Goodrich Petroleum Corporation Q4 2008 Earnings Call Transcript

Mar. 1.09 | About: Goodrich Petroleum (GDPM)

Goodrich Petroleum Corporation (GDP) Q4 2008 Earnings Call Transcript February 26, 2009 11:00 AM ET

Executives

Gil Goodrich – Vice Chairman and CEO

Rob Turnham – President and COO

David Looney – EVP and CFO

Analysts

Ellen Hannan – Weeden & Company

John Freeman – Raymond James

Subash Chandra – Jefferies & Company

Scott Wilmoth – Simmons & Co.

Kim Pacanovsky – Collins Stewart

David Heikkinen – Tudor Pickering & Co.

Joe Allman – JP Morgan

Leo Mariani – RBC Capital Markets

Ron Mills – Johnson Rice & Company

John Healy – Forest Investment Management

Joe Magner – Tristone Capital Inc.

Richard Tullis – Capital One Southcoast, Inc.

Operator

Good day, ladies and gentlemen, and welcome to the fourth quarter 2008 Goodrich Petroleum earnings conference call. My name is Josh and I will be your coordinator for today. (Operator instructions) I would now like to turn the presentation over to our host for today’s call Vice Chairman and Chief Executive Officer, Gil Goodrich, you may proceed sir.

Gil Goodrich

Thank you very much. Good morning everyone and welcome to our full year and fourth quarter 2008 earnings call. I’d like to begin this morning by introducing the Goodrich Management team members here with us beginning with Pat Malloy, our Chairman of the Board; Rob 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 issued an earnings release yesterday evening after the close. If you have not received a copy of that and you would like to, you can access one on our Web site at www.goodrichpetroleum.com or feel free to call my Personal Assistant, Becky DeLatin [ph], at 713-780-9494. She will be happy to fax or email you a copy.

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

These are certainly challenging times for all E&P companies but the actions taken, progress made and results achieved during 2008 have not only positioned us to weather the current economic storms but to continue to grow our company and create additional value for our shareholders in 2009. In 2008 and on a full-year basis, we achieved net production volume growth in excess of 50%, nearly doubled our oil and gas revenue, and achieved growth in proved reserves using a longer term price outlook of approximately $7.50 per Mcfe of approximately 30% over the prior year. Once again we delivered attractive growth reserve replacement ratios both prior to and after price related revisions.

During 2008, we achieved a number of critical objectives including significantly increasing the level of our drilling activity and the size and the scope of our capital program dramatically strengthened our balance sheet and expanded our net acreage position in Haynesville Shale play to approximately 63,000 net acres. Net production in the fourth quarter grew somewhat less than we had projected due to a number of circumstances which Rob will review with you in detail in a few minutes. However, the slide production mix was entirely related to the timing of new wells coming online during the quarter and our strategy, plans, and growth projections remain on track. Our liquidity remained strong with approximately $148 million in cash and short-term investments as of December 31, 2008. When combined with our anticipated cash flow, untapped senior revolver and strength of our balance sheet will continue to allow us an aggressive development program, and we are all in pace with our planned capital expenditures of $300 million.

We maintain an excellent 2009 hedge position with 16 million cubic feet of gas per day or approximately 22 Bcf hedged at a blended average fuel price of $8.61 per MMbtu, which represents approximately two thirds of our projected 2009 production. In addition, we have also hedged the basis differential on these 16 million cubic feet of gas per day locking in a basis differential between NYMEX pricing and our closest field benchmark NGPL TXOK pricing at approximately $0.47 per MMbtu which provides us protection against further basis expansion in East Texas.

Operationally, we continue to make excellent progress with our strategy. We have now announced results on our first two Haynesville horizontal wells and the Bethany Longstreet field of southern Caddo and northern DeSoto Parishes with initial potentials or IPs in excess of 10 million cubic feet of gas per day and we are equally pleased with the early initial mass performance of both of these wells. We have two additional wells in the Bethany Longstreet field which have reached total debt and are scheduled to be fraced and completed in March and three additional wells are currently being drilled. Our current plans call for three non-operated rigs to remain active drilling horizontal Haynesville shale wells in the field for the balance of this year with a total of 17 or approximately seven to eight net Bethany Longstreet Haynesville horizontal wells drilled this calendar year.

Moving further to the north in Caddo Parish, we have now drilled two non-operated wells in the Longwood field where we have tested the initial well our Percy Sharp 7H-1 and anticipate completing the second the Bohnert 28H-1 early next month. While it is early in the well’s production performance and the initial potential on this Sharp 7H-1 was less than we have seen in Bethany Longstreet, we are pleased and encouraged by the well’s early performance and based upon the well’s performance to date, we currently project the well’s estimated ultimate recovery or EUR will be at the low end of our previously estimated range of 4.5 to 8.5 Bcf per horizontal Haynesville well. This is just one data point, it does confirm our belief that there will be variability across the play and suggest that porosity and permeability are more significant drivers than thickness as the Sharp area has slightly lower porosity and perm yet approximately 283 to Shale thickness, and will likely perform differently over time versus higher perm and porosity areas.

Yet further to the north and Caddo Parish in the Caddo Pine Island area we have participated in three additional non-operated Haynesville horizontals. These wells are currently waiting on completion of the pipeline and two of the three wells are expected to be fraced and completed during the second quarter. However our initial well the Hall 9H-1 has been completed and thus far exhibited disappointing flow back performance with an initial potential of approximately 2.5 million cubic feet of gas per day. While it is still early in the well’s flow back it is worth noting that our Caddo Pine Island acreage represents approximately 2900 net acres or approximately 4.5% of our total 63,000 net acres perspective for the Haynesville Shale.

Moving west into East Texas, on our 100% on and approximately 39,000 acre block in the Minden and Beckville fields of Panola and Rusk counties we are currently drilling on our initial two operator Haynesville horizontal shale wells, the Lutheran Church 5H and the J.K. Williams 7H. After some initial drilling problems and delays in the shallow portion of the hole, the Lutheran Church 5H has now reached a kickoff length and had tightening [ph] set at 10,600 feet and the J.K. Williams 7H is drilling in the shallow vertical portion of the hole. Also in the Minden and Beckville area and during the second quarter of 2008 a direct offset operator successfully drilled and completed a Cotton Valley horizontal well in the Taylor sand series which is a different target and strategy from our two previous Cotton Valley sand horizontal attempts in the area. The offset well has performed extremely well over a nine-month period and we have recently completed our initial look alike Taylor sand horizontal well, the G.T. Waldrop 3H. Rob will give you more details in a moment but we are very pleased with the initial flow back performance and we expect the well will continue to improve as we recover a greater percentage of the induced frac water. Following on this success, we currently have five Cotton Valley Taylor sand horizontals planned in the Minden Beckville area in 2009.

Finally, in the Angelina River trend we closed on acquisition of a 50% operated interest in approximately 5000 acres in northern Nacogdoches County in September of last year and what we call our surprise prospect. In the fourth quarter, we drilled our four initial vertical wells strategically located across the prospect acreage and we are currently drilling our fifth. The primary objectives for the prospect are the James Lime, which we plan to test horizontally; the Travis Peak; and secondary objectives in the Cotton Valley, Bossier and Haynesville formations. After a brief delay in the fourth quarter getting the initial wells connected to the pipeline, each of the initial wells has been placed on production with positive results and we are now very well positioned to proceed with the drilling development on this prospect.

Further south in Angelina River, we have also had very good recent results in the Cotton South deals in the Angelina County with our two most recent James Lime horizontal wells which are performing exceptionally well. The proposing and successful drilling of these two wells has allowed us to further increase our net acreage position in the Cotton South deal for the James Lime formation and our development plans called for continued development of the James Lime in this area.

Now I would like to turn the call over to Rob Turnham.

Rob Turnham

Thanks, Gil. The fourth quarter was very much a transitional quarter from an operational standpoint. Drilling program continued at a reduced pace to previous quarters and our completions were down by almost 50% from the third quarter of 2008. In the fourth quarter, we drilled and cased 25 wells but only completed and put on line 12 wells down from the 18 to 22 we had expected and guided to on our third quarter earnings call down from 23 in the third quarter and 35 in the second quarter of 2008. The reduction in the number of wells completed in the quarter was primarily driven by a majority of our capital expenditures going to the Haynesville Shale where we have begun horizontal developments which is causing longer cycle times between wells, the drilling and discovery of a number of wells in our new areas that required additional pipeline capacity and infrastructure such as our four wells in our surprise prospect that Gil mentioned, and a slowdown in non-operated activities both from a drilling standpoint and timing of completions.

Our drilling operations in the Haynesville Shale trend accelerated significantly during the quarter with drilling operations conducted on 24 gross wells with 15 being vertical and 9 being horizontal. Of the 9 horizontals only one was producing at year end and had a reserve associated with it. We currently have five wells that have been drilled and are waiting on completion and six rigs running in the play with three at Bethany Longstreet, one at Longwood, and two in East Texas at our Beckville and Minden acreage. We expect to drill 40 gross, 24 net horizontal Haynesville wells in 2009. Because of the slowdown in completions, production grew by 2% sequentially for the quarter and 51% year over year. We expect 5% to 10% sequential growth in the first quarter and reaffirm our yearly guidance for 2009 of 30% to 40% growth. With two-thirds of our gas hedged at more than twice the current price, we expect to fund $300 million CapEx budget of cash flow and available cash leaving our bank revolver undrawn as we enter 2010.

Our reserves grew by 12% year over year using a non-escalated year end pricing of $5.71 per Mcf and $41 per barrel. We were 97% and natural gas and 38% developed. We had 63.4 Bcfe of revisions from the previous year with approximately 60 Bcfe or 94% due to price and 83% coming from our undeveloped reserves primarily driven by Cotton Valley of wells. When using a price stick of $7.50 per gas and $67.50 per oil, our reserves would have grown by 30% to $467 Bcfe. Less than 2% of our reserves at year end were associated with the Haynesville Shale, so it is really a look back at Cotton Valley development over 2008. Our reserve replacement ratio for the year was 285% when including revisions or 547% prior to revisions. Looking forward, 2009 will be a much different story with 67% of our capital allocated for Haynesville Shale which would yield significant reserve exposure.

Moving on and focusing on some of our core areas at Bethany Longstreet and Caddo and DeSoto parishes of Louisiana where we are 50% owners with Chesapeake and Plains, as Gil said our Graham 14H-1 was completed with an initial production rate of 11.4 million per day on a reduced choke size of 20/64 and has exhibited a very flat production profile over the first ten days averaging 11.2 million per day. The reduced choke size we feel has allowed for a slower pressure decline while projecting on a flatter curve which we believe prudent and could yield reserves in the higher end of our 4.5 Bcf to 8.5 Bcf range. The well has ten frac stages on 4600 foot lateral and Chesapeake brought the well in under the $8 million budget for the well. We have plans to complete two additional wells in March, the Branch 11H-1 and the ROTC 1H-1, both of which we have a 50% working interest. At Longwood in northern Caddo Parish, which is also part of the Chesapeake joint venture where we own a 50% working interest and 5400 net acres, we have completed our Percy Sharp 7H-1 with an initial production rate of 5.1 million per day on 22/64 inch choke and a 20-day average of 4.3 million per day.

As we said in our press release and as Gil stated earlier, our internal estimate of reserves for the well based on the initial flow back indicates a reserve at the low end of our 4.5 Bcf to 8.5 Bcf range. The well which was drilled in approximately 4600 foot lateral had 8 of the 12 planned frac stages pumped to completion. This is our layman development of Longwood but what we know is that the area is shallower than Bethany Longstreet, we are seeing lower pressures, lower porosity and more than likely lower permeability which may create an area similar to what other areas are reporting where the initial production rates may be lower, the decline curves flatter and will ultimately yield sufficient reserves and rates of return. In addition to the Sharp back on the wells, we anticipate fracing the Bohnert 28H-1 in March.

Moving even further north to Caddo Pine Island, certainly on the edge of the play where we are in 2900 net acres as Gil stated at our 63,000 acre block, we completed our whole 9H-1 at a disappointing rate at 2.6 million per day. We had 10 successful frac stages in the well. In consultation with our service providers, we will be modifying our completion plan on the two remaining wells that are waiting to be fraced in the field in an attempt to improve on the well reserves. Moving to East Texas and the Angelina River trend, we have announced four discoveries on our surprise prospect in northern Nacogdoches County where we own a 50% interest. We drilled our initial Haynesville Shale test in the field, the Tucker No. 1 which found 200 feet of Haynesville Shale thickness and tested at 600 Mcf per day. In addition to the Haynesville Shale, we are currently testing the Bossier Shale in the well with plans to co-mingle both the zones, both Haynesville Bossier and the Travis Peak at a later date. We have also completed our Hill No. 1 on the surprise prospect and the Bossier Sand at a rate of 9.4 million per day on a 16/64 choke with 7150 pounds of pressure. We fill the Hill well had a structural component and the Bossier may have additional development potential but will not have resource potential across our entire acreage block. Our third and fourth discoveries on our surprise prospect being our Grigsby No. 1 and Lilly No. 1 wells had initial production rates from the Travis Peak at 3 million and 2.9 million per day higher than our typical Travis Peak wells historically in the area. We are currently drilling our fifth well in our surprise prospect in Lewis No. 1 which we anticipate evaluating the Travis Peak, Bossier, James Lime, and Haynesville Shale.

On our Cotton South prospect in the Angelina River trend, we have completed another James Lime horizontal well, our Mims 1H-1, a well in which we own 100% interest. The Mims well like the Graham well at Bethany Longstreet flowed back on our reduced choke size with initial production rate of 7.5 million cubic feet per day and a 6-day average of 7 million per day which again exhibits a flatter decline profile than our other James Lime wells in the area. We have also completed two additional vertical wells in the quarter on our Cotton South prospect area where we have co-mingled the Travis Peak impeded zones and has seen very attractive average initial production rate of 5.1 million per day. With the discovery on our surprise prospect, our Haynesville Shale prospective acreage increased to 63,000 net acres.

Moving to our largest block relative to the Haynesville in East Texas which is our backbone Minden area and Panola and Rusk counties had a very meaningful announcement in our press release regarding our initial Cotton Valley Taylor sand horizontal well. We announced the completion of a Waldrop 3H-1 a 3350 foot lateral which we own a 100% working interest. We reported it at 4.8 million per day on a 48/64 inch choke with 23% of the frac duly recovered. As Gil said, we are very optimistic based on early flow back results that we have made a well similar to the well offsetting our acreage that has averaged 2.5 million per day over nine months which we internally estimate at 4.25 Bcf of reserve. The Taylor Sand is the primary driver of our Cotton Valley vertical wells of backbone Minden where we have over 41,000 net shallow acres as well as our South Henderson acreage we have an additional 10,000 net acres.

Current development plans for the Cotton Valley horizontal is drilling five wells in 2009. As to the Haynesville Shale on our backbone Minden acreage where we own 100% working interest and operate 39,000 net acres, we drilled seven vertical delineation wells and now drilling our first two horizontal wells. As Gil said, the Lutheran Church 5H-1 is currently drilling in the lateral section and is expected to be completed in late March early April and the J.K. Williams 7H-1 is drilling in the vertical section and is expecting to be completed in late April. The Lutheran Church 5H-1 experienced mechanical problems when drilling the vertical section at 6600 feet and had to re-drilled causing a delay n its completion.

I would now like to turn it over to David Looney to walk you through the financials.

David Looney

Thank you, Rob. Reported revenues for the fourth quarter of $44.1 million were based on average prices of $6.68 per Mcf for gas and $56.30 per barrel for oil. On gas, our average price is approximately $0.26 above the average Henry Hub price during the quarter, largely a function of the fixed price physical contracts we had totaling over $25 million a day on average where we received a price in excess of $8.25 per Mbtu for the quarter. On oil, we realized an average basis of $2.76 off of WTI Cushing prices during the quarter. Neither of these prices include the impact of $1.3 million in realized gains on our commodity hedge portfolio during the quarter as none of our derivatives were designated as hedges for accounting purposes. Thus just to reiterate, this realized gain of $1.3 million is not included in the revenue line nor is it included in operating income on our financial statement as presented under GAAP.

Looking at cash flow, our EBITDAX for the fourth quarter was approximately $27 million. Discretionary cash flow defined as net cash from operations before changes in working capital was $17.4 million for the quarter but was impacted in a negative way by approximately $4.7 million in tax adjustments that related primarily to the Chesapeake transaction which occurred in the third quarter. As a reminder, both EBITDAX and discretionary cash flow for the quarter and the full year have been adjusted to remove the impact of the $146 million gain resulting from that segment. Our full year 2008 EBITDAX was $146.7 million, a 96% increase over last year’s comparable number. Similarly discretionary cash flow for the current year was $113.8 million, a 67% increase over last year. Again I would note that our DCF for the full year 2008 was negatively impacted by approximately $15 million in current income taxes paid during the year again primarily as a result of the gain on the sale to Chesapeake.

Our fourth quarter capital expenditures which were actually paid for during the quarter totaled $86.6 million. So if you subtract this $86.6 million from the $17.4 million in fourth quarter discretionary cash flow and also factor in approximately $10 million of Federal and State income taxes that were paid during the quarter, you can then get from the $224 million of cash we had on the books at 9/30/08 to approximately $145 million in cash at year end. As there were several other small charges or changes impacting the number, we did end the year with $148 million in cash as Gil previously mentioned. On the expense side of the income statement, our lease operating expense or LOE in the quarter was approximately $9 million or $1.39 per Mcfe on a unit basis which is down approximately 7% from $1.50 per Mcfe in the fourth quarter of 2007. We expect LOE cost to continue to trend downward as we begin to recognize the full benefit of our salt water disposal projects as well as having a greater percentage of our production coming from that Haynesville Shale play which is expected to have lower salt water disposal and compression charges.

Production and other taxes for the quarter totaled $1.8 million or $0.28 per Mcfe of production versus $1.3 million or $0.32 per Mcfe for the prior year period. The per unit expense is lower due primarily to the ad valorem tax expense being spread over a larger production base. For the year, production and other taxes was $7.5 million with approximately 3.5% of revenues which is a reasonable number considering the severance tax credits we continue to receive on the vast majority of our Cotton Valley trend wells. Transportation expenses totaled $2.2 million in the fourth quarter or $0.33 per Mcfe versus $1.7 million or $0.37 per Mcfe in the fourth quarter of 2007. Transportation expense for the year at $0.37 per Mcfe is well within the expected range of $0.35 to $0.40 that we have seen in the last several years. D&A totaled approximately $26.6 million for the quarter or $4.11 per Mcfe versus $22.2 million or $4.77 per Mcfe in the fourth quarter of 2007. This decrease in the DD&A rate is largely a function of our improved efficiency in drilling and completing our traditional Cotton Valley trend wells as there was no impact on these numbers due to Haynesville Shale. Our fourth quarter DD&A rate was a function of the reserves based on our last completed independent reserve report during the year which is in this case was the mid year or June 2008 report. The recently received reserve report detailing our year end 2008 reserves will be used to calculate our DD&A rate for the first several quarters of 2009. At this point, although we have not completed our analysis, we do not expect a material change to our DD&A rate in the first and second quarters of the New Year. Again, given the newness of our Haynesville Shale program, it will not have any impact on our DD&A rate during the first half of this coming year.

Our exploration expense for the quarter totaled $2.6 million or $0.40 per Mcfe versus $1.5 million or $0.32 per Mcfe in the fourth quarter of 2007. The primary reason for the increase year over year was the $350,000 dry hole expense we took for deepening our well to an unproductive zone as well as an increase in our undeveloped lease hold amortization cost which is a non-cash expense from $1.5 million in fourth quarter of ’07 to $1.7 million in fourth quarter ’08. During the fourth quarter of ’08, we took an impairment charge of approximately $27.5 million most of which related to the company’s Brachfield property. Given current market conditions and less than expected result in that field, management made the determination that an impairment was warranted. By contrast we had an impairment charge of $7.4 million in the fourth quarter of 2007. Our G&A expense was $6.7 million for the fourth quarter or $1.03 per Mcfe versus $5 million or $1.08 per Mcfe in the fourth quarter of 2007. Of the $6.7 million roughly $1.5 million or 22% of the total was a non-cash expense related to stock-based compensation. The primary reason for the higher absolute dollar expense amount was due to the company’s increased headcount year over year. For the full year G&A per Mcfe was down approximately 24% on a per unit basis from $1.31 in 2007 to $1.00 in 2008.

Given the large gain on the Chesapeake transaction we booked in the third quarter of this year of approximately $146 million, our tax provision in the fourth quarter effectively suffered from the need to finalize or true up our annual tax provision. As a result, our fourth quarter tax provision of $4.4 million was much higher at a 69% effective rate than the typical 35% rate on a pre-tax income of $6.4 million. Additionally, due to the need to adjust our deferred taxes downward from the third quarter balance, we actually showed a reduction in deferred taxes of approximately $2.5 million in the quarter. When you combine these two items together, this negatively impacted our discretionary cash flow by a total of about $4.7 million in the quarter as we previously mentioned. Finally we reported net income of $1.2 million in the fourth quarter before deducting our preferred dividends. After deducting this $1.5 million amount, we had a net loss applicable to common stock of $318,000 for the quarter or $1.00 per share which compares to a net loss applicable to common stock for the fourth quarter of 2007 of $22.1 million.

Turning now to the balance sheet, needless to say we are extremely thankful to be positioned as we are in the current time. With approximately $148 million in cash in short-term investments on the balance sheet at year end and nothing outstanding on our bank revolver, we are in a stronger liquidity position that the company has ever been. As mentioned before, we expect this year’s cash flow and the cash balance at year end ’08 to be sufficient to fund virtually all of our capital expenditure needs this year. As such, although we expect to receive a new borrowing base from our bank group in the next several weeks, we do not foresee the need to borrow under this facility until much earlier in the year or early in 2010. Having said that as always, we will continue to explore for other possible sources of financing to best position the company to execute on our wealth of development opportunities in the future.

With that I will not turn it back to Gil for some closing comments.

Gil Goodrich

Thank you, David. Goodrich Petroleum is in the process of a very significant transition which will see us dramatically reduce the number of Cotton Valley vertical wells and increase the number of horizontal wells drilled in 2009 with particular emphasis on the Haynesville Shale play. To successfully complete this strategic transition will require us to efficiently execute our drilling plans and deliver excellent well and production performance as well as superior reserve group. Our individual wells results will vary and some areas will perform better than others. We are confident in our strategy and believe we can and will deliver top tier results in 2009.

That concludes our prepared remarks; I will turn it back to the operator now for Q&A.

Question-and-Answer Session

Operator

(Operator instructions) Our first question comes from the line of Ellen Hannan of Weeden & Co. Ellen, you may proceed.

Ellen Hannan – Weeden & Company

Thank you, good morning. A general outlook comment Rob, the last time we met you talked about trying to work with some of your service providers in terms of kind of sharing the wealth or adversely sharing the pain in terms of upping your re-contract in terms of new day rates, etc, can you kind of update us as to where you stand with that?

Rob Turnham

Sure Ellen. We have two rigs that we have entered into a color with that is tied to the NYMEX gas strip, we’ll mark to market the NYMEX strip at the end of each quarter and the rig rate will fluctuate with a floor and a ceiling and basically the floor is $16,000 a day plus top drive of $3000 a day, so we are looking at a kind of a minimum price there of $19,000 a day and that is for anything less than $7 gas price and these are large rigs by the way. They are the equivalent of 2000 horsepower rigs which we feel like will allow us to shake days off of our drill time. We are hopeful of saving the work from three to four days due to the added horsepower. We are also seeing as you know we bid out all of our goods and services. We do it on a calendar year basis and we didn’t look at it quarterly as well as semi-annually and we have just gone through that bid process and we are seeing 15% to 20% projected cost reductions across the board when you look at drilling and completion expenses. Some of that is fluid, you look at pipe prices, we clearly would expect additional pressure and relief on pipe prices, pressure pumping is under pressure, the profit is not, it is in high demand but we would hope to continue to see across the board some relief on prices.

Ellen Hannan – Weeden & Company

Thanks. Now, just one other question maybe now for Gil, in terms of your Cotton Valley Taylor sand well, could you put that in context of what you are looking more in terms of EURs and well costs and how that compares to what your thoughts are on the averages for the Haynesville Shale wells?

Gil Goodrich

Sure Ellen, good morning. You know, we would characterize it this way, probably not quite as robust and prolific as the top tier Haynesville shale wells but as Rob mentioned the offset well looks to us to be in the range of about 4.5 Bcf EUR and we think we will drill and complete these wells in the range of about $6.5 million or so. So, it is $7 and with our hedge position, we are certainly at work this year. So I am wondering about the current cost structure, we think we could generate kind of mid-20s rates of return on that which is not outstanding but certainly works pretty good for us and we will continue with that.

Ellen Hannan – Weeden & Company

Right, that’s it from me. Thank you.

Operator

Our next question comes from the line of John Freeman from Raymond James. John, you may proceed.

John Freeman – Raymond James

Good afternoon guys.

Gil Goodrich

Hi John.

John Freeman – Raymond James

I want to get a little bit more detail on exactly the differences you are seeing in Caddo Parish, just what would make for such a difference between the Holland well that you drilled in Caddo Parish on the Bethany Longstreet Field versus the last fields over in Longwood and Caddo Pine, just in terms of any specific differences on what you are seeing on the pressure porosities and things like that.

Gil Goodrich

Yes John, this is Gil, good morning. First of all, as Bethany Longstreet and Shale is located in a little deeper in the section and the Shale is roughly at about 11,700 feet and it has a bottom hole pressure in the neighborhood of about 12,000 pounds. Up at the Longwood area, it is about 10,600 feet in depth and the bottom hole pressure is likely to be around 10,000 or a little less. So we have just by natural gradient, a little bit less pressure up there because of the depth. I would say that probably the bigger driver at least in our mind is that the porosity reading is a digit or two better in the Bethany Longstreet area and by that I mean likely in the 10% to 15% range versus kind of 8% to 13% range up in Longwood. And so, as we look at the development and the porosities we are seeing, we have to believe that that is certainly a factor, I caution again this is one data point so we need to get some multiple wells drilled up there before we really can draw any firm conclusion. But that is our general feeling and belief. This time certainly we think has something to do with the driver mechanism. It does not as I said in my earlier remarks; we think everything to be big as we go in fact the Longwood is actually a little bit thicker than what we see in the Bethany area which is more like 200 feet versus Longwood being 280 feet of thickness.

John Freeman – Raymond James

That is very helpful, thanks. Looking, obviously you all have a very nice hedge position this year and I am really mainly more focused on the unhedged volumes and just kind of what the thought process is on when if gas prices stay at this level or possibly went lower at what price you would start to pull back and again I am not talking really about the Haynesville, more the Cotton Valley horizontal and James Lime, what price you would start to maybe want to pair back some of the production?

Gil Goodrich

I will tell you this John, we started to feel, as David said, very thankful of the position we found ourselves in with an untapped (inaudible) basis, sufficient cash on hand we can stay pretty aggressive, certainly, frankly much more aggressive than we would be if we didn’t have those things. And we were watching the 2010 strip quite closely, I think that is our real barometer with approximately two-thirds hedged, we feel good that even in the current outlook for 2009 we are likely to be in the 725 to 750 on a blended average pricing for this calendar year. If we get to the middle of this year and the economic conditions remain as they are today and the gas strip remains as it is, and most importantly if calls don’t come back much more dramatically than Rob alluded to, then we are going to be moving downward in the second half this year preparing ourselves for 2010 by slowing banks down and cutting CapEx but it is a little too early particularly given the transition that we are in moving to Haynesville to do that at this point in time.

John Freeman – Raymond James

Okay, last question I have and I will turn it over to somebody else, some competitors have had some pretty nice Cotton Valley Lime results near some of your East Texas acreage, any plans to test that?

Gil Goodrich

Yes, I might ask you to kind of be more specific about who and where so I can give you some better color on how it might relate to Goodrich.

John Freeman – Raymond James

Sure. I have seen results from XTO, specifically that has had some results near some of your Angelina River Trend acres, I have seen some other guys near North Minden and Beckville.

Gil Goodrich

It’s just the Cotton Valley Lime which to get everybody fully confused can also be called the Haynesville Lime not to be confused with the Haynesville Shale. We have not really seen anything in our immediate area in the Lime itself that has been what I would call stellar results. We have tested the Lime in a number of places primarily down to South Henderson, we have seen IP rates anywhere from 1% to a maximum of 3% but the Lime is very tight down there. Now if you go to south into Angelina River, Devon has been making some outstanding wells in what they call (inaudible) which is in very southwestern Shelby County. That is a structurally driven plan, I don’t think the porosities and the structure are playing a significant factor. So we think the potential for that John across our acreage down in Angelina River and we will be drilling some wells deep enough for testing but at this point I would characterize that as more prospective in nature rather than developable.

John Freeman – Raymond James

Great, thanks guys.

Gil Goodrich

Thank you, John.

Operator

Our next question comes from the line of Subash Chandra from Jefferies & Co. Subash, you may proceed.

Subash Chandra – Jefferies & Company

Yes, hi, good morning. Yesterday, I think it was yesterday, Petrohawk made some interesting comments on Haynesville that could be important, one is that structure does not really seem to mean anything and the second is that there might be indications from 3D seismic or AVO analysis which can high-grade where the Haynesville could be perspective, could you comment on those statements.

Rob Turnham

Yes, Subash, this is Rob. Clearly, we are actually about to participate with Chesapeake on a 3D shoot that will include our Bethany Longstreet acreage and we will have definitive knowledge of that over time but obviously there have been some very good drills drilled and completed off of existing structures. Certainly in the early wells now in growth you could say that maybe there were some structural component, right now stepped out and drilled wells off of this structure. So I think we would clearly agree with that. What we tried to get a handle on is not only porosity but permeability and TOC and thermal maturity, all of the various rock properties that would allow you to yield better results. What we also as Gil said earlier, I think what we are coming to the conclusion of is quality of rock versus thickness of rock that matters and some of the best wells had been in areas where you have 150 feet of thickness or potentially even less than that. So that’s what makes us optimistic in East Texas where vertical wells have had extremely high initial production rates relative to the other vertical wells and we know therefore that the quality of the rock is good there. So I think we are all figuring this out as we drill wells in different areas, we do as Gil said, expect variability. We think that the decline curves will be different in various areas and we will just over time figure out what is driving that.

Subash Chandra – Jefferies & Company

Okay and I guess that Chesapeake well was slightly below AFE, is there a range that you can provide on what you have seen on well cost being in the Haynesville so far?

Rob Turnham

For us we have cut wells along the line of anywhere from $7.5 million to $8.5 million so our target is $8 million and (inaudible) and at Chesapeake what we are learning from them is basically how to bring wells in on budget, on time and they have done a very good job with that. We had a misfortune in East Texas up shallow [ph] where we were drilling our initial horizontal Haynesville well mainly because we had a big bend in the well bore trying to maximize acreage and while in the directional portion of the well bore up shallow we basically stuck our pipe, had two options, one to either cut a window in the surface casing or skid the rig and move it over. So that is what we are seeing, we are seeing other operators with higher cost, we are also – our last in Bethany Longstreet was 10 stages and we have a 4600 foot hole so obviously 460 feet per stage which is spread out more than what you are seeing from some of the other operators we were talking about 15 stages, and based on the results from that ground well when you compare it to the Holland well which had 12 stages, we are even more optimistic that we are effectively fracing the zone at least in the better areas and might be able to drain it in 10 stages versus over fracing with 15.

Subash Chandra – Jefferies & Company

Got it, okay. This is probably the type of comment you did not want to make or intend to make but this porosity issue, is there a clue then that may be 8%, 10% is inadequate and maybe the cut off is 10 plus?

Rob Turnham

First of all, I would caution about porosity reading between logs, open hole logs and actual core samples, and what we received from the core data work we have done is you would normally see a couple of percentage less than the cores that you see on the logs and the porosity readings I gave you a few minutes ago were all based on (inaudible) that much data. There is no question in my mind that at some point you are going to have a diminishing return if porosity gets down too low that you are not going to be able to have the economic well. I would say from our perspective at least it is just too early to draw any firm conclusions to what that number is, but 8% to 10% very well – core reading very well may still be sufficient but permeability is also going to play a factor and that is much more difficult to get your arms around and then pressure also, if you have a lower porosity area but higher pressure you might be fine also.

Subash Chandra – Jefferies & Company

Understood, and one final one from me, as you bring in sort of Cotton Valley drilling to a hold here and what happens then in your reserved bookings going forward, I am making an assumption here that you have Cotton Valley PUDs more so than some of the other James Lime PUDs etc, etc, are we going to see some of those come off just because the budget won’t be towards those programs?

Rob Turnham

No, Subash, not necessarily. As we said, we have only got five horizontal Cotton Valley wells planned this year and with one we can knock down quite a few existing PUD reserves since those PUDs are all based on 40 acre spacing. So it maybe that an another part of the transition is we are moving away from vertical PUD development to horizontal PUD development, so that is still very much part of the plan.

Subash Chandra – Jefferies & Company

Understood, thanks for the clarification.

Rob Turnham

Thank you.

Operator

Our next question comes from the line of Scott Wilmoth from Simmons & Company. Scott, you may proceed.

Scott Wilmoth – Simmons & Co.

Hi guys, quick question, you guys mentioned mechanical issues at the Church well but do you have any of the same issues with the Williams 7H well?

Rob Turnham

No, we have not. So far so good Scott –

Scott Wilmoth – Simmons & Co.

Okay and then in the –

Rob Turnham – Re-drill of the Lutheran Church 5H is going very well and also we are already into the lateral. So it was an unusual circumstance up shallow probably caused by salt water issues, it had nothing to do with the Haynesville shift.

Scott Wilmoth – Simmons & Co.

Okay that is good. And then in Caddo Pine, obviously that was a matador operated well, was the completion method any different than the completions you guys have been doing with Chesapeake.

Rob Turnham

No, very similar.

Scott Wilmoth – Simmons & Co.

And then my last question, regarding 2010 hedging, you guys said you guys are watching the strip closely, what price and since you guys are settling hedges for 2010?

Gil Goodrich

Yes Scott, this is Gil, we obviously can’t give you a number, we have a hedging committee that meets regularly and discusses the strip regularly and that committee will make the decision. I would just say kind of generically that what is not available today I think would have some appeal to us would be something on the order of call it 7/9 on a collar, we will certainly view that very attractive currently for 2010 and we think and you guys have done a great job of fracing the gas related rig count, we are watching that very closely and we think that the bias is towards an improving 2010 strip because of the very steep decline in gas directed rigs. So we have the luxury of weighing a little bit, we don’t have to do anything today. We are watching it virtually every day and when time gets right you will see us and we would certainly not want to be going into 2010 totaling that in our hedges.

Scott Wilmoth – Simmons & Co.

Okay, thanks guys.

Operator

Our next question comes from the line of Kim Pacanovsky from Collins Stewart. Kim, you may proceed.

Kim Pacanovsky – Collins Stewart

Hi, thank you, good morning everyone. In the Taylor sand, did you include Taylor sand potential in your little chart in your presentation that includes your probable reserves?

Rob Turnham

No Kim, this is Rob, that is all based off of vertical reserves that we took the average reserve size at midyear times the number of locations. There is no horizontal implication in the inventory churn.

Kim Pacanovsky – Collins Stewart

Okay, that is great. And what kind of spacing would you anticipate there on your net 50,000 acres or so, do you think all of that is perspective?

Rob Turnham

Depends on the length of lateral but we are looking at 160 acre potential spacing, we would hope to drill these 3000 foot to 4000 foot laterals.

Kim Pacanovsky – Collins Stewart

Okay. So you might have lost some potential from Caddo Pine Island but it appears to me that you have added more potential reserves through this Taylor Well program.

Rob Turnham

It is a meaningful well, it does not have Haynesville in front of it so it does not get nearly the attention but the finding and development cost and rate of return look very good to us and we have an extreme amount running with 41,000 acres shallow in that field, much less at southeast where it is the big driver of our Cotton Valley wells there also.

Kim Pacanovsky – Collins Stewart

Okay and did I hear you correctly that you have two other wells that are drilling in Caddo Pine Islands?

Rob Turnham

No we have two other wells to complete in Caddo Pine Island, nothing currently drilling. Yes, one rig is working in Longwood in which you have a 17% working interest operated by a different company.

Kim Pacanovsky – Collins Stewart

Then I guess more of a strategy question in Caddo Pine Island, being that that is so far north from the more established area of the play; I guess I am just curious why you went ahead with three wells that far north instead of doing a one well and kind of waiting and seeing than committing more dollars?

Gil Goodrich

Good morning Kim, this is Gill. Obviously 20/20 is a beautiful thing. When we went into the deal someone mentioned earlier it was Matador and that is correct our partner there and operator is Matador Resources, we had an opportunity to join them at very attractive entry price levels to get into the deal and part of that was we knew the case that there was some time commitment on some leases and wells needed to be drilled in order to preserve leases, so we made the decision to step up and be a little more aggressive than we might ordinarily do to get into that deal. So we went ahead and drilled three wells that had to be drilled and we are now in a position of laying those just completed, see how they perform and obviously we can’t improve upon the results of the first one we won’t be drilling in more wells.

Kim Pacanovsky – Collins Stewart

Okay and what is your financial commitment there?

Gil Goodrich

We are done.

Kim Pacanovsky – Collins Stewart

What was it sorry, what was it?

Gil Goodrich

It was $1000 an acre plus a small carry on the first well. I think the initial promote added in and it came in at about $1500 per acre.

Kim Pacanovsky – Collins Stewart

Okay and I know that the Bossier Sand is partly down Angelina River, can you just kind of describe a bigger picture, how that was deposited and what kind of variation you might expect and is there any way to quantify, obviously it is not a resource based play but is there any way to quantify what you might have there?

Gil Goodrich

Yes, this is Gil again Kim, there are a couple of wells that run east or west across the surprise prospect area and the Hill well which encountered about 40 feet of this upper Bossier Sand with very significant bottom hole pressure is laying on the down turn side [ph] fall. That obviously has been dumped in there, we believe from a geological perspective elongated in an east west direction along the down turn side fall, how far east and west it goes we just don’t know, we are going to have some delineation wells to try to prove that up. It can be very small and it can be very small and it can quite large but we do not believe that it is necessarily present on the up front side or to the north of that vault and we believe that it does pitch out or it at least gets very thin as you go to the south. So you can think of is coming an oblong football that is running east, west elongated in there and the size of the tank is a question which we are trying to get our arms around as quick as we can, we just don’t know.

Kim Pacanovsky – Collins Stewart

Okay, great. That is a good description. And finally, can’t you just comment on what your thinking is on the ex tier results on that new horizon well and how you are looking at the play in East Texas and the prospectivity?

Rob Turnham

Kim this is Rob that was the most encouraging data what we have seen it is the well that is the closest to our acreage, it is roughly four or five miles north of this. It is a good bit west, it has very similar characteristics of shallow to what we see so clearly very encouraging and like what we are seeing in Longwood, they have reported a nice reserve relative to an initial production rate and therefore it exhibits some collateral decline. So that was extremely encouraging for us and as I said earlier we have been very encouraged just because of the productivity of our vertical wells in what we are seeing. So I have just been to get some wells down but that was a great data point for us.

Kim Pacanovsky – Collins Stewart

Okay, great, thanks a lot guys.

Rob Turnham

Thanks you.

Operator

Our next question comes from the line of David Heikkinen from Tudor Pickering & Co. David, you may proceed.

David Heikkinen – Tudor Pickering & Co.

Good morning guys. Just thinking about your acreage and where commodity prices are and allocating capital, how much of your acreage is held by production now in each one of the areas?

Rob Turnham

Davis, Rob again, at Bethany Longstreet it is basically 100% held and will be held with the drilling of the two wells that we have going right now and that would be basically all dealt over at Beckville Minden again where we have almost two-thirds of our Haynesville acreage, it is about 80% held by production old depths and 100% held on the shallow depth. So I think we have 12 wells at horizontal Haynesville Shale wells planned or budgeted in 2009 over the backbone Minden acreage which will in essence hold most of that acreage but even then we have three to five year leases on those acres that we took at Longwood and Gil said one of the reasons we stepped out and drilled some wells at Caddo Pine Island in particular with just some lease exploration dates and the well was in a little bit better shape but we did have I think plans to drill probably less than a handful of wells over I would say a year and a half to hold that acreage.

David Heikkinen – Tudor Pickering & Co.

Just thinking to how you allocate capital then, now you have the hedges and you have your Cotton Valley production that is going to at the end meet those – why not let the technology and kind of well results come to you a little bit and you are held by production acreage participate in the joint venture world that other people are running and just give the play a little bit of time?

Gil Goodrich

And we feel like that’s exactly what we have done, part of the reason we did the Chesapeake joint venture was to try to learn from them and they have done a nice job of bringing wells on budget as we said and we have taken that same procedure and apply it to East Texas, it is unfortunate we had a shallow problem on the first horizontal well there but we feel like that was an one-off circumstance and obviously the next two wells have gone well so far. Once we prove up our acreage in East Texas, as I said, we have 12 wells planned there, we do have some leave way within our budget, we have 10% allocated lease hold and infrastructure that is basically a plug number and we have a budget process that could change what you ultimately said we are waiting until the middle of the year before we decide what the ultimate second half of this year’s budget looks like. We are commenting on a number of things. We happen to think on the macro side that supply will correct and cost will come down and then once you get a handle on the demand side we feel like the commodity prices had a chance to rebounding and in the meantime we have plenty of flexibility and capital.

David Heikkinen – Tudor Pickering & Co.

And then just another side, on your PV10s did you run any commodity price sensitivities testing for what the yearend ’09 rules will be as far as commodity price and what value that would be?

Gil Goodrich

We just ran at $7.50 we did not do it on the average price.

David Looney

Well the average price in ’08 was higher than that so if we have been under ’09 rules as of December 31, 2008 it would have been $8, north of $8 and we have been completely (inaudible) in what we ran at $7.50 which I think we can put in.

David Heikkinen – Tudor Pickering & Co.

Yes, just was curious trended back in the – as things changed how the PV10 changes.

Gil Goodrich

And you can see there is great leverage to that, our future net revenue goes from $560 million to $1.3 billion by just going from $5.71 to $7.50 so as everything knows the Cotton Valley is a margin play and it is extremely leveraged to gas prices and costs and it is highly leveraged to those things.

David Heikkinen – Tudor Pickering & Co.

Right, that’s it, thanks guys.

Operator

Our next question comes from the line of Jo Allman from JP Morgan. Joe, you may proceed.

Joe Allman – JP Morgan

Good morning everybody.

Gil Goodrich

Hi, Joe.

Joe Allman – JP Morgan

I guess you have got five rigs running now, two I think in the Haynesville operated rigs that is and you are going to wind up with three in the fourth quarter. So I am assuming in the fourth quarter that is two in the Haynesville and where is the other one going to be running?

Gil Goodrich

It will alternate between Cotton Valley horizontal wells. As we said, we have five of those planned and I think we still have James Lime horizontal well or two that is budgeted.

Joe Allman – JP Morgan

Okay that is helpful. And then just thinking about data points that we can look forward to especially the Haynesville I guess you are completing two wells and I guess in Bethany Longstreet and one in Longwood and it sounds like we might hear about those I know you are going to say release one well at a time but we could hear some news maybe in March or April, got one in East Texas in April and then another one in East Texas maybe April, May. Now I guess we have these two in that Caddo Pine that is not too promising, is that kind of a good summary of what we are looking forward to in terms of data and am I missing anything from the Haynesville?

Gil Goodrich

No Joe, I think you have got it pretty good. Probably very late March, early April we got a timeframe of having some additional results.

Joe Allman – JP Morgan

Okay, very good, thanks very much.

Gil Goodrich

Thanks Joe.

Operator

(Operator instructions) Our next question comes from the line of Leo Mariani from RBC Capital Markets. Leo, you may proceed.

Leo Mariani – RBC Capital Markets

Hi good morning here folks, just kind of a follow-up to that question we had here, how may operated Haynesville wells do you have got a plan on drilling in 2009?

Rob Turnham

We have 12 gross and net operated wells planned out of the 40 gross 24 net.

Leo Mariani – RBC Capital Markets

So –

Rob Turnham

Half of the net total was the operated.

Leo Mariani – RBC Capital Markets

Okay and what are the ASPs for the well cost on those completed well cost?

Rob Turnham

We are working off of $8 million ASPs and ten stage fracs.

Leo Mariani – RBC Capital Markets

Okay, thanks a lot guys.

Rob Turnham

Thank you, Leo.

Operator

Our next question comes from the line of Ron Mills from Johnson Rice & Company. Ron, you may proceed.

Ron Mills – Johnson Rice & Company

Thank you, good morning. Here is the question and there may be more about Chesapeake and the way they are completely the wells and curiously about the differences in the ways they are completing wells, it looks like they are using smaller chokes than some of the other people, the rates are a bit low but can you give some of their thought processes as to why they may be doing that or in your discussions and then how do you plan on completing the wells in Texas or would you follow more the Chesapeake technique?

Gil Goodrich

Yes Ron, this is Gil, good morning. All things on the ground being equal bigger the choke size the more rates you are going to have so rates must be and IP must be mashed against the size of the choke as well as the flowing pressure obviously. So one of the concerns about opening the wells up too much is creating too much draw down or differential in pressures based on the perforations down hole or along the ladder and so we think that it is a more cautious approach a bit more concerned approach to keep the chokes down a little bit that being said if you can generate 6000 to 7000 pounds at the surface and your bottom hole pressure is 12,000 pounds that likely means that when you get down hole you are not drawn having too much draw downs so that is a comfortable range. Some areas are going to have higher porosity and permeability and will be able to flow more gas with more pressure and even higher chokes. I think we are seeing that kind of variability across the wells that we have reported thus far. As far as us in East Texas, I think we will let the reservoir tell us what the well is going to do both on choke side of the handle and on rates. But we are getting the rates and we are maintaining the pressure than you likely might see us going to open it up a little bit but we will let the reservoir tell us what it is going to do rather than make a predetermined approach.

Ron Mills – Johnson Rice & Company

Okay and I think you referenced the XTO Haynesville well in East Texas, how far was that well from your acreage and it sounds like that was between your acreage and the (inaudible) well trying to get us in terms of –

Gil Goodrich

That is correct Ron, it is probably about half way between the XTO new rises will tend up in the very northwest corner of Panola County so it is approximately 5 miles north and somewhat east of our Beckville block.

Rob Turnham

I would just make a comment that I know there has been a good bit of focus this morning on the Caddo Pine Island well hall 9 where we have got about 2900 acres. If you want to focus on impact to Goodrich, it is our East Texas acreage where we have got gigantic leverage to the play and that is of far more of an importance at least in our mind to the company in value creation.

Ron Mills – Johnson Rice & Company

Okay thank you guys.

Rob Turnham

Thanks Ron.

Operator

Our next question comes from the line of John Healy from Forest Investment Management. John, you may proceed.

John Healy – Forest Investment Management

Hi, I guess it is good afternoon now. On your revolver did you say the borrowing base is currently being re-determined?

David Looney

Yes John, this is David Looney that is correct.

John Healy – Forest Investment Management

What are you expecting in terms of – do you expect increase, decrease?

David Looney

You know we had $170 million borrowed base in place really since the mid-year timeframe, we did not push the bank’s estimate to increase last time around, certainly don’t see any need to push them to increase this time around given where we sit until we just see where it shakes out. Obviously their price decks have changed but certainly particularly when you look at the proved development reserves which is quite frankly a lot more important to the banks, our proved developed reserves were up from roughly 110 Bcf to 152 Bcf so we think we will be in good shape.

John Healy – Forest Investment Management

Then also in your press release you mentioned that you won’t need to have the capital markets this year but what if credits pulled back a little bit lately, but if the credit market continued to improve and the high yield market opened would it make sense given you have this $70 million secondly in term loan, it is not due to the end of 2010 but that coupled with you are going to burn through some cash this year would it make sense if that market opened up to slow the ten-year straight bond given the equities prices have sold off so much?

David Looney

Certainly from our perspective we have the luxury if you want to think of it that way of being able to watch the market and if there is a point in time when it looks like it is opportunistic to do something like that we would certainly look at very that very hard.

John Healy – Forest Investment Management

So I know it is hard to answer but if the things got significantly better in the capital markets in some point in the future, I guess what I am saying is the straight bond would be your first choice raising capital?

Gil Goodrich

Let me jump in here, you are asking of the hypothetical option and we don’t like to answer hypothetical questions. So I think it is best to say that we are cognizant of all the different market dynamics we are watching them all very carefully, we are very cognizant of the fact we have got a $75 million on a term loan when it comes to December 31, 2010 and we further have convertible notes that are due in December 11 at $175 million convertible at $66 a share, yes we are already thinking about those two instruments, we are thinking about how we make sure their balance sheet stays in excellent condition in order to satisfy both those requirements should the (inaudible).

John Healy – Forest Investment Management

Okay, thank you very much.

Gil Goodrich

How that comes about, we will just have to see over time.

John Healy – Forest Investment Management

Okay.

Operator

Our next question comes from the line of Joe Magner from Tristone Capital Inc. Joe, you may proceed.

Joe Magner – Tristone Capital Inc.

Just a question, I have seen some recent data that suggests a pretty close correlation between the amount of fraced volume of property put into a well of productivity, can you just review what your rest has been to date and whether you are considering any changes or what sort of changes you are considering given some of the lower rates and lower productivity wells you have had? \

Rob Turnham

Yes, so this Rob. I think one of the reasons why we feel good about our ten stage fracs at Bethany Longstreet in particular is one of the things we have done is we have added clustered perforations to each stage and we have increased the profit a bit. We are kind of going from 300,000 pounds at a stage to about 365,000 ponds, so we are eliminating cost by cutting back on the stages. We are adding perforations and we are hitting it with a little more profit. So we feel pretty good that we are zeroing in on the right recipe. As to the Longwood area, we have in essence tried the same frac up there than what we have been doing in Bethany Longstreet and I think it just reacted differently, it may well cut the rocks a little bit different as we said a little lower pressure, lower for us and we have potentially lower perm. So we are constantly trying to tweak it, East Texas may be a different area that could react differently but we will certainly take what we are learning from the Chesapeake joint venture and apply it in East Texas.

Joe Magner – Tristone Capital Inc.

Good thank you and just following on some of the earlier comments and questions about choke sizes and rates, and how you balance that out, have you seen anything or any information or data that would suggest that some of the rates or pressures that have been seen or utilized so far have led to any issues or is it too early still the life of some of those wells to notice whether or not you would see any fallback or any detrimental behavior?

Gil Goodrich

Yes Joe, this is Gil, the answer to that would be no, we haven’t as I tried to say a minute ago I think the choke sizes and the pressures are related and so if you continuing to have higher pressures at the surface then you can afford to have higher choke size of that creating any kind of risk to the formation and I have not seen anything that would alarm me from a reservoir perspective and I am not aware of anyone having any material problems thus far.

Joe Magner – Tristone Capital Inc.

Okay just one last question, a couple of comments on some of the wells are producing at lower rates over time there might not be much difference to the recovery and perhaps don’t have a flatter decline or less sleep decline and a flatter production curve, can you talk about what your estimates are, assumptions are on starting with an initial first year decline and how that compares to I guess existing conventional wisdom of 75% to 85%.

Gil Goodrich

I would start with – hovering back to one of my earlier comments in the beginning which was that we think that porosity and permeability are going to be significant drivers so if you kind of move that to the side for a second, you make the assumption that the reservoirs themselves are all exactly the same, which they are not but if they were then obviously a smaller choke and therefore a smaller flow rate initially will ultimately still get you the same amount of gas but it is taking longer to get it out and you will see a flatter decline from that performance then you would have just opened up and borrowed much gas than you could immediately that would get you back to more the kind of 80% to 85% in the decline. If one were to cut this thing back to say 16% or 20 to 26% choke, you are going to see flatter comps perhaps in the 70% to 75% range first year but under the assumption they all have the same porosity or permeability you will ultimately get the same amount of gas. Does that answer your question Joe?

Joe Magner – Tristone Capital Inc.

Yes, it is fine; I can follow up later on.

Gil Goodrich

Okay.

Joe Magner – Tristone Capital Inc.

Thanks.

Operator

Our next question comes from the line of Richard Tullis from Capital One Southcoast, Inc. Richard, you may proceed.

Richard Tullis – Capital One Southcoast, Inc.

Thank you. Rob or Gil, looking at your initial Haynesville well, the Holland well, how was that performing I think it came on early January?

Gil Goodrich

Yes Richard, good morning, what we said was that through the first several weeks production had held in quite nicely. We don’t get into a spot or a point in time numbers, we will have to happy that (inaudible) next time we have got an operating release to give you some performance numbers but right now it is best to say that we are very pleased with what we have seen thus far.

Richard Tullis – Capital One Southcoast, Inc.

Was that well included in your awaited reserves?

Gil Goodrich

That well was and in fact that was the only Haynesville horizontal well that was included in our year end services. I will say before you ask the next question that well did not come on line until basically January 1 so the amount of data that (inaudible) in here from working with was I would say very limited and therefore they were kind of having to grasp in the air to come up with reserved numbers. So we think that number will have a very different look to it when we get to the midpoint this year.

Richard Tullis – Capital One Southcoast, Inc.

Okay. The 15% to 20% decrease in well cost that you guys had mentioned a little earlier, did that include the Haynesville as well or the other area that you operate in?

Gil Goodrich

No, that would be kind of a blended average look at our 2009 and of course that number is moving all around and it would be a combination of rig rates, pipe prices, profit, yes we would hope and we would expect if lower commodity prices continue those costs will continue to fall.

Richard Tullis – Capital One Southcoast, Inc.

Which type of profits are you using in the initial Haynesville wells?

Gil Goodrich

We would use both rather than coated sand and ceramic proppant they are both are holding up well, ceramic proppant is a little bit more expensive, it is a great product but we are not seeing any detrimental results with the rest of coated sand so far.

Richard Tullis – Capital One Southcoast, Inc.

Okay, I know you mentioned the well cost, the Graham well and kind of what you are use and your modeling for your 100% wells, what was the cost on the Percy Sharp in Longwood.

Gil Goodrich

All of our wells have been within that range that I quoted earlier about 7.5 to 8.5, yes we have experimented like others with number of stages on the fracs and I think over time we will free up the optimum number of stages and kind of best drill and complete and hopefully drive those costs down and of course the last well that we brought on being the Graham has been the cheapest well that we have done so far. So hopefully we can replicate that but over time we will just have to see.

Richard Tullis – Capital One Southcoast, Inc.

Okay the surprise prospect wells, what would those run in you approximately?

Gil Goodrich

Yes Richard they are chocolate, vanilla and strawberry and a couple of other more we are just at Travis Peak wells vertical and those came in at about $2.5 million per completed well and a couple of Hill and then a couple of them and the one we are drilling now our newest have gone down the Haynesville, those are deeper wells that will probably be in the $4.5 million range there.

Richard Tullis – Capital One Southcoast, Inc.

Okay. That’s all from me, thanks very much.

Gil Goodrich

Thanks, Rich.

Operator

At this time, we are showing no further questions available. Mr. Gil Goodrich, you may proceed sir.

Gil Goodrich

Thanks very much. We appreciate everyone’s participation this morning and we look forward to getting back when we talk about first quarter results in a few months. Thanks.

Operator

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

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