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Goodrich Petroleum Inc.(NYSE:GDP)

Q4 2007 Earnings Call

March 13, 2008 11:00 am ET

Executives

Gil Goodrich - Vice Chairman and CEO

Robert Turnham - President and COO

David Looney - EVP and CFO

Mark Ferchau - EVP and Director of Engineering and Operations

Analysts

John Freeman - Raymond James

Ellen Hannan - Bear Stearns

Brian Kuzma - JPMorgan

Robert Lynd - Simons and Company

Kim Pacanovsky - Ferris, Baker Watts

Richard Tullis - Capital One Southcoast

Ron Mills - Johnson Rice

Monroe Helm - CM Energy Partners

Operator

Good day, ladies and gentlemen, and welcome to the fourth-quarter 2007 Goodrich Petroleum Earnings Call. My name is Daniela, and I will be your operator for today. At this time, all participants are in listen-only mode and we will be facilitating a question-and-answer session towards the end of this conference. (Operator Instructions)

As a reminder, this conference is being recorded for replay purposes. I would now like to turn the presentation over to your host for today's call, Mr. Gil Goodrich, Vice Chairman and CEO. Please proceed, sir.

Gil Goodrich

Good morning and welcome, everyone. I'd like to begin by introducing the other Goodrich 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 and Director of our Engineering and Operations.

If you've not received a copy of the earnings release that we put out last night, you may find one on our Website at www.goodrichpetroleum.com, or feel free to call my personal assistant Becky Delatin at 713-780-9494. She will be happy to fax or e-mail you a copy.

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

During 2007, our aggressive drilling and development activities led to record additions to proved reserves. Proved reserves grew by a 105% to 358 Bcfe, which were 97% natural gas and 31% developed. After subtracting approximately 32 Bcfe, associated with our sale of assets in South Louisiana in the first quarter of last year and the approximately 16 Bcfe actually, we have produced in 2007, we added approximately 200 Bcfe of proved reserves with our organic drill bit focused activities. These additions to proved reserves resulted in a replacement of an impressive 1,150% of our 2007 production.

With the drilling and development capital expenditures of $274 million during the year all in, finding and development costs were $1.38 per Mcfe. As a significant percentage of our proved reserve are currently classified as proved undeveloped, we have included the incremental estimated capital required in fully developed our existing proved reserves and estimated total proved reserve additions in 2007, plus future development costs resulted in an estimated $3.46 per Mcfe F&D, which we believe better reflects our underlying economics and it is where we would expect our DD&A rates to trend overtime, as we increase the maturity of our assets.

I'm pleased to report that we achieved our internal production targets in 2007 with sequential production growth in each quarter of the year and annual growth of 44% from continuing operations versus 2006. In addition, the pace continues and this morning we are again, projecting meaningful sequential growth in the first quarter of this year to an average of approximately 55 million to 57 million cubic feet of gas equivalent per day or 9% to 13% sequential growth over the fourth quarter of last year.

While reserve additions and production growth met or exceeded our internal projections for the year, reported fourth quarter and year-end financial results were impacted by a number of items. David will discuss these in more detail shortly but I would like to address a few of them.

First, relatively low nature gas prices for the quarter and full-year impacted cash margins somewhat during the periods. For the year, we expensed approximately $80 million in non-cash DD&A expenses or approximately $4.99 per Mcfe of production.

As we have said on previous calls, we used successful efforts method of accounting, which requires us to calculate our DD&A rates using our total net book capital divided by proved developed reserves only, which results in generally higher DD&A rates then if we included all proved reserves in the corresponding future estimated development cost. Consequently, we are amortizing our invested cap costs at a relatively rapid pace given our reserve life at year end of approximately 22 years.

Finally, lease operating expense, or LOE, were higher in the quarter than we had projected, primarily due to ongoing salt water disposal costs. While our salt water disposal costs have been reduced as expected with our low pressure gathering and salt water disposal system in the Beckville Field area, our increased level of activity in the Angelina River Trend, which is still largely an emerging play for us, and where we maintained a minimum three rigs during the second half of the year, and the salt water disposal costs associated with the production in this area more than offset the gains we made in period.

We have recently added one salt water disposal, or SWD, well in the Angelina River Trend area, which should improve cost going forward, and as our level of concentrated geographic drilling increases in this area, we will be able at a future date to just file the investment for a complete gathering and disposal infrastructure as we put in, in the Beckville area.

While we hope and expect LOE will trend downward, we do expect some variability from quarter-to-quarter depending on the various levels of activity and associated production in each area.

During 2007 we invested approximately $275 million in drilling and development activities, which is somewhat greater than our preliminary budget of $245 million. The incremental capital expenditures were driven by several additional non-operated wells which were proposed and drilled in 2007, as well as incremental capital from wells drilled in prior periods but accounted for in 2007, and some capital associated with 2007 cost overruns.

For 2008 we have budgeted 115 gross Cotton Valley Trend wells to be drilled, and approximately $275 million in total capital expenditures which includes approximately 20 non-operated wells of the 50 wells planned in the Angelina River Trend, targeting both Travis Peak and James Lime formations, as well as approximately $30 million for additional leasehold acquisitions and infrastructure investments.

We anticipate approximately 70% to 75% of our 2008 capital expenditures will be directed towards core infield drilling with the balance being allocated to continue step-out drilling, designed to further prove up and enhance our inventory of future development opportunities.

In 2007, we drilled seven 20-acre space Cotton Valley sand wells in the North Minden and Beckville areas of Panola and Rusk Counties in East Texas. These seven wells were included in our year-end reserve report and have an average estimated ultimate recovery, or EUR, of approximately 1.1 Bcfe per well. With these strong results, we will continue to exploit our acreage on 20-acre spacing and enhance our inventory of development locations accordingly.

We also initiated the development of the James Lime formation in the Angelina River Trend using horizontal drilling and completion technologies. While we are still early in the development of the play, and preliminary results have varied somewhat, we remain encouraged about the play, the potential to achieve enhanced economics and currently plan to drill approximately 15 to 20 James Lime wells in 2008.

In addition, we are currently drilling our third Cotton Valley horizontal well in northwest Louisiana and as Rob will outline in just a minute, we remain encouraged by the results we've experienced thus far and we plan to continue to test and exploit the Lower Cotton Valley, Davis and Taylor Sand, using horizontal drilling.

Finally, we are watching very closely as a new play emerges in northwest Louisiana and in around our position of approximately 47,000 gross acres in DeSoto and Caddo Parishes for the Haynesville or Bossier Shale section located between 11,500 and 12,000 feet.

In an effort to better understand the potential of the Haynesville Shale under our acreage and to be positioned to exploit our position, we had recently drilled a vertical well to James Cook No. 1 in the Bethany-Longstreet field deep enough to see the Haynesville and encourage strong gas shows over the targeted 220-footage interval with similar log characteristics to the initial offset wells.

In order to provide downside price protection and enhance our ability to continue the execution of our strategy, we have recently augmented our existing hedge position with incremental hedges in both 2008 and 2009 and fixed price slots ranging between $8.60 and $8.90 per MMbtu, which has us with approximately 65% of consensus 2008 gas hedge at a blended average minimum NYMEX equivalent of $8.24 per MMbtu and 50 million in MMbtu per day hedged for full year 2009 at a blended average minimum NYMEX price of $8.43 per MMbtu.

In addition, the equity offering we completed last December and the second lien term loan funded in January of this year added approximately $200 million in liquidity, which we are confident had us well positioned to continue our aggressive nine rig development plan well into 2009. And we are already evaluating a number of additional opportunities to further increase liquidity, including potential disposition of non-core assets, which will allow us to maintain our aggressive plans into 2010.

During 2008, we look to continue to judiciously add to our existing acreage position in the Cotton Valley trend, continue with the execution our balance development strategy, focusing on both rapid conversion of non-proved reserves in to the proven category and the maturing of concentrated areas of our acreage, so we can further leverage off the economies of scale that come with concentrated geographic drilling and operations, as well as continue to further delineate, expand and de-risk that currently less developed portions of our acreage.

I would now like to turn the call over to Rob Turnham for a more detailed analysis of our operating results.

Robert Turnham

Thank you, Gil. We continue to be focused on production volume and reserve growth through the drilled bi and 2007 was a very good year on both fronts. Our growth in Cotton Valley trend production volumes grew to a record 85 million cubic feet equivalent per day average for the quarter, with net production volumes for the quarter in excess of 50 million per day, a 9% sequential growth rate.

We had 257 Cotton Valley trend wells producing as we exited the quarter with 10 in completion phase and one well suspended for mechanical reasons, bringing the total to 268 wells drilled and logged, with the success rate in excess of 99%. Of the 257 producing wells, 88 were in Minden, 65 at Beckville, 38 in the Angelina River Trend, 32 at Bethany-Longstreet, 21 at South Henderson, and 13 on other acreage outside of our core areas.

For the quarter, we completed 36 wells, in six fields with an average initial production rate in excess 1.9 million cubic feet equivalent per day, which is approximately 100 Mcfe per day, or 6% higher than our historical average. Of the 36 wells completed during the quarter, ten were in the Angelina River, nine at Minden, eight at Bethany-Longstreet, five at Beckville, four at South Henderson.

For the full year 2007, the company completed 95 of the 104 wells drilled with an average initial production rate of approximately 2 million cubic feet equivalent per day. Of the 95 wells completed in '07, 25 were completed in our Minden field with an average IP rate of 1.7 million cubic feet per day, 13 at Beckville with an average IP rate of 2.1 million cubic feet per day, 17 at Bethany-Longstreet with an average IP rate of 1.9 million cubic feet per day, 26 at Angelina River with an average IP rate of 2.8 million cubic feet per day, 12 at South Henderson with an average IP rate of 1.7 million per day and two outside of our core areas with an average IP rate of 900 Mcf per day.

One of our non-core areas with the low IP rate was in Alabama Bend, a property in North Louisiana, which comprises the majority of our impairment for the quarter, which David will discuss a little bit later in the call.

At Minden, of the 25 wells completed during the quarter, 14 were drilled in our Southeastern portion of our acreage block, including one 20-acre spaced well and the results were encouraging. The average initial production rate of these wells was 1.9 million per day and they had an average reserve of 1.1 Bcfe at year end. Included in this area of North Minden is our A. Brooks No. 5 well, with the additional 20-acre spaced well in the field, and at year-end it had a reserve of approximately 1 Bcfe equivalent, consistent with its 20-acre offset well reserve.

With these results, we've now included the Southeastern portion of North Minden and our inventory chart on the basis of 20-acre spacing along with Beckville field, which has six producing wells on 20-acre spacing, all of which have had no apparent communication with the offset wells. We will continue to drill in this portion of North Minden in 2008 with at least one rig working continuously in the area, drilling both 40-acre and 20-acre spaced wells. We also have plans to test in 2008 our South Henderson acreage on 20-acre spacing later this year.

We conducted drilling operations on 43 wells during the quarter, with approximately 10 rigs running, nine of which we operated. Of the 43 wells in which we conducted drilling operations, 12 were drilled in Angelina River, with 10 being Travis Peak wells and two being James Lime horizontal, ten were at Minden; seven at Beckville; five at South Henderson; and eight at Bethany-Longstreet.

Our drilling plans for 2008 will be focused on continuing to drill proven areas of our core Cotton Valley acreage, both on 40-acre spacing and 20-acre spacing, continue to aggressively drill our vertical Travis Peak wells in Angelina River, as well as continuing to test horizontal applications on our acreage, in the Davis and Taylor sands and the Cotton Valley sands, the James Lime formation in Angelina River and potentially the Haynesville shale and even Bethany-Longstreet or Longwood.

Focusing on Bethany-Longstreet again, which is in Caddo and DeSoto Parishes, we're currently drilling our Champe Graham 5-H, our Cotton Valley horizontal well targeting the Davis sand similar to our Champe Graham 3-H.

We expect to reach total depth and have production results of about 60 days. Gil stated earlier, we are encouraged by results from our James Cook 1 vertical well, which saw approximately 220 feet of net thickness is the shale, with good gas shows and we will continue to evaluate our 47,000 gross, 25,000 net acres in the place, as well as monitoring offset activities with plans to test the Haynesville later this year.

Our vertical well development continues to perform very well at Bethany-Longstreet, with both the Cotton Valley and Hosston presence and a 100% of our wells drilled to-date. At Longwood which again is north of Bethany-Longstreet in addition to the Haynesville shale potential, we have drilled and completed our initial Cotton Valley sand horizontal well on our 19,500 gross, 6,400 net acres which we call the AC Mitchell 1-H.

The Mitchell 1-H had an initial production rate of 2 million cubic feet per, a 30-day average of approximately 1.9 million per day and a current rate of approximately 40 days into production of the same 1.9 million cubic feet per day. IP results were lower than expected, but the well has shown very little decline in the first 40 days versus what we typically see in both vertical and horizontal wells which is certainly encouraging. We have plans to drill second Cotton Valley well and acreage in the second quarter.

Moving to Texas, we continued to focus more and more of our efforts in the Angelina River trend, where we own in average 58% interest and 69,500 gross acres. This area has substantial potential for the company and that we have two plays working simultaneously, Travis Peak vertical wells and horizontal James Lime wells.

For the quarter we participated in drilling operations on 10 vertical Travis Peak wells and completed six with an average initial production rate of 2.7 million cubic feet per day. We are continuing the test at James Lime with horizontal drilling and now completed four wells with an average initial production rate of 7.8 million cubic feet equivalent per day.

Our most recent well, the LB Mast 1H in the Cotton Prospect area had a 24-hour initial production rate of 8 million cubic feet per day. We are flowing back our first well in Bethune Prospect currently, the Bethune A-1H, but initial flow back results have been inferior to our Cotton Prospect wells.

We plan on drilling our initial James Lime horizontal well on our Cotton South Prospect during the second quarter and are encouraged by results from an offset operator just west of our Cotton South acreage.

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

David Looney

Thank you, Rob, and good morning, everyone. Reported revenues for the fourth quarter of $32.5 million were based on average prices of $6.60 per Mcf of gas and $89.60 per barrel of oil.

On gas, our differential was approximately $0.37 below the average Henry Hub price during the quarter which was slightly lower than the prior several quarters, but largely a function of the way we sell our gas on spot versus index basis.

On oil, we realized an average basis of $0.89 off of the WTI Cushing prices during the quarter. These prices do not include the impact of $1.1 million in realized gains on our hedge portfolio during the quarter.

Just to reiterate, for all of 2007 our gas and oil hedges were being ineffective. Thus, the changes in the mark-to-market value of the contracts must run through the line item, gains and losses on derivatives not qualifying for hedge accounting. This line item includes both, unrealized and realized gains or losses. Thus again, the realized gain of $1.1 million is not included in the revenue line I just mentioned, nor is it included in operating income on our financial statements as presented under GAAP.

Looking for just a moment at cash flow, our EBITDAX, or earnings before interest, taxes, depreciation, amortization, and exploration, for the fourth quarter was approximately $19.7 million or $0.74 per basic share. Discretionary cash flow defined as net cash from operations before changes in working capital was $15.6 million for the quarter.

Our 12-month EBITDAX was $74.6 million, or $2.92 per basic share, a 79% increase over the $41.6 million, or $1.67 per basic share for the year ended December 31, 2006. Similarly, discretionary cash flow, or DCF, in the current 12-month period was $68.1 million, a 13% increase over the 12-month period ending December 31, 2006.

Note that the 12-month ended December 31 '06 number for discretionary cash flow actually includes the results from the South Louisiana operations which were sold in early 2007, as discretionary cast flow and cash provided by operating activities do not recognize the distinction between continuing and discontinued operations.

Focusing on the expense side of the income statement; Our lease operating expense in the quarter was approximately $6.9 million or $1.50 per Mcfe on a unit basis, which was up from the $1.44 per Mcfe in the fourth quarter of 2006 and a $1.22 in the third quarter of this year.

The largest category of expenses relative to our LOE is saltwater disposal costs, as we've mentioned before. In the Cotton Valley Trend these costs have been running us on average between $0.40 and $0.45 per Mcfe of gas produced. As we've progressively drilled up our East Texas acreage position, we've chosen well locations, obviously, based on a number of different factors, many of which have caused us to spread our wells out across wider geographic areas.

As such, the cost to truck and dispose of the saltwater produced by the typical Cotton Valley well has been exacerbated by the lack of adequate nearby disposal facilities in many cases. For example, our disposal costs ranged from approximately $0.50 to $0.60 per barrel of water produced in the areas where we have installed the appropriate infrastructure, to an expense of $2 per barrel in the areas where we've not established any meaningful concentration of producing wells.

In the last few months the company has taken several steps, we feel will ultimately lead to a significant reduction in these costs, including drilling and establishing two additional saltwater disposal wells on our acreage position and lay saltwater disposal lines in association with our previously disclosed low pressure gathering system. We've seen significant reductions on the order of 50% in the one major field where they we have installed these lines, which is Beckville.

Our plans are to put similar systems in all of our major fields, once they reach critical mass. However, such capital investments generally cannot be made until we've drilled enough wells in that particular area to make such facilities economic. As such, we expect to install two such systems this coming year, one in Minden and other Bethany Longstreet and we have alternatives disposal plans offsetting our Cotton South area in the Angelina River Trend.

Production and other factors for the quarter totaled $1.3 million for $0.27 Mcfe production versus $322,000 or $0.11 per Mcfe for the prior year period, due largely to the inclusion of ad valorem taxes in the 2007 numbers. In prior years, these amounts ad valorem taxes, were included in LOE and were not significant as the company was in early stages of developing its assets.

While we still continue to do a good job applying for and receiving severance tax credit on most of our Texas based wells, delays in the regulatory process can result in somewhat lumpier bookings of these credits than we would like. Additionally, the more developed nature of some of our field is leading to the higher ad valorem tax that I mentioned just a moment ago.

Transportation expenses; totaled $1.7 million in the fourth quarter or $0.37 Mcfe versus $1.1 million in the fourth quarter of 2006, and was flat from the $1.7 million in the third quarter of this year. Given our portfolio of transportation agreements, which varies across our acreage box, we would expect this expense to remain in the $0.37 to $0.40 range per Mcfe going forward.

DD&A totaled approximately $22.2 million for the quarter or $4.77 per Mcfe versus $11.5 million or $3.77 in the fourth quarter of 2006 at $4.77 for the third quarter of this year. As Gil mentioned, our per unit DD&A rate for 2007 is a function of the reserves based on our last complete independent reserve report during the year, which in this case for 2007 was the midyear report.

The recently received reserve report, detailing year end 2007 reserves will be used to calculate our DD&A rate for the first several quarters of 2008. At this point, while we've completed our analysis, we do not expect a material change to our DD&A rate in the first and second quarters of 2008 as it relates to the last two quarters of 2007.

Our exploration expense totaled $1.5 million for the fourth quarter or $0.32 per Mcfe versus $1.4 million or $0.48 per Mcfe in the fourth quarter of 2006 or $1.7 million in the third quarter of 2007. Other $1.5 million this quarter, $1.1 million or 73% was associated with the amortization of our undeveloped lease sold cost, which we do amortize over a three year period.

Well, there were no dry-hole expenses for the quarter, as Rob mentioned we did take a $7.4 million impairment charge in the quarter, of which $6.1 million was related to the two wells that we had drilled earlier in the year in the Alabama Bend area.

Our G&A expense was $5.0 million for the fourth quarter or $1.08 per Mcfe versus $5 million or $1.63 per Mcfe in the fourth quarter of 2006. Of the $5 million, $1.03 million, which is 21% of the total, or $0.22 per Mcfe, was a non-cash expense related to stock-based compensation.

Finally, we reported a net loss of $20.6 million, or $0.77 per basic share, for the fourth quarter. The net loss applicable to common stock for the quarter was $22.1 million, or $0.83 per basic share.

Looking at the balance sheet for a moment, while we are certainly cognizant of the turmoil in the credit and other markets, we've been extremely pleased with the appetite shown by the market for all types of Goodrich paper, as evidenced by the almost $200 million we raised in the months of December and January right in the midst of these difficult market times.

To recap, during the fourth quarter, the company issued approximately 6.4 million shares to common stock which raised approximately $124 million net to the company after paying for the concurrent capped call transaction at that time.

At the end of the fourth quarter, revolver debt outstanding totaled $40.5 million, reducing the company's debt-to-cap ratio to approximately 42% to 43%. As most of you are aware, we raised $75 million in January 2008 with our second lien term loan facility, and thereby reduced our revolver borrowings to zero on a pro forma basis.

With year-end 2007 proved reserves increasing to 358 Bcfe, we certainly expect to receive another borrowing base increase during the first quarter of 2008 after we submit the report to our bank group.

Our past track record gives us confidence that the borrowing base will continue to increase as we execute on our Cotton Valley drilling program, and this in conjunction with our growing cash flow should provide us ample liquidity well into 2009. Having said that, we are actively exploring other possible sources of financing, including the possible sale of certain non-core properties, to help reduce the long-term funding needs of Goodrich Petroleum going forward.

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

Gil Goodrich

Thank you, David. We are extremely enthusiastic about our prospects for 2008, the depth and strength of our portfolio, drilling locations, and opportunities, continues to grow and improve. Our balance sheet as David said is in very good condition, and allows us to continue aggressively developing those opportunities well into 2009. And as we continue with development of our assets, the options and opportunities to incrementally fund development into 2010 increases significantly.

We appreciate your participation this morning, and we'll be happy to answer any questions you may have.

Question-and-Answer Session

Operator

(Operator Instructions) Your first question will come from the line of John Freeman with Raymond James. Please proceed.

John Freeman - Raymond James

Hi, guys.

Robert Turnham

Hi, John.

Gil Goodrich

Good morning, John.

John Freeman - Raymond James

First question on the AC Mitchell 1-H well, while the IP rate I guess was what you all had hoped for. You did mention the extremely shallow climate over the first 40 days. Just wondering if there was something done on the completion side differently that may have caused this?

Gil Goodrich

No. John. Good morning. This is Gil. No, nothing was done differently. In fact, we drilled and completed and frac that well almost identical to what we did on the Champe Graham 3-H well. Those wells were about 20 miles apart from each other, Mitchell obviously being up at Longwood and Northern Caddo Parish.

So we don't really have a very good explanation why the IP rate was not higher, we were expecting kind of 3 million to 4 million day rate but can't say that we certainly -- we are watching it very closely and it's going to take a few months for us to sort out. We're very pleased with this performance in the 40 or so days that it has been on line.

John Freeman - Raymond James

All right. And then on the 20-acre down spacing, so far, has been focused on Beckville North Minden, obviously looked pretty successfully. Are there any plans to test some other fields, and if so, which are they?

Gil Goodrich

Yes. I mean, Rob, I think, mentioned this morning that we do have plans to go down to South Henderson which is an active area for us and Rusk County, south and west of our Minden Beckville blocks, and we plan to drill 20 acres space power them there sometime during the year.

John Freeman - Raymond James

Okay. And then on the James Lime, obviously you have pretty good results there on the Cotton Prospect. Of the three rigs that are in Angelina River, how many of those are just focused on the James Lime as opposed to Travis Peak?

Gil Goodrich

Yes, good question. John, currently just one operated well rig is targeting the James and then sporadically a second non-operated rig particularly up on the Cotton Prospect. At Cotton, in particular, we expect roughly 10 non-operated James Lime wells to be drilled at Cotton.

John Freeman - Raymond James

Okay. So for right now, there's no change kind of in the mix of, I mean, I guess, last quarter, you all did like 10 Travis Peak wells, two James Lime, it's same kind of mix going forward and majority the two rigs basically Travis Peak, one James Lime for the most part?

Robert Turnham

Yeah. John, this is Rob. I think we put this in our presentation. Our best estimate is about 30 Travis Peak wells in ’08 and 20 James Lime and that would be split between operated and non-operated.

John Freeman - Raymond James

Okay and then last question and then I will turn it over to somebody else. Obviously this James well sounds pretty exciting. Based on your comment and the kind of press release. Am I right in assuming that your kind of taking a wait-and-see approach, waiting to see what some other competitors get before you all kind of proceed?

Robert Turnham

Exactly right John this is very early in the play. Not a whole lot of information has been reported publicly and we are going to sit and wait on the public reported data and look at that overtime. So that we can get to a position of been able to model that production and model those reserves and start to get a feel for what kind of alternate recoveries we would see. That being said we certainly have been looking at the technical aspects of it and are encouraged of what we see as a fairly broad based play that we would have acreage position, very well positioned for that overall play.

John Freeman - Raymond James

Okay, great thanks guys.

Operator

Your next question will come from the line Ellen Hannan with Bear Stearns. Please proceed.

Ellen Hannan - Bear Stearns

Good morning.

Gil Goodrich

Good morning Ellen.

Robert Turnham

Good morning Ellen.

Ellen Hannan - Bear Stearns

Just a few question here, it is a kind of follow up. Can you talk about your drilling inventory now being around 2000 locations which looks like it is obviously is up from the last reserve. That’s a gross or a net number, but was any portion of what you have, did you decrease what you think you are going to do with the impairment in the Alabama Bend area?

Robert Turnham

Hi this Rob. The 2000 locations are internally risked, the additional locations really came from 20-acre spacing at Minden. Additionally, proving up a little bit more acreage on the Angelina River although we still have a quite a bit more to do there and de-risk. And Alabama Bend was never in there. We have drilled those two wells probably nine months ago, initially knew that results were invariable, we have been drilling and never put any of that potential in the inventory, so the 2000 is a growth number. It did take our three key reserve exposure up by approximately 200 Bcf when you add in the additional proved reserves and probable reserves. So obviously with success, it's certainly panning out and adding to our inventory.

Ellen Hannan - Bear Stearns

Okay, thanks. On the 20 acre down spacing of the seven wells you've done so far, is there a wide range? You mentioned that the 1.1 Bcf was an average is that something -- some figure around that or..?

Robert Turnham

No. They were actually not all sitting right on top of each other, but the band was fairly narrow.

Ellen Hannan - Bear Stearns

Right.

Robert Turnham

I can't think of any that were below an economic level, they were all pretty solid numbers.

Ellen Hannan - Bear Stearns

Okay.

Robert Turnham

The lowest we had a was a Bcf and there were a couple that were certainly higher than that that would make the average 1.1.

Ellen Hannan - Bear Stearns

Okay, and, Rob, you just mentioned this, on the James Lime for the 20 wells that you've got slated for this year to a mix of operated, non-operating. Can you give us a feel of how much is which or..?

Rob Turnham

Yeah, that is roughly 50% each. It kind of depends on certainly the operator there on the Cotton Prospect area. That's the indication that we have, that they are going to drill nine or 10 this year. So at this point in time, we would say 50% each, and certainly as we said one of our next wells, in the second quarter will be to drill over Cotton South, which would be our first well on that Prospect area, and we're encouraged by an offset operator who drilled a well directly offsetting our acres to the west. But with results from that well, we'll de-risk that portion of the acreage, which would clearly add additional probable reserve potential as well as certainly proved reserves.

Ellen Hannan - Bear Stearns

Okay. Great. There is two quick ones here maybe for David. You mentioned that you have added some additional hedges for '08 and '09, is that in addition, something incremental versus the last update you had, I think it was the 16th of January out on the website. Is there -- should we be looking for a new schedule there and also could you happen to have your, what your deferred taxes were, the expense either in the quarter or year-to-date, either one.

David Looney

Yeah. I am David, we will be updating the website on the hedge. I believe it is updated through early February. Because when we file our K, which should be later today, we will have full disclosure of that.

Ellen Hannan - Bear Stearns

Okay. Thanks.

David Looney

Yeah. On the deferred tax hedge. Now as you are aware we did in the third quarter, we had to write of deferred tax asset based on looking at all the available evidence as rules require us and again in the K, we'll obviously have a discussion of what we expect our net operational loss carried forwards are going forward and all that. But we will not have any sort of deferred tax asset on our books at 12/31/07.

Ellen Hannan - Bear Stearns

Great. That’s it for me. Thanks.

Operator

Your next question will come from the line of Brian Kuzma with JPMorgan. Please proceed.

Brian Kuzma - JPMorgan

Hi. Good morning, guys.

David Looney

Hi, Brian.

Brian Kuzma - JPMorgan

Could you go through Bethany-Longstreet again? And with regards to this Haynesville potential, what did you say your net acreage was there?

Gil Goodrich

Very good morning, Brian, this is Gil. We said in the overall trend, which includes Longwood and Bethany-Longstreet, we’ve got 47,000 gross about 25,000 net. At Bethany-Longstreet, in particular, it's about 19,000 net acres.

Brian Kuzma - JPMorgan

I got it. Okay. And how far away are Chesapeake horizontal wells from Bethany-Longstreet?

Gil Goodrich

I think at least one of them Brian is about a mile a away, 1 mile to 2 miles away, section removed from the north end of our block.

Brian Kuzma - JPMorgan

Okay.

Gil Goodrich

And then the initial well that we aware of is probably another 5 miles north of that.

Brian Kuzma - JPMorgan

Okay. And so, these are the wells that you are comparing your results, your logs to those prospects?

Gil Goodrich

Yes. And then there is a private operator that has drilled a couple of wells also vertically within that overall area and we have the information from those wells. And then regionally, there has been some wells drilled both west of us and east, actually heard about one this morning at south Davis, we don't have information of that well yet.

Brian Kuzma - JPMorgan

Okay.

Robert Turnham

Brian, this is Rob. I will remind you, we have updated our presentation also and it's on our website and you will be able to spot where the offset wells are relative to our acreage.

Brian Kuzma - JPMorgan

Okay. And do you guys think that you will be able to replicate the results that other players have seen with their horizontal programs?

Gil Goodrich

Well, I will take stat at that one. Brian, we are hearing most of the information that we've received thus far is second and sometimes third hand information as this is a very new play. Only a spattering of information has actually been filed publicly. So, what we're hearing is very positive, it's very encouraging. We would only say this, what we see on the well that we have drilled has all of the characteristics earmarks and details of what we've seeing in the offset well.

Brian Kuzma - JPMorgan

Okay. And do you guys have seen enough that you are going to try horizontal wells yourself on Bethany-Longstreet?

Gil Goodrich

Well, as I said, I think a minute ago, we certainly want -- I think it's an answer to John's question, in a wait-and-see actually, we certain want to see several months of production so we can start getting arms around the modeling of that and seeing what is telling us in terms of decline rates and therefore some preliminary range of EUR projections versus the capital costs. So that we could get a better feel what the ultimate economies would be in the play before, we would step out and drill the baseline horizontally.

Rob Turnham

Brian, again this is Rob. What we are encouraged by the James Cook 1 well that you also see on our presentation is drilled pretty much in the middle of our acreage and so we step a good bit away from the offset wells that we have data on and drilled to the handful.

Brian Kuzma - JPMorgan

Okay. And has there been interest in your deeper rights at Bethany-Longstreet from competitor activity?

Gil Goodrich

Yes. Let us just say that, yes, there are some things that's been coming back to us, both directly and indirectly relative to our acreage in deep rights.

Brian Kuzma - JPMorgan

Okay. And is that in your list of assets that are available for sale in terms of liquidity long-term?

Gil Goodrich

Potentially, obviously, in our mind, and certainly, as it would apply Bethany-Longstreet was a core block for us. It's way too early for us to be doing anything relative to that. We would want to get into development, see what kind of potential in terms of inventory enhancement and to the 2P reserve we think is there before we would even consider something relative to that.

Brian Kuzma - JPMorgan

Okay. And then at Bethune, have you guys written-off that early altogether for the James Lime?

Gil Goodrich

No, it's too early. Rob mentioned the well is inferior. And I said I think that we have seen somewhat mixed results. We've had a couple of mechanical issues on a well or twos thus far that we can't quite determine the impact of that. This well is still early in its flow back but clearly it's discouraging to us.

That said, Bethune is a fairly big block. I think it's about 8700 acres gross, something like that. Bethune has worked quite well for us with the Travis Peak. So we will continue to be drilling Travis Peak wells, which will increase our data points relative to the James and we'll be kind of doing some postmortem work here to get arms around what provides that wells inferior performance thus far.

So, we are clearly not to the point of the writing-off. That being said, it was never in our inventory or the inventory chart or the 2P or 3P reserve potentially we've talked in the first place.

Brian Kuzma - JPMorgan

Okay. And then my final question was just, as you look out in 2008, you guys have I think nine or 10 rigs around running. Where do you guys see those rigs at throughout 2008?

Gil Goodrich

Yeah. Again I hate to keep referring to this management presentation on the website but as you know we have an inventory chart, I think it's page 18 that really breaks out where our current estimate of those wells will be drilled about 40% which is at Angelina River, again 30 Travis Peak and 20 James Lime horizontal. I mean that's always a fluid number in allocation but that's as good as we can predict right now.

Brian Kuzma - JPMorgan

I got it. Okay. Thanks, guys.

Gil Goodrich

Thank you, Brian.

Operator

Your next question comes from the line of Robert Lynd with Simons and Company. Please proceed.

Robert Lynd - Simons and Company

Good morning.

Gil Goodrich

Hi, Lynd.

Robert Lynd - Simons and Company

I wanted to talk a little bit more about North Louisiana and I guess specifically at Bethany-Longstreet, and you've been trying several different development and completion techniques here be it horizontal, deep, vertical or dual-completions. Is this decision being made before you spud the well or after you drilled an initial pilot hole or do you know have a better feel towards which technique to apply for specific area within that field?

Gil Goodrich

Yes. Well, Robert, it's a good question actually. Certainly when we are drilling a vertical well and we have expectations to seek certain Hosston sands that -- the majority of the wells that we've drilled have been -- have had [shortcut] drills with a dual strength of tubing, one to produce in Cotton Valley and the produce in the Hosston. And the benefit of that is to minimize the water-loading that occurs on the backside or the Hosston side.

So more of our wells are being completed that way, although occasionally, we'll see the benefit of just doing running one string of tubing for the Cotton Valley and slowing up the casing side. So that decision is tentatively made ahead of time when we drill the vertical wells.

We are not drilling any vertical wells and then determining whether to go horizontal. We're setting up that plan ahead of time to drill horizontally. In essence, we would do as much well control as we have, you can pretty much nail where the Davis sand or the Taylor sand in particular is before you drill your horizontal well. And of course we've only drill two horizontal, actually the second, is being drilled right now.

So ahead of time, we're able to predict that and obviously, we decided internally to take the James Cook number one down to test and see the Haynesville ahead of time.

Robert Lynd - Simons and Company

Okay so I guess, between, if you have well control or you see a goods thick Davis number then you automatically, well, you plan a horizontal kind of between them?

Robert Turnham

Yeah, I mean, what we are proactively choosing when and when not to drill vertically versus horizontally, we would like to continue to see results from our horizontals wells before just totally converting to a horizontal Cotton Valley play. Again, this is kind of the second well, the first one, obviously worked very well and we're certainly optimistic on the second well. But again, repeatability of that versus duly completing vertical wells, we just needed some history before we just set out. The way you maximize the value of the field is clearly, if it works across the board, will be to drill horizontal Cotton Valley wells and vertical much more shallow kind of Hosston wells. It is much cheaper to drill a Hosston vertical well than to drill a duly completed well. So, again its kind of, a little bit too early to drop the Cotton Valley vertical program. We need a little more history and some data points but that would be the optimum development plan.

Robert Lynd - Simons and Company

I guess, just a final question follow up. How do you budget for that? Is the budget sort of set for, the area or the field and then, I guess when you use up the allocation, you're done for the area or is it fluid to where you believe you can drill more horizontals, you apply little bit more capital to the field?

Gil Goodrich

Yes, it is a fluid situation, you'd be surprised though at how little the budget moves in that and basically you have your rigs running everyday of the year and you have 9 rigs running 365 days. So those costs, whether your drilling horizontally or vertically, are being incurred. The difference would be obviously you drilled less wells if you are drilling horizontally because it’s a longer process and you might have a little more completion dollars in that you are putting on bigger fracs. But the variability if you would have to just go fully horizontally versus fully vertically is not as big as you would think. So certainly a fluid situation and we will just adapt as we go, but certainly still comfortable that the budget that we put out there, although it is preliminarily out there we are confident that we can hit that.

Robert Lynd - Simons and Company

Okay thanks. That’s helpful and that’s all that I had.

Gil Goodrich

Okay.

Operator

(Operator Instructions). Your next question will come from the line of Kim Pacanovsky with Ferris, Baker Watts. Please proceed

Kim Pacanovsky - Ferris, Baker Watts

Good morning everybody.

Robert Turnham

Hi Kim.

Kim Pacanovsky - Ferris, Baker Watts

As I look, I am going to refer to your presentation now. As I look at this map of Bethany-Longstreet, it looks like since the last map you had out, Chesapeake has drilled Bossier horizontal just north of that little piece of your acreage, that kind of juts of into their acreage?

Gil Goodrich

That is correct Kim. Good morning, this is Gil.

Kim Pacanovsky - Ferris, Baker Watts

Do you have any information or are your hearing anything on that well in particular since it is just located adjacent to your property?

Gil Goodrich

We are Kim and since its at least second, if not third hand, I would rather not say what it is but I can tell you that what we see and are hearing is certainly very positive and very encouraging.

Kim Pacanovsky - Ferris, Baker Watts

Okay good. And again looking at the map, on the eastern portion of your acreage, the block that is north of you and just east of [Quebec], there is no ownership attributed to that on the map, and also just that huge block of acreage to the east of you, who owns all that acreage?

Gil Goodrich

I'm not sure. I don't have that map in front of me, so just because we do not have a color does not mean it's not leased to somebody.

Kim Pacanovsky - Ferris, Baker Watts

Right.

Gil Goodrich

And there are other players in the area.

Kim Pacanovsky - Ferris, Baker Watts

Yeah, I guess the question is, is this that somebody doing anything in Bossier?

Gil Goodrich

We have not seen any other activity in that immediate area other than what you see on that map.

Kim Pacanovsky - Ferris, Baker Watts

Okay.

Gil Goodrich

And as activity permits come through and get reported with the state of Louisiana and activity takes place, it is public information that we can rely on as state information we will add that to the map.

Kim Pacanovsky - Ferris, Baker Watts

Okay. And did you mention anything to the south of you, have you heard anything to the south of Bossier?

Gil Goodrich

Literally, 20 minutes before go in this call I was informed of a well again secondhand, so I hate to say anything about it. But a well was drilled southwest in DeSoto Parish vertically through the Haynesville.

Kim Pacanovsky - Ferris, Baker Watts

Okay. And let's say changing subject to Champe Graham 5-H, were there any technical difficulties on that well. I though that was spud in early January, I guess like you are saying you are 60 days away?

Gil Goodrich

60 days away, Kim from being in a position to really report results.

Kim Pacanovsky - Ferris, Baker Watts

Okay.

Gil Goodrich

We have experienced some delays, but generally speaking, we are on path to be in a position to report results when we originally thought.

Kim Pacanovsky - Ferris, Baker Watts

Okay, great. And on the cost side, on the LOE side, your guidance is a little bit higher than where your exit rate for December '07 was. And I assume that's just because the disposal facilities are not in place until the third quarter and you are increasing production there. But looking at the third quarter and the fourth quarter of '08, what do you kind of targeting to get to for LOE?

David Looney

Yeah, Kim, this is David. I mean you are certainly correct in terms of what you said that we put out there for the guidance. We say all and when you include the work-over cost that we are looking at somewhere between $1.25 to $1.45, certainly the third quarter was better as we sort of discussed during the conversation, a lot of that can be attributed to the fact that the Beckville Field has just gone into operation with its low-pressure gathering system which had the impact of reducing the cost significantly.

And we have this increase in production coming from the Angelina River area where we have been very active and we really don't have what we would consider to be good adequate facilities there. So I think as Gil referenced, it might be a little spotty in terms of some of the improvement one quarter and then the next quarter may not improve or maybe flat out or slightly up or something like that. But I think as we loot out, I think somewhere between a $1 and $1.25 is where we are likely to wind up for most of 2008. And that's a pretty wide range but I think that's what we are dealing with at this moment.

Kim Pacanovsky - Ferris, Baker Watts

Okay. And just a nitpicky kind of question, where do you expect the share count to be in the first quarter?

David Looney

Don't really expect much, I mean certainly what we are going to be showing at year end when we file the case, it should be about where we are in the first quarter.

Gil Goodrich

I would just add Ken a global comment for everyone. And as a reminder that included in the outstanding shares is approximately 3.1 million share, that's under a share lending agreement with Bear Stearns, associated with the convertible notes we have outstanding on redemption of conversion that 3.1 million shares comes back to us. But they are out there in the trading currently.

And then secondly obviously, the capped call option that we purchased in association with the December equity offering is kind of a sliding band that at the termination of both contract have the potential depending on where our share price is to return about 1.6 million shares back to us as well in 18 months.

Kim Pacanovsky - Ferris, Baker Watts

Okay.

Gil Goodrich

So, those are just data points. Again one should keep in mind, I know it's a little cumbersome to keep that calculation going but those are I think pretty important numbers from our internal perspective, an insider perspective relative to our ultimate share count down the road.

Kim Pacanovsky - Ferris, Baker Watts

Okay.

Robert Turnham

Our year end Kim is right at about 31.5 million shares, if you back out those 3 million shares Gil was talking about under share lending agreement.

Kim Pacanovsky - Ferris, Baker Watts

Okay, great. All right. Thanks guys. I look forward to seeing what '08 has for. Thank you.

Gil Goodrich

Thank you.

Operator

Your next question is from the line of Richard Tullis of Capital One Southcoast. Please proceed.

Richard Tullis - Capital One Southcoast

Good morning.

Gil Goodrich

Hi, Richard.

Richard Tullis - Capital One Southcoast

Hi. What's the cost on the Mitchell and LB Mast wells?

Gil Goodrich

Well, we don't normally get into specific well cost. I think that on the Mitchell, we were generally AFE in that well at about $5.5 million as a Cotton Valley horizontal. I think give or take a reasonable range, we came in fairly close to that. And down Angelina River area we kind of estimate those wells at $3.5 million to $4 million I would say, of what we've seen so far is still a pretty fair estimate.

Richard Tullis - Capital One Southcoast

Okay. What do you see in drill cost have you had any rig contracts renewed recently or up for renewal.

Gil Goodrich

Yes, I think we've said or may have said on our last call that we renewed contracts on five wells in the second half last year. I guess maybe going back to June actually of last year the blended average of those five renewed contract is 15,500 a day and we've got three more contracts coming up in June, July and August of this year and obviously difficult to say exactly where we will be at that point in time given where gas prices are today, but if we're in a position to renew those today they would likely be right on the same range at 15.5.

Richard Tullis - Capital One Southcoast

Okay.

Robert Turnham

Richard, our blended average right now was about 18.5 a day, which down about $3000 a day from a year or so ago.

Richard Tullis - Capital One Southcoast

Okay.

Gil Goodrich

I might just to add that where we really have our most optimism is on the completion side. We said not too long ago that we've renewed our contracts for 2008 on five separate completion services, the biggest one being frac stimulation and collectively those were down very, very significantly but we are expecting as much as 15% overall costs savings per well on a rate basis in 2008.

Richard Tullis - Capital One Southcoast

Excellent. Are you guys doing much with the surgical fracs anymore with the vertical wells?

Gil Goodrich

We are doing at some -- it really depends on the application, but yes, we are continuing to use it, it unfortunately as we've said in prior calls it does not lend itself yet to kind of across the board use, but depending on the specific location of certain zones that we want to stimulate relative to other zones we are using it, particularly in the Hosston, the Travis Peak side.

Richard Tullis - Capital One Southcoast

Okay. What's the LB Mast well producing right now?

Gil Goodrich

Well, with 260 wells producing, we don’t get in to talk about one well. What we'll say is, that well is performing at our expectation and it's very early. I think Rob said the IP was 8 million a day. We are very, very early on and it's doing quite well.

Richard Tullis - Capital One Southcoast

Okay, good, very good. That's all I have today. Thanks, guys.

Robert Turnham

Thank you.

Operator

Your next question is from the line of Ron Mills with Johnson Rice. Please proceed.

Ron Mills - Johnson Rice

Believe it or not, I have a couple questions.

Gil Goodrich

Beautiful.

Ron Mills - Johnson Rice

On the reserve bookings, you mentioned you have the seven proved developed 20-acre locations. Do you have any 20-acre PUDs and all in your reserve report?

Gil Goodrich

No, we didn’t Ron. All our PUDs are on 40 acre spacing.

Ron Mills - Johnson Rice

As you look our for 2008 how many -- if you drilled seven 20 acres spaced well last year, how much do you think you will end up drilling this year across the couple do you expect drilling in Southeast portion of north Minden and would that be enough combined with production initiative. Potentially can you show some bookings either at mid-year or year-end?

Gil Goodrich

Yeah, Ron, this is Bill. As you look at our map, we really are so far away from any kind of necessity for drilling wells on 20 acres spacing, the seven that we drilled this past year were done specifically for research and development purposes to try to understand what the ultimate potential of drilling our acreage position down as far as 20s. That process in our minds is largely accomplished. In other words, we're confident based on all the data we've got and everything we've seen thus far is to ultimately to fully develop our acreage position at Minden, in fact we will need to drill on 20-acre spacing. That being said, we are still in some cases drilling 320-acres apart from each other.

So we will continue, I would say somewhat sporadically to drill 20-acre spaced wells just to continue that information flow. And we may and we are a long way from next year, but we may depending on those results start asking for some 20-acre space PUDs. But that being said, we're still largely an undeveloped company and really don't have the necessity of even asking for 20-acre spacing to just increase the number of development locations, which is not really an objective for us.

Ron Mills - Johnson Rice

Right, and this would be reserved for upside anyway. The follow-on to that, would then be, given to largely undeveloped portion of our acreage. Are you still drilling some wells just to hold units or how do you look from an acreage and lease exploration?

Gil Goodrich

Yeah, I would say that, as to Minden and Beckville, we're at great shape and effectively done, South Henderson we're effectively done, Bethany-Longstreet, I'll remind everyone as a farm-out, where we are required to drill one well every 120 days, or we're got to drill four wells a year. I think Rob said we drilled some like eight last quarter. So we're clearly eclipsing that, but by doing that we keep the entire 29,000 acres intact. We drilled I think 33, 34 wells in the field so we are earning around those wells, but obviously in very good shape there.

And place where we probably have the biggest need and where we are very active is obviously at Angelina River because that is still largely acreage. We are getting as we've said a concentration of activity in the Cotton South area and then up at Cotton, we've got at least 10 wells planned up there this year. So we don't see anything that's really a critical time line for us on any of our acreage as we sit here today.

Robert Turnham

And Ron I might add, if you see our acreage count go down any which we are not sitting here projecting that, it could be on some of the [fringes] acreage that we had not included in our drilling inventory and accounting as a perspective.

Ron Mills - Johnson Rice

Okay, great. And then I'll take the bait on the financing options you're looking at, though you've mentioned twice as being non-core sales. Following the sales of south Louisiana last year, what areas would you all be looking to or be considering non-core as potential divestiture candidates?

Gil Goodrich

Well, there are some acreage positions that we got that are not part of our bigger blocks and I would characterize our bigger blocks, Ron, as Beckville, Minden, Bethany-Longstreet so that leave some others. And Angelina River of course is still an emerging place, so that really would not be up on the table. And I don't want to point you or any one else to something specific we are going to go do, we are just saying that as our activity increases and the maturity of our both core and non-core areas improves, our options and flexibility for peeling off some of that increases and we are confident that as we move forward those two opportunities are going to improve.

Robert Turnham

And, Ron, just another thing to add, when you look at the number of locations to drill and once you just say the Haynesville pans out that just adds another layer of potential activity. The present value of the well that you are drilling in these non-core areas because you're having to scale back in those areas is certainly diminished which would be another reason why you may monetize something that's not really a part of your short-term or intermediate term development plans because you have prioritize the areas in which you want to be drilling over the next three years.

Ron Mills - Johnson Rice

Okay, great. Then lastly just if I am looking at it correctly that once you get some SWC systems in place and low-pressure gathering systems in place in some portions of Angelina River and those costs increase or decrease, the economics get benefited quite bit. But even without that, is there a reason for some of increased focused on that area because those wells have shown to be, shown some better economic returns at the higher costs structure?

Gil Goodrich

Clearly, Ron, both Travis Peak as we said, very encouraged with what we have seen thus far in the James and the Travis Peak results have been marginally to the upside on economics and the James has the potential to be very significant to the upside. So that's why we have put an emphasis there, as Rob said I think 40% of our budget allocated there. So, clearly something that we are going to be very aggressive with this year.

Ron Mills - Johnson Rice

Okay. Great. Thank you, guys.

Gil Goodrich

Thanks.

Operator

Your next question is from the line of Monroe Helm with CM Energy Partners. Please proceed.

Monroe Helm - CM Energy Partners

Hi, thanks. Two, three questions, and I apologize I missed the first of the call, but can you say what the debt level was at the end of the year, and what the components of total debt were?

David Looney

Yeah. Monroe, it's David Looney.

Monroe Helm - CM Energy Partners

Yeah.

David Looney

We had obviously $175 million in senior convertible notes and we had $40.5 million outstanding on the bank revolver.

Monroe Helm - CM Energy Partners

Okay. And the borrowing base was $75 million?

David Looney

Borrowing base, it gets a little bit confusing if you talk about year end versus after year end. At yearend technically the borrowing base was $170 million.

Monroe Helm - CM Energy Partners

All right.

David Looney

As we mentioned in our earnings release last night, the borrowing base once we entered into the second lien term loan which we did in January of this year, the borrowing base is reduced by definition to $142.5 million, of course after we reentered into the second lien term loan we paid off, the bank revolver down to zero.

Monroe Helm - CM Energy Partners

Right.

David Looney

And the other comment I would make here is of course, we are going to have a borrowing base redetermination very shortly after we deliver the new reserve report to the banks and we would expect to have that new borrowing base in place probably within the next three, four weeks.

Monroe Helm - CM Energy Partners

Okay. When I look at reserve numbers at the end of the year, will they use updated pricing to determine you new borrowing base or will they use the year end pricing that like the SEC does in their case?

David Looney

Well, the banks do two things. They use their own specific price tags, which generally speaking are a little bit lower than where the current market or NYMEX levels would be. However, I would say based on the price that was used in the reserve before, which was $6.80, if I'm not mistaken, our lease bank actually starts off at something right around $6.75 and they step down. The big difference to that when you look at the banks and the way they approach it is, they really include the benefit from our hedge position and our financial hedges in their calculations which we are not allowed to do in the SEC reserve report.

Monroe Helm - CM Energy Partners

Okay. The second question is, can you give more detail on your year end reserve numbers? Can you break it up? It looks to me, like, I guess if you had 16 bs of production then 358 bs proved at the end of the year you had a 199 bs, how much of that was added to the drill bit, how much of that could have been from price revisions?

Gil Goodrich

Yeah. Essentially, all of that was from the drill bit. I mean everything that we add that was from the drill bit, there was a little bit as price revision and this last year, it was actually even lower, but I don’t have a specific breakout how much that was.

Monroe Helm - CM Energy Partners

Okay. And then the last question was, in your most recent presentation, you gave an estimate of potential inventory value per share of $49.26, I just wanted to know how you came up with that number?

Robert Turnham

Yes. Monroe, this is Rob. It's footnoted on there and that is really a back of an envelope estimate and a $1 per Mcf in the ground if you just-- of your proved reserves, probable and possible. I would not take that to the bank, it is just one of those metrics out there that people look at to try to just get some idea of what the inventory value would be.

Monroe Helm - CM Energy Partners

Okay.

Robert Turnham

Another way to look at it would be put on the proved reserves a typical kind of transaction metric of $2.50 to $3 in there and then just allocate some value to the probable reserves.

Monroe Helm - CM Energy Partners

And what were you showing or what number you are using for probables and possibles

Robert Turnham

Well, in the dollar per Mcf analysis which is in the footnote and that’s everything at a dollar, if it did improved at 2.50 to 3, you shrink it down to $0.50 in them or something along those lines. But again, those are just two kinds of value equation of techniques to just kind of get a feel for what your inventories were. But that may or may not represent what you could actually get for.

Monroe Helm - CM Energy Partners

Right. I am still not clear on, why you think that 2P and 3P reserves are. I didn’t see a footnote here in the copy of the presentation?

David Looney

I believe its $7 dollar per Mcf or for all of the reserves, I don’t have the presentation in front me.

Monroe Helm - CM Energy Partners

Okay.

David Looney

Which would include 1P, 2P and 3P.

Monroe Helm - CM Energy Partners

Okay. And that was based on your midyear, improved reserved number 302 days I am sure?

David Looney

Correct.

Monroe Helm - CM Energy Partners

Okay. Thanks for help.

Robert Turnham

You're welcome.

Operator

At this time, there are no more questions in the queue. I would now like to turn the presentation back over to Mr. Gil Goodrich for any closing remarks.

Gil Goodrich

Thank you very much everyone for participating. We look forward to visiting with you again, when we report first quarter 2008. Thanks.

Operator

Ladies and gentlemen, this concludes your presentation. You may now disconnect and have a great day.

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Source: Goodrich Petroleum Inc.Q4 2007 Earnings Call Transcript
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