Ardagh Group S.A.
Q4 2007 Earnings Call Transcript

Published: 1 Apr 2008

[Operator:]

Greetings and welcome to the Arena Resources 2007 fourth quarter and year-end financial and operating results. At this time, all participants are in a listen-only mode and a brief question-and-answer session will follow the formal presentation. (Operator Instructions) As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Mr. Tim Rochford, CEO for Arena Resources.

[Lloyd (“Tim”) Rochford:]

Thank you, Operator. And again, we’d like to welcome all of our listeners to our fourth quarter and year-end 2007 financial and operations conference call. Again, my name is Tim Rochford, Chief Executive Officer. Joining me this morning is Phil Terry, our President and Chief Operating Officer, as well as Randy Broaddrick, our Chief Financial Officer. Before we begin, I would like to make reference that any forward looking statements which may be made during this call are within the meaning of the Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995. For a complete explanation, I would refer you to our release issued this morning. If you do not have a copy of that release, one will be posted on the company’s website at www.arenaresourcesinc.com. Now today, we’ll cover the financials and operations for the fourth quarter and 12-months ending 2007. We’re going to also review the results and give you some insight as it relates to the first quarter and on through 2008. And at the conclusion of our overview, we’ll open up for any questions you may have. Now at this time, I’m going to ask Randy Broaddrick, our Chief Financial Officer, to review the financial points.

[William Randall (“Randy”) Broaddrick:]

Thank you, Tim. I will be reviewing our financial results for the 3- and 12-months ended December 31, 2007. For the three months ended December 31, 2007, the company had oil and gas revenues of $35.1 million and net income of $9.4 million as compared to revenues of $16.5 million and net income of $5.2 million in the fourth quarter of 2006. This represents an increase of 113% in revenues and 80% in net income. For the 12-months ended December 31, 2007, the company had oil and gas revenues of $100.1 million and net income of $34.4 million, as compared to revenues of $59.7 million and net income of $23.2 million in 2006. This represents an increase of 67% in revenues and 48% in net income. On a diluted basis, the earnings per share for the 3-months ended December 31, 2007, were $0.26 or $0.29 per share excluding a $1 million net of tax non-cash charge for share-based compensation, as compared to $0.17 in 2006. For the 12-months ended December 31, 2007, earnings per diluted share were $1.02 or $1.10 per share excluding a $2.5 million net of tax non-cash charge for share-based compensation, as compared to $0.77 in 2006. Net cash flow from operations adjusting for changes in operating assets and liabilities for the 3- and 12-month periods ending December 31, 2007, were $27.1 million or $0.76 per fully diluted share, and $77.8 million or $2.31 per fully diluted share, compared to $12.4 million or $0.40 per fully diluted share and $46.9 million or $1.56 per fully diluted share in 2006. Additionally, we exceeded $257 million in shareholder’s equity. I’ll now present a little more detailed information about certain line items beginning with our total production costs. We have seen higher production costs for the 3-months and the year ended December 31, 2007, when compared to the same period in 2006. This increase is the result of a variety of factors, including increased rates for essentially all of our services, materials and equipment, and particularly labor. Additionally, we are still seeing increased trucking and contract labor costs for water disposal while we continue to wait for approval of permits to convert wells to water disposal wells. Some of the permits have been approved and some were completed. But the increased water hauling and disposal costs continued through the fourth quarter. Some of these costs will continue through the first and possibly into the second quarter, but we do not anticipate these costs to continue beyond that. We have also seen significant increases in our electrical service as most of the electrical generation in our areas of operations are affected by oil and gas prices. Lastly, we have seen oil and gas production taxes become a larger component of our overall cost of revenue. Most production taxes are based on values of oil and gas sold. So our production taxes have increased dramatically, particularly during the fourth quarter 2007. Looking forward, we anticipate our lease operating costs to be in the range of $7.50 to $8 per BOE and our oil and gas production taxes to be around $4.50-plus based on current commodity levels. That’s for 2008. Moving on to our depreciation, depletion and amortization, we do continue to see an increase in our DD&A for both the 3-months and year ended December 31, 2007, as compared to the same periods in 2006. In particular, we saw a significant increase in our DD&A per BOE during the fourth quarter. As has always been the case, depletion of our oil and gas properties is the primary contributor to our DD&A. A gradual increase in depletion costs is expected as we continue to develop our properties. This gradual increase is the result of our adding capitalized costs as we develop our properties and any future development costs as we add additional reserves. However, we saw a particularly noticeable increase for the fourth quarter 2007. One of the primary reasons behind this increase in the fourth quarter was the completion of multiple acquisitions during the quarter. With these acquisitions, we add our acquisition costs to the depletion base, as well as all future development costs related to the reserves added. Additionally, at the commodity price levels at which our reserve estimates were prepared, it is appropriate to include reserves for wells that would not have been considered economical at year-end 2006. However, these wells will cost the same amount to drill as similar wells with greater production potential. The effect of this is that the ratio of future development costs to add the reserves versus the amount of reserves added for these wells caused an increase in our depletion per BOE. For 2008, we anticipate an increase each quarter to ultimately average approximately $15 per BOE for the year, excluding any impact of any additional acquisitions throughout the year. Our depreciation expense will increase for 2008 as compared to 2007 and previous periods, primarily as a result of the company now owning the office buildings it occupies. While the increase will be considerable compared to similar expenses for previous periods, depletion will remain the dominating factor in our DD&A calculations. Moving on to G&A, our increases in general and administrative costs are the result of increasing payroll as we continue to add more new employees in order to sustain our growth, as well as significant increases in our stock-based compensation expense as we grant options in order to entice new employees as well as to retain both new and old employees. Management believes that this is necessary to continue to add quality personnel with the experience and knowledge that we need. Stock-based compensation increased from approximately $900,000 for 2006 to over $4.1 million for 2007. We anticipate a further increase in our stock-based compensation amount for 2008 as a result of the options granted during 2007, particularly those granted towards the end of the year. Additionally, any options granted during 2008 would cause further increases. Lastly, we do have one hedging component in place. The collar we have in place runs through year-end 2008. We had a realized loss in the quarter of approximately $579,000 after tax or $0.02 per diluted share. We also showed an unrealized loss of approximately $2.8 million after tax as other comprehensive loss, which does not affect our earnings. This is our only hedging component in place. Tim, I believe that covers all of my points.

[Lloyd (“Tim”) Rochford:]

Thank you, Randy. Good job. 2007 was truly a year of transition for Arena. With the addition of key in-house personnel and our second company-owned drilling rig, we have now directed our energy towards development rather than acquisition. This has resulted in record production, revenues, earnings and cash flow. In the fourth quarter, we drilled 49 new wells, 48 of which were at the Fuhrman-Mascho and one of which was at the Y6 property in Fischer County, Texas. This brought the total of new wells drilled in 2007 to 134. In addition, we performed refracs on 37 existing wells and continued the improvements and the upgrades to our leasehold infrastructures. In the fourth quarter, our sales as a result of production were 441,632 barrels of oil equivalent. This is a 33% increase over same period in 2006 and a 9.5% increase over third quarter 2007. Our average net daily production increased to approximately 4,800 barrels equivalent per day. The average sales price per BOE received in the fourth quarter was $79.45. That is a 20% increase from the third quarter and a 59% increase from the fourth quarter 2006. For the 12-months ended December 31, 2007, our sales as a result of production were 1,566,627 barrels of oil equivalent. That’s a 47% increase over the prior year. The average sales price $63.89 as compared to $56.08 in 2006, another 14% increase. Our 2007 year-end proven reserves are 55.4 million barrels of oil equivalent, as compared to 43.1 million barrels of oil equivalent in 2006, a 32% increase when adjusted for 2007 oil and gas sales. PV-10 values increased to $1.982 billion, a 134% increase from 2006 using average prices of $88.89 per barrel and $8.74 per Mcf of natural gas. Our reserves are weighted on the oil side are approximately 86%, of which 36% is developed. Now, at this time, I’m going to ask Phil Terry, our President and Chief Operating Officer, to highlight some areas of activity and just give us a brief overview of operations.

[Phillip W. Terry:]

Thank you, Tim. I appreciate the opportunity to talk with you about the fourth quarter 2007 activity and the year 2007 in general. Tim has already spoken with you and given you information relative to the production for the fourth quarter. I will reiterate that we did see a nice increase in production during the quarter. On a total company basis, we produced about 437,000 barrels for the year. Our total production was just over 1.5 million barrels for the fourth quarter. It was a significant increase, about 33%. We closed 2007 fourth quarter averaging 4759 BOE per day. And for the year, we averaged 4306 for the total company. In 2006, we produced just over 1 million barrels, so there was a significant increase in production from 2006 to 2007. I will break that down further and relate that to activity in the field. As Tim mentioned earlier, we drilled 134 wells for the year, and taking that on a quarter-by-quarter basis, the first quarter was 28 total wells; the second, 29; the third, 28; the fourth, 49, for a total of 134, with 19 wells being drilled in December. So it’s obvious from that that you can see that the addition of the third rig accelerated our drilling and completion activity, and as a result of that, we’re seeing some nice increases in production. I will go now to the individual properties and try to break down some information for you as to the fourth quarter and 2007, beginning first of all with the Fuhrman-Mascho in Andrews County, Texas, which of course is our major property. In the fourth quarter, we drilled 48 wells. We completed 34 of those wells and 14 were in various stages of completion at year-end. Also in that third quarter, we refraced three wells. For the total 2007 at Fuhrman-Mascho, we drilled 133 wells, of which 119 were completed and of course, 14 waiting on completion. We also refraced 37 wells. For the total project since its inception in April 2005, at the close of 2007, we had drilled 256 wells and we had refraced 104 wells. I mentioned earlier the fourth quarter production at Fuhrman-Mascho was just over 351,000 barrels. That’s an average of 3823 net BOE per day. And in the year 2006, we produced 220,000-plus barrels, which was an average of 2421. So we increased from 2421 in 2006 to 3823 in 2007. To give you further insight, in December 2007, we produced 139,000-plus barrels or an average of 4499. Again, for the year, Fuhrman-Mascho in 2007 averaged 3368; 2006, 1840. So our increases are significant. We continue to see the production ramp up as we drill more wells. Thus far in the first quarter of 2008, provide you a little insight there, we have drilled 45 wells, of which 42 have been drilled and 3 are now drilling, and we’re in the process of completing the wells that were awaiting completion. I’ll talk with you about Fuhrman-Mascho reserves and the 2007 reserve report. The report for 2007 listed a PW-10 of 1.4 billion for all of Fuhrman-Mascho reserves. We had a total proved reserve count of 39,200,000 and change. That’s an increase of 42.6%. The proved developed producing component of our reserves was a little over 10 million barrels, that’s an increase of 65%. The crude developed non-producing was 732,000 barrels and that deserves some explanation. That actually is a decrease of 38% over last year. That takes into consideration the wells that were drilled in 2007 but not completed in 2007. We had 14 wells that fell into that category. It is our opinion, which differs from that of the third party engineering group, the 14 wells were treated very pessimistically. These 14 wells are in an area that we have previously talked to you about as being high reserves areas where we have both the Grayburg and San Andres present, and those wells historically have had cumulative recoveries in excess of 75,000 barrels per well. The engineering firm chose not to be that aggressive with these 14 wells. We did not have an opportunity to get all 14 of those on obviously. At the time the report was done, there was very little production information. In some cases, the wells were not completed, and as a result of that, they were treated very conservatively and very pessimistically in our opinion. The average well was, instead of being in the range of 75,000, which we anticipated and which we calculated in-house, those averages were in the 30s. So we feel like that history and time will demonstrate to us, just as we felt all along, that these wells in this good reserve area will perform much better than predicted by the third party engineering group. The other components of our reserves, the proved undeveloped primary in the year ending 2007 was 16,758,000. That’s an increase of 96%. And I’ll break that down for you. We have a total of 517 PUDs booked as of 12/31/2007. Of those, 16 are 40-acre PUDs; 192 are 20-acre PUDs; and 309 are 10-acre PUDs. And if my math is right, that should total 517. That yields an average per PUD of 32,400 barrels, which again we feel is very, very conservative. It is not representative of what we have seen in the past, and one of the things that happened to us is that the third party engineering group again took the average for the entire field and applied that average basically to the PUDs, as they carried them forward into 2008. We feel like that the average will be significantly higher because of the fact that a great portion of our PUDs to be drilled in 2008 are indeed in the higher reserve area and our production increase that we have seen so far in 2008 verifies exactly what I just said. We’ve seen significant improvements in our production in the fourth quarter of 2007 and in the first quarter of 2008. And that is reflective of the fact that these good wells are performing as we predicted and we anticipate that we’ll be able to get these reserves increased significantly at year end 2008. Our proved undeveloped secondary component remained relatively unchanged from 2006 because we have not initiated water floods; that’s just slightly over 9.3 million barrels. Our Yates proved developed non-producing component remained at 2,283,000 and that again is unchanged because we have not begun to do our Yates development projects yet. I’ll make a comment also about PDP and the PDP component of our reserves; that again was an area where we accepted the reserve report of the third party engineering group, but we did not agree with it. The initial rate on an average well was adjusted to more closely match the production growth. We didn’t have a significant problem with that because we did need to adjust and that adjustment wound up being adjusting downward from 125 barrels BOE per day net per well to an average of about 117 BOE net per well, which equates to about 150 barrels a day gross. In the past, in our better areas, we’ve seen wells that will come in and average 170 to 200. We indeed are seeing that in our 2008 activity in the areas of good reserves and good production growth. So as a result of that, PDP was adjusted somewhat. But we continue to feel like based on what we are seeing so far that PDP component will prove to be very conservative. Again, I talked about PDNP and also about PUD primary. I’ll make one other comment about PUD primary; we were not able to book as many 10-acre PUDs as we had hoped for. In earlier conversations on the conference calls and in various seminars, we have indicated that we felt like we were going to be very aggressive and our third party group would be equally as aggressive in booking 10-acre PUDs. We did book 309 10-acres. However, because we were not able to drill as many 10-acre PUDs as we had hoped for, the third party engineering group would not book 10-acre reserves in some areas that did not have 10-acre history. So as a result of that, we have significant 10-acre PUDs to add as we move forward in 2008, 2009 and 2010. The other thing is that slowed our 10-acre development program in 2007 was the fact that we had to wait on the Texas Railroad Commission to rule on our request to change the field rule spacing between the wells. We did accomplish that and the field rules were changed, but it was late in the year, and matter of fact, it was in the fourth quarter when you see that our drilling activity increased from 28 to 49 and our production increased as a result. We had a very strong fourth quarter. We’re having a strong first quarter 2008. And we feel very, very good about where we are going with the Fuhrman-Mascho project. Again, I’ll lead you into 2008 and just to give some insight as to what we plan to do in 2008. We’re seeing excellent production, significant increases over the fourth quarter of 2007. We have completed those 14 wells that were in the PDNP category at the end of 12/31/07 and the results have been excellent. We’re extremely pleased. Our production growth is quite significant. In 2008, we will drill 220 PUDs San Andres wells. We budgeted $121 million to do that. It should be noted that the largest portion of those PUDs will be drilled in the areas of higher average cumulative per well. We are now drilling well number 45 in this first quarter, which puts us right on target to drill our budgeted 55 wells each quarter. We will also drill two deeper Clearfork zone wells. We budgeted $1.5 million to do that. The first of those wells will start in late March this year. We look forward to that. The positive results from that drilling would be extremely significant to our project, would add another element to the development in the Fuhrman-Mascho, being San Andres, Clearfork and Yates. So we’re certainly looking forward to drilling that well and getting positive results. We anticipate refracing 40 wells in 2008; thus far we have refraced 7 wells and these refracs are in areas also that are the high reserve areas. What we found is that the previous owner-operators in many cases did not open all of the Grayburg or all of the San Andres; we’ve seen excellent results from the 7 wells we have drilled thus far. I also should note that the third party engineering group was quite harsh on our frac results last year, and even though we’ve demonstrated in these high reserve areas that they deserve what we thought were higher reserve basis. We’re just going to have to prove it to them based on refracs going forward, but we’re very positive about the results. We’re excited about the 40 wells that we’re going to refrac this year. Also at Fuhrman-Mascho, we plan on spending about $12 million for infrastructure improvements. That will include additions to tank batteries, additions to water flood stations, flow lines, heater treaters, roads, so forth and so on. As you can imagine, drilling 220 wells per year requires a tremendous amount of work to keep your facilities in place. So that $12 million will go to assuring that we can adequately treat and handle the production that we are obtaining. I mentioned water flooding. We hope to have all of our information together − information being engineering, geology, and production data − we hope to have all of that together. We’re 95% complete with that. We will be ready then to submit that to the Texas Railroad Commission. At the current time we’re also establishing a list of the royalty owners associated with these proposed projects. And once we have those royalty owners identified, we will go forward to the Commission and our time table says that we hope to be in front of the Commission by the start of the third quarter, by around July 1. That will, of course, allow us to start converting wells to injection. We already have converted some wells, which as Randy earlier alluded to, will help us with our LOE in that we will not have to haul water. But our real water flood projects will not begin until probably the first quarter of 2009 in terms of getting significant water in the ground. But that, of course, adds another significant component to our cash flow when those water floods start to respond. Our Yates project will shift into high gear this year in the second half of the year. We have signed all of the agreements with Aspen. The pipeline is to be completed, anticipated sometime during the first quarter of 2009 and our activity will parallel the activity of the pipeline. We have begun already to work on wells to assure that they are mechanically sound. And we identify those and then move on to others. We’ve worked on 20 to 30 wells; I can’t recall the exact number. But by the end of this year, we will have identified a number of wells that will be then ready to perforate, acidize and frac and then turn them right down the line at the time the line is ready to accept gas. We’ve targeted 90 completions during this year, spending $15.75 million. Moving to another Texas project, the Y6 lease, we drilled 1 PUD well in 2007, but we were not able to complete it. We’re now in the process of completing and testing that well. We’ve tested some lower intervals, which have not produced in the area; they are not the targeted intervals. But we have tested those and we will continue to test, and we’ll next test the upper intervals, which appear certainly to be as good or better than the offsetting production. We drilled another PUD well in the first quarter of 2008, it is waiting on completion. In 2008, we will drill an additional 2 PUD wells on the south part of this property. We’ve budgeted $1 million for those wells, a total of $1 million. We will convert to 3 wells on the south side of this property, which has never been flooded, we anticipate it will respond nicely to water injection and we’ve targeted $800,000 for that. In addition, we will perform work-overs in the form of cleanouts and refracs on 4 wells. The total for that is a $400,000 expenditure. So we continue to be very excited obviously about Fuhrman-Mascho; we also are equally excited about Y6 and the potential that we have in the state of Texas. Moving on into New Mexico, I’ll first talk about the East Hobbs, San Andres unit. East Hobbs continues to be one of our major properties. In 2007, we did not drill any PUD wells there. I think all of you are aware of the fact that we did have some production problems that were associated with high line pressures caused by our gas purchaser’s line being packed and not able to reduce pressure on that. We’ve waited on them for most of the year to get a new gas line in place. That gas line finally was put in place in the latter part of the fourth quarter. We put our compressor in place then and started production. We have seen a nice increase in that production as a result of that compression. But as a result of those lower producing rates, the third party engineering group chose to reduce the proved developed producing reserves to reflect the decrease in production. Obviously, we did not feel that that was justified. In water floods, it’s very rare to reduce the PDP component unless you see a really long-term decrease in production. However, in this particular case, the third party said that ‘we haven’t had the benefit of enough time to see production increase after you had gotten your compressor on line.’ We’ve increased production about 50 barrels a day since that compressor has come on. And it will continue to increase, we feel. So, what the third party group did do was to take the differences and the extrapolated curves from 2006, compare those to 2007, and any differences in those two curves were then shifted to proved developed non-producing reserves. So the reserves are still on the books, they were just changed in category. Again, we didn’t agree with that, but for sake of argument, we had to accept it. In 2008 we will convert up to five additional wells to injection. We are now completing our geological and reservoir studies to determine the five best places to convert, and that work will be done in quarters two and three, and that should reflect in terms of an increase in production, late in 2008, early 2009. We also anticipate drilling 6 PUD wells in 2008. These wells are in areas of high reserves potential and we have about $2.7 million budgeted for those wells. Again, East Hobbs is a major property for us and we will continue to devote time and capital expenditures to that project to enhance it. Also in New Mexico, the North Benson Queen unit has shown significant improvement this year. Just in orders of magnitude, in 2006, the property produced 11,900 barrels of oil. In 2007, it produced 19,768 barrels. That increase is due to just a small amount of work to a very few wells. We cleaned out a few wells and fraced some of those wells. And at the same time we were able to construct a water line from a third party source for floodwater. And that water has been transmitted and transported to our North Benson Queen and is now being injected. So we’re seeing increases in production as a result of the wells being worked on and the increased water injection. 2008 calls for us to drill 12 PUD wells. We anticipate drilling those wells in quarters two and four. We budgeted $5.4 million for that work. We have 10 permits now being processed by the Bureau of Land Management, so we anticipate that we will receive permits to drill within the next 30 days, which was prescribed by BLM and we will then schedule rigs and begin drilling. In addition to the drilling in 2008, we’ll refrac 15 wells. That will be done in quarters two, three and four at a cost of about $2.25 million. Again, North Benson Queen is a target of a great deal of activity and a capital commitment from us this year. It is a nice project and we anticipate it getting better. The Seven Rivers Queen unit continues to produce nicely. We had the same kind of problem at Seven Rivers as we did at East Hobbs in terms of the appraisal of the third party group. Proved develop reducing reserves were decreased by the third party group, because there was a period of time when production was curtailed. We were actually down for a while due to some electrical problems and also gas lines carried some extremely high pressures. But in spite of all that, our Seven Rivers production in 2007 was greater than it was in 2006. In 2006, we produced 63,500 barrels, in 2007, 67,609. But because of the periods of downtime, the third party appraisal was done in such a manner that it declined production based on that curtailment. Again, PDP went down as a result. But the third party group attached reserves in the PDP category equal to the difference between 2006 and 2007. We at Arena did not feel like that the PDP component should have been changed but again, we didn’t have the benefit of enough time to counter that argument. Other New Mexico properties include the acquisitions that we made in 2007. And as you’re aware, we made several such acquisitions. We’ve been very pleased with those properties. We obviously don’t have a great deal of history in terms of being in our inventory for great periods of time. But we have been able to increase production on just about all of them with very minimal work. In 2008, we plan on drilling 18 wells on those properties and that’s a total of 18 for all of the properties, and we’ll spend $6.75 million to do so. We’ll also refrac and rework 28 wells at a cost of $2.4 million and we’ll do additional infrastructure improvements. I might add that New Mexico has grown quite significantly in terms of our number of properties owned and operated and we continue to look for other opportunities, but we have some nice development work to do on the properties that we have in inventory, and also the ones that we just added to our inventory. In Oklahoma, our reserves on the Oklahoma properties basically reflected production. In most cases particularly the OMU which is the Ona Northwest Morrow unit, 2006 production was 17,700; 2007 was 14,350, which is relatively close to expectation, and it reflects the changes in production from one year to another. In 2008 on the OMU, we intend to finish the water line construction which is now under way and will be completed before the next month to six weeks. We also plan to drill 3 PUD wells in the year at a cost of about $1.5 million. We will anticipate that the drilling of those wells will coincide fairly closely with the time when we increase our water injection, which should result in increased rates of oil production. On our mid well water flood unit, the water line to that property is completed, and we will convert four wells to allow water injection to begin. The 4 wells will be converted probably in quarters two or three. We should see relatively quick response to that because of the Morrow sands and the nature of those sands. They do flood extremely well and they respond to water injection fairly quickly. We also anticipate drilling 2 PUD wells in 2008. The Hanes in 2007, we completed the well that was drilled in 2006 but not finished. That well was not commercially productive, but it is in a critical spot in terms of production based on conversions that can be done around it. Again, because of the mapping and studying that we’ve done, we feel like converting a well to water injection will result in moving oil to the surrounding producers in a very short period of time. The Hanes water system is in place and we will convert an additional well in quarter number two and three and spend about $125,000 to do that and move forward with our water flow project. At the Eva South Unit, or ESU, the production was close to prediction. We’re going to drill 2 PUD wells in 2008. We will also convert an additional well to water injection, which is the result of an engineering study that we’ve shown that there is a portion of the reservoir that has not yet been flooded. We anticipate ESU production to continue to move at a relatively flat rate of decline and should increase after converting the wells. ESU produced 27 barrels in 2007 compared to 31,000 in 2006. We have a sizable amount of activity in Oklahoma, but all of it has depended on the construction of the water line and that line is almost finished at this point. Finally, I’ll talk about Kansas. Our Kansas production was significantly lower in 2007 due to curtailments by the gas purchaser. We produced equivalent barrels of 25,600 in 2007 compared to 34,600 in 2006, and again the reason for that is there were long periods of no gas sales due to the curtailment by the gas purchaser. As a result of that, the third party engineering group was quite harsh in their treatment of PDP reserves and also in their treatment of PUD potential. The third party group essentially held to the opinion that as long as curtailments are in place, they couldn’t increase PDP back to previous levels. We feel like the curtailment problem has hopefully gone past its worst point. There is the potential, however, that it could reoccur. But we feel like that we will not experience the long periods of zero gas sales in 2008 as we did in 2007. That concludes my review of 2007, and also a projection of 2008 and I’ll turn it back to Tim.

[Lloyd (“Tim”) Rochford:]

Phil, thanks. Great overview. In summary, you can see that we’re going to be very busy this year. We are now drilling our 301st well at Fuhrman-Mascho lease since starting back in spring of 2005. In addition, we have refraced another 104 wells since starting back in the spring of 2005. Also as mentioned earlier, we have 3 rigs running now to our Fuhrman Mascho project. We’re well underway for our Yates development project. That’s going to be a great impact as we get further through this year and that pipeline construction starts to materialize and we start to prepare for production with the tests that we anticipate. We expect that year-end 2008 is going to offer some good impact as it relates to added reserve components from the Yates project. Most of our properties, not 100%, but most, 90-plus percent of our properties all have scheduled development and activity this year. Our previously announced CapEx budget is $218 million. We will drill over twice as many wells in 2008 as we did in 2007; 275 new wells companywide; 220 wells at Fuhrman-Mascho alone. That does not include any Yates recompletions. As discussed earlier the company has directed its energy and resources toward development. Our Fuhrman Mascho properties alone offer in excess of 1,600 additional locations of which less than a third have been booked as PUDs. And, yes, we will continue to look for acquisitions, particularly or specifically in areas that complement our current operations. Our credit facility is $150 million with a borrowing base of $100 million. We anticipate with year-end 2007 results that our borrowing base will be increased and we expect to see that in the near future. Now at this time, what I’m going to do is turn it back over to the Operator. It really concludes our overview. Operator, we’re going to open it up for any questions.

[Operator:]

Our first question is coming from David Heikkinen - Tudor, Pickering, Holt & Co.

[David Heikkinen:]

One question, it’s going to have to be a good one. The Yates gas potential and as you think about moving that forward, you have done a lot of mechanical integrity testing, can you tell us the number of well bores that are available for recompletion? Also can you tell us the timing of pipeline capacity and can you give us an indication of what the production rates are per well and what you would expect the production profile to look like from Yates gas?

[Phillip Terry:]

Yes, David, we have about 90 well bores that are currently shut in, and those wells are being systematically tested as we move forward. I mentioned in my comments about the Yates that we have worked on 20-plus of those wells to identify which ones are mechanically sound. It’s probably closer to 30; out of that group, only two have shown to lack integrity to move forward. We anticipate having at least 60 of those wells finished by the end of this year; finished being to do the pre-testing, and to be identified as sound well bores for Yates completions. And then our plan is to begin the final completion stages to coincide with the completion of the gas pipeline. That completion is scheduled now for the first quarter of 2009. We have had meetings with the Aspen personnel. They are currently buying right-of-way, they’re ordering pipe, they have the process moving along and they anticipate that they will be in a position to complete that line by the first quarter of 2009. Further to your question, we feel like that the average well out there has an initial potential anywhere from 100 Mcf per day to 300, and the average is probably about 150 or so. Some will be considerably better than that. But we feel like if you have an average of 200 Mcf per day, you’ll see a decrease of 30% to 40% for the first year, and then you’ll have a declining rate of 8% to 10% for the years after that. We anticipate that we will have some wells in our model particularly in the areas of the field that are higher structurally that will be considerably better than that. We’ve also targeted additional acreage in the area for acquisition of both San Andres and Yates rights and that we’ve been successful in picking up some additional acreage. So we’re very excited about the project. As far as timing is concerned, we feel like it will really kick into gear the fourth quarter of this year and the first quarter of 2009.

[Lloyd (“Tim”) Rochford:]

David, I believe too, just to add to that, is the overall capacity as I understand it now, Phil, with that 20-inch line, is it we’re looking at about 50 million feet?

[Phillip Terry:]

Yes, that’s correct. I’m sorry, David, I did not cover that point. The Aspen has the total capacity of 50 to 55 million cubic feet per day.

[Operator:]

Our next question is coming from Jeffrey Hayden - Pritchard Capital Partners.

[Jeffrey Hayden:]

Jumping to the Fuhrman-Mascho, with some more results, having drilled up some more of the good area as you call it, we’ve got the Greyburg as well as the San Andres, do you have a better sense of what percentage of your locations or what percentage of your acreage position right now you would classify as the really good stuff, which does give you the potential from both of those?

[Lloyd (“Tim”) Rochford:]

Jeff, let me add a little to that to begin with, and then I’ll also let Phil reflect on this. Keeping in mind that we now have north of 22,000 acres there; also as mentioned in our overview earlier, you know that we talked about exiting the fourth quarter averaging companywide about 4,800 barrels of oil. I’m happy to share with you now companywide that we’re averaging better than 6,000 barrels a day, and that’s due to the activity at Fuhrman-Mascho, and more in particular, as it relates to those 14 magical wells that we keep talking about and others in addition to that, that have been drilled and completed in this first quarter. So let me respond and say that we’re seeing not just better results, we’re seeing really great results, in our opinion. But beyond that, in terms of how much of the overall acreage we can anticipate that kind of performance in, we’re part of that curve, we’re still seeing how that’s going to turn out. But Phil, maybe you can add something to that as well?

[Phillip Terry:]

We have about between 45 and 50 wells that are in queue to be drilled in the remainder of this quarter and early in the second quarter. And those 45 to 50 wells are in that really good fairway of both of maximum Grayburg and maximum San Andres thickness and production potential. You grade slightly downward from that, as you move off the top of that structure and a little bit either west or east of that trend. But we have, I would say just as a guess that I can give you, we probably have five to 6,000 acres that are in that really, really, extremely good fairway. The wells that I identified that are in the better part of it will average over 75,000. Some have averaged in their history over 100,000 barrels per well, and then as you move slightly off those structures, you get wells that will make 60,000, 50,000 and so forth. But we have an inventory of 45 or 50 currently in queue, and the major portion of our 2008 activity would be targeted along those trends.

[Jeffrey Hayden:]

All right, great, I appreciate it.

[Operator:]

Our next question is coming from Mark Lear - Sidoti & Co.

[Mark Lear:]

Just to expand on the last question and you had mentioned you were targeting even deeper formation at Clearfork, I think you’d said. It looked like a drill and complete cost of about $750,000. Is there any an analogous production in the area to give you an idea of what kind of reserve adds you would see with those kinds of costs? And going back to the Grayburg as well in that area, what kind of production curves are you seeing initially from those wells?

[Lloyd (“Tim”) Rochford:]

Mark, to begin with, as it relates to the Clearfork, that is a deeper horizon as we’ve discussed, and, yes, it is more costly. I know that we’ve budgeted those, I believe, right at $0.75 million. That horizon runs about another 1,200 feet deeper than what we’ve been drilling. It’s approximately at 7,000 feet, I believe. Phil can correct me if I’m wrong there. Keep in mind that the Clearfork produces throughout the Permian basin, and particularly in that area. I don’t think it’s going to be as predominant as our San Andres or our Grayburg, but we do have depth rights to the Clearfork over a substantial amount of our acreage there. Phil, you might just shed some light on what we’re anticipating in terms of potential reserves from the Clearfork horizon itself.

[Phillip Terry:]

Mark, as I mentioned, or if I did not, I should have, this Clearfork is the first deeper test that we have drilled in the area. We have drilled 301 San Andres wells but we’ve not gone deeper than the San Andres. So this is our initial foray into some of the deeper horizons. But Clearfork is present in the area. There are a number of excellent Clearfork leases that produce. There is also the Clearfork Fullerton unit, which is an Exxon Mobil property and I should say it was a property that I was familiar with in the 1970s when I worked there as a young engineer. So it’s been around a long time. The Clearfork is a very prolific reservoir. It is not as universally deposited as Tim mentioned, you won’t see blanket deposition across the area. But when it is found, it is prolific. You can see production rates of 50,000 on the low end to 100,000-plus on the top end. And it doesn’t add a tremendous amount to the drilling side of it. But we feel like it’s worthwhile because we have identified potential for deposition in the area. And if this project is successful, we would have additional development to come behind that. I’ll add to the fact also that Clearfork is an excellent secondary recovery project. So we’re excited about it, we feel like that we have the potential of that production range of initial potentials or roughly equivalent to what you see in the San Andres, 100-plus barrels per day. But because you have a little more pressure, and because the producing mechanism is a little different, they don’t decline quite as quickly as a San Andres well. So we’re very excited to see what the result might be.

[Mark Lear:]

That’s great. Thank you very much.

[Operator:]

Our next question is coming from Noel Parks - Ladenburg Thalmann.

[Noel Parks:]

Just a question about the development costs, there was a mention earlier in the call about the future development costs per barrel were higher because of the acquisitions. I just wondering, could we get some numbers for typically what those development costs are for the new properties and maybe where companywide those stand on the oil side?

[Lloyd (“Tim”) Rochford:]

Certainly. We’ve been budgeting in the neighborhood of 550 to 575 for the average San Andres well that’s drilled at Fuhrman-Mascho. Most of our Permian basin assets will probably be coming in to close proximity there, whether it’s Hobbs or Seven Rivers, a little bit shallower, North Benson will come in a little bit less than that as well. I think going forward as it relates to the Clearfork, we’ll see some of those costs associated around $0.75 million. But what we’re seeing is, and I think maybe where you’re headed on this bit, is that where you’re on a BOE basis, your costs are rising a bit. Keep in mind that we now are adding reserve components that normally we wouldn’t have added in an environment a year ago, where commodity prices were, as we sit here today, about half of what we’re seeing today. So when you have a higher commodity price, the cut, if you will, or the threshold becomes a little bit lower in terms of economics and profitability. So as you are now bringing into the circle, if you will, a reserve base of say, maybe the cutoff is 20,000, whereas maybe last year it would have been 25,000. We have the costs remain the same for the well, but you have lesser reserves on a per well basis. So you’re going to average that BOE down on the reserve side and you are going to kick up the cost of that BOE a bit. But all in all, it’s a good thing, because what we’re doing is we’re just expanding that band or that parameter that allows commercialability or profitability and we are now able to add even more additional reserves than initially anticipated, overall.

[Noel Parks:]

Just to follow up. So in the long term since the decline is pretty flat, just looking out on a BOE basis, for the company looking at a net asset value basis, what would be a good number you think to use for future development costs?

[Lloyd (“Tim”) Rochford:]

I think that probably in all fairness that we were overall companywide, our finding and development costs were right at $12, I believe, and $0.03, if I’m not mistaken. Or if you break that out from an acquisition versus drill bit, we were at about $6 and change I believe, Noel, on acquisitions and I believe we were about $18-plus as it related to the drill bit. I think that’s probably fair to say that, particularly on the drill bit side, that somewhere in that $15-plus range, I believe that we’ll see or expect in the future.

[Noel Parks:]

Great, thanks.

[Operator:]

Our next question is coming from John Lane - Lane Capital Markets.

[John Lane:]

Really congratulations on the BOE’s per day being up over 6,000, that’s huge, and what a tremendous change considering now you have got these extra wells in production and where you’re going to. But in regard to that, you had entered into those collars a while ago where you capped yourself, the hedges, with a price, I think it was $80 on oil and $9-something on gas. At these lofty prices now, what’s your feeling about maybe re-entering for a certain percentage, being that your BOE’s are so high now and moving higher?

[Lloyd (“Tim”) Rochford:]

That’s a great question, John, and you’re absolutely right. We’re following these things daily with quotes; our component that’s in place now that Randy addressed earlier has I believe it’s a $60 base with an $80.50 ceiling. That expires at the end of 2008. Question is, do we want to consider components in place for the remainder part of this year at these higher prices? We’re considering that, we are very positive about the price of oil right now, and so we wanted to be careful. You can appreciate, if we were having this conversation just 30 days ago, when we would have possibly implemented something with a $100 ceiling, you could see already we would be underwater. So we’re going to be very careful, but we’re very conscious of the fact that we’re seeing outstanding prices, and that it may make sense, it may be very prudent for us at some point here to put another hedge component in place, but we’re just playing that by ear, and trust me, we’re very sensitive to it.

[John Lane:]

With the average price in the fourth quarter, I think you said it was $79.45, it was not overly costly for you, then I would presume, though a lot of sales were done above the $80.50 threshold.

[Lloyd (“Tim”) Rochford:]

Yes, we averaged, our after-tax loss for the fourth quarter was a little over $0.5 million, about $0.02 a share. I’ll give you an example. As of this morning, on a costless collar with a $90 base, your ceiling would look at about $117.10. On an $85 base, you’d be looking at $124.30. This would be a contract that would be in place through the remaining part of this year and through December of 2009. So again, we’re watching this closely, and we’ll just see how it goes here.

[John Lane:]

Is there a shot to do less than an almost two-year lock-in?

[Lloyd (“Tim”) Rochford:]

Yes. You can do different increments, yes you can. And you are right, the 6,000-plus barrels a day that we’re enjoying this quarter is a result of a lot of things, timing is always so important in so many areas, and particularly here. Here we had at year-end a number of wells that had not really had the opportunity to be completed or if they were completed, they were just into production. And the unfortunate thing is had they been completed and had a little more time line for production, the reserve results of that would have been far better. But the good news is, it’s a make-up, and we’ll see it in 2008. We’ll not only see those 14 wells be ranked up quite a bit higher in value and in numbers, but also the associated PUDs with those, so.

[John Lane:]

The assumptions then, because of the extra drilling and now the extra production, I presume you’ve been drilling then in areas where that spacing question will probably go away?

[Lloyd (“Tim”) Rochford:]

The spacing issue as Phil touched on earlier, and this took some time to do this, but we were actually able to go in and get field rule changes where other operators in the area have gone in on an exception basis, and it requires a lot of work, a lot of paperwork, a lot of moving parts. We went in and actually petitioned the Railroad Commission to change field rules and we have that, that’s in place, so that’s not a barrier for us or an obstacle any longer.

[John Lane:]

Excellent. Thank you very, very much. Great job.

[Operator:]

Our next question is coming from George Whiteside - SWS Financial Services.

[George Whiteside:]

I was very much interested in your report and then as it got published on the Street, headline was “Arena Resources Fourth Quarter Earnings Jump 80% But Missed Wall Street Forecasts.” I think it is a little bit ironic, your track record of positive earnings certainly has been remarkable for several years, and it certainly sounds as though the future looks extremely positive. Could you give us a little more color in terms of what you anticipate in terms of earnings? And I recognize for an E&P company, it’s a major accomplishment to even be profitable drilling at the pace that you are doing.

[Lloyd (“Tim”) Rochford:]

Thank you for the comments, George, and it is interesting, yes, we did miss the mark as it related to earnings from what the Street expected. And, of course, we’ve tried to explain that away as it relates to a couple of key components, in DD&A and G&A. These are just issues that you have to deal with from time to time. But I’d like to redirect the focus back to our cash flow per share. And as most people know that are on this call, I’m sure all of us know on this call, that companies like ourselves, when you’re developing so rapidly, you’re going to build those DD&A components and focusing on that cash flow per share, I think is also important. We had terrific margins as it related to that; our revenues of just north of $100 million and our pre-CapEx cash flows north of $70 million just speak volumes. And I anticipate that those kind of margins are going to be the same if not better even this year. George, we do not give formal guidance, but as I’ve mentioned a couple times so far on this call, we are in current production of a solid plus 6,000 barrels a day, and as we’re developing with 3 rigs running here, and knowing that here as we get into the second quarter, and particularly the third and fourth quarter, we will have as many as 5 rigs running companywide with all of our different assets, that we anticipate some pretty good continued growth on production and as a result, reserves by year end. I hope that satisfies your question, but again, we won’t give formal guidance, but we’re feeling very bullish about how things are going right now.

[George Whiteside:]

I apologize, I’m not trying to maneuver you into forward looking projections, and I recognize that is tricky. Your performance to date has been remarkable. And all I can say is keep it up. The other comment I would make is about reserves. Those who have followed the company for any period of time certainly can’t be unhappy with the level of reserves that you’ve built and the fact that your reserve engineers don’t add as rapidly as you might feel justified, as you’ve remarked, you’re going to pick that up and prove it up in the future.

[Lloyd (“Tim”) Rochford:]

Yes, thank you, George. Even in the absence of that issue, we’re very proud of our gain, when you factor in sales from last year, 32% growth from the year before. We’re very proud of that. How can you not be pleased? And as you mentioned, I think everybody is pleased with the results that the company’s been posting, and I think they’re going to continue to be pleased as we go forward.

[George Whiteside:]

We certainly are, and we’ll continue to be, I’m confident.

[Operator:]

Our next question is coming from Jeffrey Hayden - Pritchard Capital Partners.

[Jeffrey Hayden:]

Just wondering if you could go into a little detail, you talked about a bunch of the water flood projects, Hobbs, etcetera, some work you were doing at Y6. Just wondering if you could give a little bit more color on timing and magnitude of the production impacts we should be looking for from those other projects outside of Fuhrman-Mascho?

[Phillip Terry:]

Jeff, first of all, at Fuhrman-Mascho, as I mentioned earlier, we are in the process of preparing information to get to the Texas Railroad Commission, that information being engineering, geology, reservoir, log data, thickness maps and so forth. And as you can imagine, with the magnitude of acreage that we have, it’s a fairly big project, but we’re very close to finishing all of that. As a matter of fact, I said we’re 95% complete and I think that’s a good number. We have then got quite a bit of work to do from the land side; we’ve identified the royalty owners and then you have to go out and physically contact them and get them to agree. But all of that having been said, can be done, we’re in an area where the landowners and mineral owners are professional, they know that water flooding works, and they know that it is significant. In terms of timing, we anticipate that we will not have significant water going in the ground at Fuhrman-Mascho until the early part of 2009, early part being first quarter, and probably towards the end of that first quarter, we’ll start to get water in the ground. What happens then is a result of how much water and how many wells. It is a certainly a moving target, and I’m not trying to be evasive, but it’s just difficult to really predict the magnitude and the responses and the time of the response. What we can say is that for every barrel of oil that you produce primary, from primary production, you can expect to recover on the bottom side, 65% of that, on the top side, 100% of that. So in other words, if you produced 1 million barrels of primary oil, on the conservative side, which is where we’re engineered, you’d produce 650,000 barrels of secondary oil. We feel like, and the history has shown in that area, the more wells you drill, the tighter you drill your spacing, the greater your recovery. So you go from 65% on a 40-acre water flood to approaching 100% or one-to-one ratios as you get down to 10-acres. We will see some results in limited areas within about 12 to 14 months. And what you can model is that you can take a well from an average of a barrel a day, if it’s an old well, you can expect that well perhaps might get as high as 20 to 30 barrels of oil per day under secondary recovery. But your reserves are essentially what I said, is that you go from 65% of primary to in some cases in excess of 100%. But for our purposes, we’re engineered at 65%. So we’ll have Fuhrman-Mascho, at least one small water flood that will be active by this time next year and another large water flood will come behind that, which we hope to be in place by the end of 2009 or the beginning of 2010. We really don’t see and have not engineered much response or any response in 2008 and very little in 2009 on the Fuhrman-Mascho project. At East Hobbs, I mentioned there that we’ll convert up to 5 wells this year. We have a relatively large component of secondary recovery reserves, and we see nothing to discourage us from that. We will drill additional wells to further develop the field, we will convert additional wells; we’ve actually been putting water around the perimeter of the reservoir, and we haven’t seen significant response from that, but what it has done is arrest decline. And part of that is the reason that we were disappointed that some PDP reserves were shifted in category. But 2008 will not see a great deal of response to injection. 2009, we will start to see that production increase and you can essentially take basically take production from a current rate of 500 barrels a day to rates that could get to significantly higher than that, upwards of 2,000 barrels a day, but that would occur over a two or three year period. The other water floods that we have, the North Benson Queen unit, it will respond a little differently, because we have reactivated that water flood. We now have water going into the ground; we’ll drill 23 producing wells over the next two years, 12 of which will drill this year. So that production increase from North Benson could occur and probably will occur a little faster. If you take 12 wells and if you average 25 barrels per day for a year, you’re going to get a fairly significant increase as a result of that during the first year. And then the water flood should help sustain those rates for several years.

[Operator:]

Our last question is coming from Noel Parks - Ladenburg Thalmann.

[Noel Parks:]

Just on one other thing about Fuhrman-Mascho; I remember some time ago you were expecting to improve the efficiency there in terms of the days to drill and set pipe. I’m just wondering where that was standing now? And then just one other quick thing, I missed Randy’s comment on G&A and what the expectation was for that going forward?

[Lloyd (“Tim”) Rochford:]

Let’s address the timing first, when we initially started development at Fuhrman-Mascho, we were in the neighborhood of probably 6.5, maybe as many as 7 days. Phil, I believe now, I think it’s fair to say, that although sometimes we even beat this, but we are what, 5-plus?

[Phillip Terry:]

Yes. That’s correct.

[Lloyd (“Tim”) Rochford:]

And we’ve managed that pretty well, Noel, so feeling pretty good about that, and that’s with all 3 rigs, not just the 2 company-owned rigs, but the contract rig as well. As it relates to the G&A component, Randy, would you respond to Noel, please, with his question?

[William Randall (“Randy”) Broaddrick:]

Noel, I didn’t give any specifics to what we expect in 2008, but we do expect our stock-based compensation to continue to increase in 2008. We did issue a number of options throughout 2007 and the way the options are expensed, it’s always weighted toward the first part of the vesting period. So 2008 stock-based compensation will exceed 2007. Other G&A items, I think will see a steady increase, we have added a variety of personnel. But beyond that, I didn’t give any other guidance and I don’t think we’re prepared to at this point.

[Noel Parks:]

Just one last thing, what are your differentials looking like for the quarter-to-date, and just any thoughts going forward?

[Lloyd (“Tim”) Rochford:]

Yes, that’s an excellent question. It’s interesting how that moved around a bit during the course of the year. Differentials overall for the year actually were in the neighborhood of about $4.40, actually, specifically, $4.42. The fourth quarter, the differential really improved substantially, we averaged $2.46. Third quarter was $3.50, second quarter was $6.68. We started the year at $5.50 differential. So it did improve as we went along.

[Noel Parks:]

Okay. And so far in first quarter, what are you seeing?

[Lloyd (“Tim”) Rochford:]

Randy, I know that we just received that information yesterday or day before for February. What were we averaging in February, was it right at 90?

[William Randall (“Randy”) Broaddrick:]

I believe so, just based on oil, that would make our differential a little below $5 per barrel. I don’t have the gas information available at this time.

[Noel Parks:]

No problem. Thanks a lot.

[Lloyd (“Tim”) Rochford:]

Thank you, Noel. And I believe that was the last question, and so we want to thank everyone for taking the time today. We know that there are a number of calls that are taking place, and we apologize if some have conflicted with other call opportunities. But once again, thank you for your interest in the company and we’ll look forward to seeing and talking to you all soon. Thank you.

[Operator:]

This concludes today’s teleconference. You may disconnect your lines at this time. Thank you for your participation.