stimulation portion of the completion. So on a ten stage frac so that would be 110,000 per stage just for the stimulation, certainly need to add more. It's probably 250 to 300,000.

Richard Tullis - Capital One Southcoast, Inc.

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 upper cut.

Walter Goodrich

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 kind of in that $0.10 range. Actually if you do the math, it's good than less than 10% in Nirwana (ph) I think Petrohawk and others will confirm that's their modeling, also. But as you add compression and that's 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 reigning pressures as to when that compression kicks in, but that's when you would start to see the increase in LOEs. Is when you have to layer in compression cost.

Richard Tullis - Capital One Southcoast, Inc.

Okay.

Walter Goodrich

It's really almost like a fixed LOE that goes up once the compressors are added.

Richard Tullis - Capital One Southcoast, Inc.

Okay, on the well cost. Do you think we're pretty much close to the minimum there or do you foresee another couple of hundred thousand that you could peak out it?

Walter Goodrich

Richard, this is Gil. Two things, one is just to make sure we're all on the same page the, fracing we are talking about in the course we gave in a raisin coated fracs. I think that's 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've really start 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 to 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 equation. So we think there is still room to go there, unless and until the market for gas kind of turns around.

Richard Tullis - Capital One Southcoast, Inc.

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

Walter Goodrich

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

Richard Tullis - Capital One Southcoast, Inc.

Okay. And then finally, not to get too detail. But how do you think you'll 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--?

Walter Goodrich

I think we'll just, we'll take one at a time and see how -- we have an obligation on both side of the equation. And when we feel like there is some material piece of information that's in our possession we typically put it down for total 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, Inc.

Very good. Thanks so much, appreciate it.

Operator

Your next question comes from the line of Ron Mills. Please proceed.

Ronald Mills - Johnson Rice & Company

Good morning. Just to follow-up on one of Richard's question, the Angelina River area Rob, can you breakdown that 42,000 acres between Surprise, Bethune, East Lake and the Cotton/Cotton South areas?

Robert Turnham, Jr.

Yeah. Let's start with Surprise, where we have the three wells that are penetrated that's all will come in that 2900 net acres for us.

If you look at the Cotton prospect which would be kind of Nacogdoches County along the River we'd probably would say 12,000 net acres there not only two but the gross is roughly 24,000 we had 40% of that roughly.

And then the remainder would be I guess Cotton South as probably another or I'd say it's a little bit less than that probably 10,000 acres. And then the remainder will be or what we call that there East Lake which is probably the closest acreage that we have, I've to get the exact number but that will be -- I would say somewhere in the kind of 12,000 net acres.

Ronald Mills - Johnson Rice & Company

Okay. And I think we had talked in the past so, you had also 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 in what that may lead to potential no shallower declines.

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 should have held up and how they are tracking relative to that 6.5 B type?

Robert Turnham, Jr.

Yeah. Still very early on the EURs and obviously it will depend on net analysis and then what we think. But as I kind of mentioned to others we did a ground we flowed back on a reduced choke size of 2464, it came at a 11.4 million a day is 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 high curve that we include in our presentation that would be a flatter initial decline than what we have projected.

The 2464 choke well at the Holland came at the higher rate, but following more similarly to that decline curve. At the end of the day your initial decline rate will be tight fit into the top curve that will ultimately kind of spit out what that EUR would be.

And so, we are still experimenting with choke sizes in the better areas no questions you can choke the wells back and help maintain your pressure drop and hopefully ultimately increase your EUR on the area that have less velocity and permeability.

We think you need to go ahead, open the choke up a bit to unlock the well. We are seeing a little bit flatter curves in those areas as are other companies. And just due to lack of profit permeability to be open choke appears to be more flexible there.

Operator

Your next question comes from the line of Ellen Hannan. Please proceed.

Ellen Hannan - Weeden & Company

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

Walter Goodrich

Good morning, Ellen, both good questions. Hopefully, we detailed this before but we'll happy to do it again.

We specifically build into our agreement with Chesapeake kind of the barriers with government on both the end. And that is we did not want to be, where we didn't have the ability to propose wells in the event they -- 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 to 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 kind of run over like a herd of cow with a 100 acre piece in 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 can not exceed $50 million gross for both parties. So we've 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 have half of that so $100 million. And so where we were in terms of reducing from three rigs to two rigs was really about mutual agreement between the two parties.

As to your second question, yes we've got, we have two rigs Ellen that will roll-off under normal contract terms in very end of July and then one August the 1st.

We have another one that runs until December. I think someone here might correct one of those rigs we run pretty close to the mid-summer termination, the other one we'll release a bit early and pay up 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 up fee probably in the neighborhood over $1 million or so.

Ellen Hannan - Weeden & Company

Okay.

Walter Goodrich

That's a substantial amount of CapEx from there on till the end of December.

Ellen Hannan - Weeden & Company

All right. Thanks for that reminder. Thanks.

Walter Goodrich

Thank you.

Operator

Your next question comes from the line of Ron Mills. Please proceed.

Ronald Mills - Johnson Rice & Company

Rob just a --

Walter Goodrich

Hi, Ron.

Ronald Mills - Johnson Rice & Company

Hey. Just in East Texas you guys had a number of recent wells over the course of the last month showing better results particularly in Southern Harrison Northwest, it's been in the 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 are completing your wells in Beckville and Minden in terms of number of stages and what your lateral length is?

Walter Goodrich

Yes. Ron it's Gil. Our -- we're as we said in the release we're currently slowing back our J.K. Williams well. It was -- I don't know the exact number, 4400, 4500 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 to roll back now.

Ronald Mills - Johnson Rice & Company

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

Walter Goodrich

Well, I think the main driver there is two folds, the length of laterals and I don't see that being will lead to Texas or Louisiana both cases getting out 44 - 4500 feet, make sense and you're seeing that. The next question is, how much do you break the each interval down to and we tip this time around 300 to 350 feet per stage. And others have experimented initially with bigger intervals, some may ultimately more go to smaller intervals and the idea of going to smaller intervals you get more frac intensity per stage.

Ronald Mills - Johnson Rice & Company

Okay. But in your initial wells, you planned on sticking with kind of that 3 to 350 feet that length?

Walter Goodrich

Yes. Now, that's our current thinking in plant.

Ronald Mills - Johnson Rice & Company

All right. Thank you very much.

Operator

Your last question comes from the line of Mike Salvia (ph). Please proceed.

Unidentified Analyst

Hi, guys. Sorry if I missed it, but did you say, where you are planning to run the two operated rigs in the second half of the year?

Robert Turnham, Jr.

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

Unidentified Analyst

Okay. And then on the J.K. Williams and the Lutheran Church. Can you show the cost side 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?

Robert Turnham, Jr.

Yeah, again it all depends on the number of stages, but as Gil just said, we get 13 stages on the J.K. Williams, so, obviously that cost is going little bit higher than what we have projected at 7 million on ten stage frac. So right now, if you want to just kind of be conservative, put couple of hundred thousands dollars per stage of frac and big rig time and other goods and services on top of that.

So that would get us, we have to do it on our cost and we're still flowing the well back, so 7.5, $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 fracing last stages then we'll get back to that $7 million range, but more than likely, if this 13 stage frac works and we are able to get 4,500 feet on each well and in some cases we may not be able to do that, just due to acreage or mechanical issues.

But at that level, obviously that yields higher number of stages and we're still little bit more than the 7 million.

Unidentified Analyst

Okay. And then, Gil, it sounds like you are happy to just watch others drill the Haynesville down there and no plans to, I think at one point you talked maybe drilling few horizontal Haynesville well, yourself down there, but has that kind of been mixed?

Walter Goodrich

No, we've never really talked about or at least plan for that. We initially set out the drill vertical wells and also ultimately the plan would be to go horizontal, but at this point in time we have so much on our play, and our CapEx budget is set and the play is early. We feel like and hear that the play is coming our away with the encouraging results for the J.K. William well and we're just going to take a kind of wait and see approach on that acreage, if it comes closer to as I don't know de-risk and at some point we'll test it.

Unidentified Analyst

That makes sense. Last one for me is, with your production goods now, any of that dependant on Hayneville production from East Texas?

Walter Goodrich

Yeah. Sure, I mean, still a big portion of our CapEx budgets is coming from East Texas. And except for the handful of wells we are taking talking about deferring into 2010, the rest of the volume growth is going to come from both East Taxes and our Chesapeake joint venture.

Unidentified Analyst

Thank you very much.

Walter Goodrich

Thanks Mike.

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.

Walter Goodrich

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.

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Source: Goodrich Petroleum Q1 2009 Earnings Call Transcript
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