Talos Energy Inc.
Q4 2007 Earnings Call Transcript

Published: 27 Feb 2008

[Operator:]

At this time, I would like to welcome everyone to the Stone Energy Fourth Quarter and Year-end 2007 Earnings Conference Call. (Operator Instructions) Thank you. Mr. Welch, you may begin your conference.

[David Welch:]

Thank you very much, Amanda, and welcome to our 2007 earnings call. I'm joined this morning by Ken Beer, our Chief Financial Officer, and Jerry Wenzel, who is our Senior Vice President of Operations and Exploitation. First, Ken Beer will go over the numbers, and then turn it back over to me for some more general comments on our 2007 performance, and then a few remarks on some of the challenges and opportunities we see in 2008. And then, we'll take your questions. Ken?

[Ken Beer:]

Thank you, Dave. Let me start with the forward-looking statement. In this conference call, we may make forward-looking statements within the meaning of Security Act of 1933 and the Securities Exchange Act of 1934. These forward-looking statements are subject to all the risks and uncertainties normally incident to the exploration for, and the development, production and sale of oil and natural gas. We urge you to read our 2007 annual report on Form 10-K for a discussion of the risks that could cause our actual results to differ materially from those in any of the forward-looking statements we may make today. In addition, in this call we may refer to financial measures that may be deemed to be non-GAAP financial measures as defined under the Exchange Act. Please refer to the press release we issued yesterday, which is posted on our website, for a reconciliation of the differences between these financial measures and the most directly comparable GAAP financial measures. Finally, in this conference call we may refer to the terms probable and possible reserves, which the SEC guidelines prohibit us from including in SEC filings. Please reference our disclosure in the press release addressing this issue. Once again, rather than go through the financials in great detail, we'll assume everyone has seen the press release and the attached financials. Also, we intend to file our Form 10-K later today, which will contain additional financial information and our MD&A discussion, and urge you to review this filing. Let me focus on a few of the highlighted areas. Our quarterly net income totaled about $65 million or $2.33 per share, well above First Call estimates. Fourth quarter discretionary cash flow was just under $126 million. Full year income was a record $181 million, and full year discretionary cash flow totaled $453 million. As noted in the release, our cash flow was positively impacted by strong production volumes and pricing, and lower operating costs that were offset by the $95.6 million in current taxes, which were primarily due to the gain on sales from the Rocky Mountain properties, our record level of earnings, and minimal drilling activity during the year. This provided some incremental tax deferment. We also repeated some of the information included in our separate press release issued on February 15, which highlighted our reserves update. However, as Dave will address later, we also in this release included our estimated probable and possible reserves for the first time. This should provide you with a sense as to our inventory of potential projects. These estimated probable and possible reserves were fully-engineered by Netherlands', Sewell & Associates, and we anticipate providing this information on at least an annual basis. Production for the quarter and the year came in at 210 million and 224 million cubic feet equivalents per day respectively. The annual 224 million figures was at the upper end of our original 2007 guidance, even before we sold our Rocky Mountain properties, which were averaging around 38 million cubic feet a day for the first half of the year before the sale. For 2008, we have provided production guidance of 175 million to 200 million cubic feet a day, which also incorporates the recent sale of some non-core Gulf of Mexico properties and compares with pro forma of about 195 million cubic feet a day in 2007, which adjusts for the recent properties sale of non-core Gulf of Mexico properties, and for the mid-year, our Rock Mountain property sale. Oil and gas price realizations for the fourth quarter came in at just under $85 a barrel and $7.55 per MCF, or an attractive blended price of $10.41 per MCFE. Our gas price is boosted by $0.18, due to our gas floors that we had in place, while our oil price was reduced by $2.53, due to our oil ceilings that we had from our hedges. As we highlighted last quarter, without the impact of averaging, and Rocky Mountain prices, our gas and oil price realizations are now tracking just above Henry Hub for gas and just under WTI for oil. So, as you model the Stone price realizations for future periods, don't be influenced by the past blended differential, which did include the Rockies. Regarding hedges, we did put in a small 2008 gas collar since the last quarter, and that was a 750 floor and a $11.35 on the ceiling, or about $20 million BTUs per day from April through December. And we'll continue to monitor the futures market for hedging opportunities. The full schedule of our dollars is indeed listed in the release. Our absolute LOE dropped significant this quarter due to four reasons. The first was a one-time adjustment of $8.4 million regarding a higher projected insurance recovery rate versus our previous estimate. The second was the normal seasonal reduction in major maintenance activity during the fourth quarter. Remember, our second and third quarters are more active, whereas our first and fourth quarters typically have limited major maintenance activities. The third point was some minor positive year-end adjustments to previous LOE estimates. And then, finally, there was an absolute reduction in base LOE as our operating guys continue to become more efficient. Looking forward, we are estimating our LOE to be in the $140 million to $155 million for 2008, which would be around the $2 per MCFE mark. Also, as noted in the release, we took $8.2 million impairment charge relating to our forecast pool in China, which is separate from our U.S. forecast pool. We determine the cost associated with the dry hole we drilled last year should be written-off, although we would expect to have additional seismic activity and another well drilled in this concession in 2008 to complement the two other wells we drilled in 2006, which did encounter hydrocarbons. Interest expense was down to $4.3 million in the fourth quarter as we only had a $400 million in sub-notes outstanding, and with a portion of that, interest expense capitalized. Remember, in the third quarter we still had our $225 million floating rate notes outstanding for a little over a month. So this was the first quarter with that behind us. And then, under the other income category, which we are showing the positive effects of having a sizable cash position as interest income is the major part of that figure. At year-end we had $475 million of cash, all unrestricted as we did not complete the 1031 exchange before year-end. Previously we had some of that cash as restricted. Next, we have the provision for income taxes, which is a hard line item to follow this year and even harder to explain. The reported tax rate for the year ended up being around 32% and 33%, due to some domestic production deductions, which reduced the reported rate from the 35% statutory rate. We had this deduction because we were paying current taxes, as mentioned earlier, due to the combination of having a significant gain on the sales of the Rocky properties, and the higher than expected production volumes, and prices and less than expected drilling activity. We ended up with the current tax provision of $95 million. This is obviously an unusual position for Stone, which has historically had most of its reported taxes deferred. For 2008, we are estimating the tax range to be between the 32% and 37% for reported taxes, and we'd certainly expect to have some deferred taxes within our tax provision, especially given our projected level of CapEx spending. Finally, as noted earlier, we have provided our initial guidance for 2008 in our press release and hope that to be self-explanatory. And with that, I will turn it over to Dave.

[David Welch:]

Okay. Thank you very much, Ken. 2007 was a very good year for us at Stone Energy as we completed our first full year without the distractions of the past. There is a new excitement and momentum within our company as we deliver positive and sustainable results. Our stock price increased by about a third this year. This increase was underpinned by solid fundamentals. Stone achieved a net income of $176 million and cash flow of over $450 million, both of which were significantly above our targets. In 2007, we replaced our reserves while spending less than half of our cash flow to deliver at the upper end of our production guidance, lower gain inflation and reduced our total lease operating expense, including reducing base lease operating expense at about $3 million. And we continued to improve our safety record, meeting our target of one recordable incident for 200,000 hours work by achieving a level of only 0.85. We also repositioned the Company in 2007 by executing the Rocky sales for $578 million plus a retained 35% working interest in several Rockies exploration play, and then paying down debts. At the beginning of 2007, we had a debt level of $797 million, offset by a cash of only $59 million. And at the end of the year, we have merged with only $400 million of debt, offset by around $475 million of cash. Also, we have announced the share buyback program, which is intended to help improve our per share metrics in the future. Although no shares were repurchased through December 31st, we continue to view share repurchases as a viable investment alternative. In the reserves picture, we began the year with 591 BCF of estimated proved reserves. From this we sold a 192 BCF and produced another 82 BCF. Commodity price increases over the year added 12 BCF by extending the economic life of existing reserves. Then we completed field studies, identifying non-swept areas in some of reservoirs and performed well in field optimization work, and added some small non-drilling investments, which added a combined 33 BCF. We also estimate that the 2006 drilling program added about 11 BCF in new net upward revisions from its initial booking. Finally, our limited 2007 drilling program added another 30 BCF proved reserves. So in aggregate, we added about 86 BCF to slightly more than offset the 82 BCF, which we produce. We pursued many different avenues open to us to replace production in 2007, while we were spending less than half of cash flow on reinvestment. These small investments in field operating systems, an aggressive well work, yielded nearly as much benefit as our limited to 2007 drilling program. Our year-end 403 BCF of estimated proved reserves comprised 128 BCF of proved develop producing reserves; 195 BCF of proved develop non-producing reserves; and 80 BCF of proved undeveloped reserves. Since the year-end reserves report, we've already executed in 2008 a small $20 million Gulf of Mexico, non-core property sale of about 18 BCF, bringing the post sale estimated proved reserves base to 385 BCF. This sale obviated over $33 million of future abandonment liabilities. Also, in 2007, for the first time Stone had Netherland and Sewell, our third-party reserves engineering firm, quantify our probable and possible resaves. At year-end 2007, the Company had estimated probable reserves of a 142 BCF and estimated possible reserves of 448 BCF. These are, of course, independent of our proved reserves. We anticipate monitoring probable and possible reserves annually and reporting to you the progress made in these two categories, as well as the official proved reserves. Also, these categories exclude any contingent resources, which would be contained on our exploratory or untested business development acreage. On the production-side, we averaged 224 million cubic feet equivalents per day in 2007 compared to 2011 the previous year. This was a great achievement by our organization as we sold off about 20 million cubic feet a day of annualized Rockies production and we're still able to grow production about 6% year-on-year. Regarding cost, we were able to reduce our total lease operating expenses by almost $10 million through aggressive cost controls and the absence of the Rocky Mountain properties in the second half of the year, despite an increase in both Gulf of Mexico major maintenance expense and increased insurance costs. We intentionally increased major maintenance with our aggressive work-over program and field improvements, which aided in delivering this year's increased production rate. The costs control was an impressive accomplishment during a period when overall oil field service costs were inflated. Our operations group was very efficient with our LOE dollars. Although our insurance costs were up for the year, we were able to reduce our premiums mid- 2007, and expect the results of our field improvement spending over the last couple of years to help drive the strength downward again in 2008. So these are the facts and figures. But there are many other things that the company achieved in 2007, which are not yet reflected in these results. We developed exploitation and development inventory for roughly three years duration, and put together a capital program for 2008 to deploy about $200 million in low-to-moderate risk projects. The core of our exploitation drilling program will be done at Ewing 305, which contains our largest source of proved undeveloped reserves at Main Pass 72, which is our Caprock oil test and at Mississippi Canyon 109, the Amberjack field purchase from BP in 2006, which contains multiple drilling opportunities. We have already commenced the Ewing 305 program in our [Trinity well], which is the largest proved undeveloped reserves on our books at 2 million barrels. It has been successful and is in the process of being brought on live. Presently, we are cleaning up after the completion of operations and producing at a rate of almost 2,000 barrels of oil a day, which is consistent with our production forecast. We expect to move our rig to Caprock Main Pass 74 in about a month and are awaiting a specific rig for Amberjack, which should be available in the fourth quarter. Waiting for this particular rig in Amberjack will allow us to drill a multi-well program, which will continue into the 2009. This year we also recruited and hired new Vice President of Exploration, Rich Smith, former head of the Dominion's, very successful deepwater Gulf of Mexico exploration business. Rich joins Stone Energy in July and he has already led us through a very successful lease sale on October, wherein we acquired 16 promising blocks for about $13 million. All of these blocks have now been awarded to us by the U.S Government Minerals Management Service. 10 of these blocks are in deepwater and six are on the outer continental shelf. We are also evaluating resale opportunities in the upcoming March offshore resale, which has a significant number of new leases available. Under Rich's direction in 2007, the Company has now developed to drill a ready exploration portfolio and is positioned to participate in a half dozen or so growth prospects in 2008, including two to three wells in deepwater gulf, which had a 10% to 33% working interest. We could spend up to $90 million in total on exploration drilling in 2008 including prospects in South Louisiana, Gulf of Mexico and Bohai Bay. We would expect that the South Louisiana and outer continental shelf projects could add production in reserves this year is successful. In Bohai Bay, a partners meeting is scheduled later this month to finalize plans which will likely comprise of 3D seismic program offsetting the recently announced 1 billion barrel Nanpu discovery by, and either an appraisal well or another exploratory well, on the 750,000 acre block. In addition to our exploration efforts, the company has been working since February of 2005 on the shale play in Appalachia. We believe this shale has favorable productive potential, and we are hopeful that it will be similar to the Barnett, Woodford or Fayetteville, but is more favorably situated, relatively to the commodity market in any of these already commercially successful place. Accordingly, we have high-graded four areas of interest in Appalachia, where we believe commercial shale gas production is possible and the market is favorable. Thus far, we have acquired a leasehold of about 20,000 acres in two of these areas and are expanding cautiously into the other two. We anticipate being able to drill at least two Appalachian test wells this year to help us begin to evaluate the long-term potentials of these areas. Adding it all up for 2008, we anticipate keeping a stable production rate within the range of our divestment-adjusted 2007 delivery, which was 195 million cubic feet a day. Our target range is 175 to 200 million cubic feet a day. We anticipate maintaining a high level of well operations, and at the same time, reducing total lease operating expense by about $5 million from 2007. We'll endeavor to keep our proved reserves flattish on a divestment adjusted basis, which is 385 BCF, and to begin growing our probable and possible reserves, as we cautiously restart our exploration program. Capital program for 2008 is authorized for $395 million. Share buyback program is also available to help per share growth and for production and reserve metrics, even as the absolutes remain flat this year. We're also keenly aware of the credit crunch and the impact it may have on overextended companies, and can use the strength of our balance sheet for the right deal in one of our core areas of the Gulf, Eastern U.S. gas, our onshore oil projects. So in conclusion, this gives you our assessment of 2007 as being a very good year, and tells you what we foresee in 2008. We have an organization poised and determined to deliver significant value to our shareholders. Thank you for joining on the call and we will now be happy to take your questions.

[Operator:]

(Operator Instruction) Your first question comes from Dave Kessler with Simmons & Company.

[Dave Kessler:]

Good morning, guys.

[David Welch:]

Good morning Dave.

[Dave Kessler:]

Thinking about the Netherland Sewell on risk probables and possibles, can you discuss what this is from a risk perspective, maybe touching on are these direct offsets, can you get at the probable from existing infrastructure, just trying to think about how we model this out?

[David Welch:]

Right. We really can't discuss that in any detail at all. As you know, it's not a topic that is yet endorsed by the SEC. So we do want to give you an indication of what our on risks are. I would just refer you to the definitions that third parties typically would use for probables and possibles. The one thing I would point out on this, though, is it doesn't include any of the potential resources from our deepwater or anything that we have on our Appalachian acreage.

[Dave Kessler:]

Okay. That's helpful. And then, looking at kin d of the proved, developed, non-producing reserves that were stranded a while back due to the storms and third-party, can you give us any additional color on those, what's come back, if it hasn't already come back, how much capital has to be spent to move those back from proved, developed, non-producing to proved, developed, producing?

[David Welch:]

I think those are pretty minor at this point. Jerry, there are not any large PDNPs that still stranded from the storm?

[Jerry Wenzel:]

No. It is typical recompletions and workovers that we'll be doing throughout the year.

[David Welch:]

Basically the lion share, the vast majority of our proved, developed, non-producing are just behind pipe reserves and producing wells.

[Dave Kessler:]

Okay. Great. Last question, on your reserve additions in 2007, it appeared to be driven by drilling a PUD and then booking a PUD right next to it, do we expect to see more of that going forward, just trying to get a handle on what inventory really looks like?

[David Welch:]

Yeah. In 2007 we didn't drill any PUDs. All the wells we drilled were for new reserves. We did have some reserves that were added as a result of making improvements in our field operations where, for example, we could lower the pressure in reservoirs and get more gas or oil out of existing reservoirs that sort of thing.

[Dave Kessler:]

Great. Thank you so much. I'll let somebody else jump on.

[David Welch:]

Thanks, Dave.

[Operator:]

Your next question comes from David Heikkinen with Tudor, Pickering, Holt.

[David Heikkinen:]

Good morning. Just a question on 2007 what was the CapEx on the retained assets?

[Ken Beer:]

David, if you include or exclude the P&A, but if you include it's going to be about $190 million to $195 million.

[David Heikkinen:]

Okay. And then when you think about following along the lines of PUD conversion cost, your future development cost, whenever you get 10-K out, what will those be?

[Ken Beer:]

The 10-K will be out, hopefully, later on this afternoon. But I'll give you -- I can give you a sense of future development costs, and again, for us that will also include P&A, is about $840 million.

[David Heikkinen:]

Okay.

[Ken Beer:]

So that was inclusive of P&A costs as well.

[David Heikkinen:]

Okay. And then if I think about bringing the probable and possible in, is there a reason why those reserves will be dramatically different than converting PUDs as well as the costs for those?

[Ken Beer:]

There could be, I mean, typically your proved undeveloped would have facilities already in place. Some of the possible reserves would require building platforms, pipelines that sort of things. So, in general, those costs should be consistent with the Gulf of Mexico because I think just about all of the proved and probable that we have are in the Gulf.

[David Heikkinen:]

Okay,

[Ken Beer:]

With probables and possibles are in the Gulf.

[David Heikkinen:]

And then, when you think about overall, you talked about retaining interest from Rockies place. Can you give some characteristics for those Rockies place? And then indication from, I guess new fields as far as when they will be drilled?

[David Welch:]

Yeah. We're going to have some partner meetings with new field coming up in the fairly near future. They haven't indicated any plans to be highly active on those things this year. There maybe a few dollar that are spent in the Rockies but nothing highly material this year.

[David Heikkinen:]

Okay. So thinking about it, I guess, if you have meetings coming up would it be fair to ask the question again on your first quarter call and you probably have some better details of what your --?

[Ken Beer:]

Yeah. We'll definitely know more three months from than we know now.

[David Heikkinen:]

And on your probables and possibles, how concentrated are those around the three major projects that you talked about during Banks Main Pass and Mississippi Canyon?

[Ken Beer:]

I don't have that specific detail in front of me right now, David.

[David Heikkinen:]

Okay.

[David Welch:]

Although, you're right there is some concentration in our top areas, but David is correct in that that it is spread throughout our list of properties.

[Ken Beer:]

What I can't tell you is that the largest possible was the one that's in Caprock, which we're getting ready to try to drill well within the next month.

[David Heikkinen:]

Okay. Thanks, guys.

[David Welch:]

Okay.

[Operator:]

(Operator Instructions). Your next question comes from Rehan Rashid with FBR.

[Rehan Rashid:]

Good morning, David.

[David Heikkinen:]

Good morning, Rehan.

[Rehan Rashid:]

Trying to stick with this 2P, 3P discussion and I understand you can't give too much more detail. But maybe help us reconcile capital allocation decision with so much more 2P and 3P available why have a higher risk portfolio 40% of your CapEx this year towards anything other than make it much more lower risk, access your 2P, 3P reserves and double the size of the company. So just trying to reconcile that if indeed this 2P, 3P is somewhat reasonably accessible and developable in a reasonable timeframe, why allocate capital anywhere else but here?

[David Heikkinen:]

Yeah. Well, we are allocating capital to the probable and possible. The biggest possible element that we have as I mentioned just second a ago is this Caprock, which we're focused at within the next month or so. So that's going to be a direct attack on the big part of those possible reserves. But they are like a pipeline and as you know, there need to be [figure] pool into those possible for the future to keep the whole mechanism going.

[Rehan Rashid:]

Right. But at 65 BCF roughly midpoint, the guidance for '08, even if I risk the possible is heavily, you're talking about the five, six-year inventory that will allow for much more slower dip into a deepwater, then kind of what the feel I am getting with capital allocation, again, trying to reconcile the both?

[David Heikkinen:]

Yeah. I wouldn't say that we are really being aggressive, Rehan, in getting into deepwater and these other exploration things. We're being very cautious about managing which working interest that we take in some of these things and it’s possible that some of the leases that we just bought in October may find their way into the possible category. Okay and those would be some of the things we'd hope to be testing that are not yet in the possibles. That could show up in there fairly soon.

[Rehan Rashid:]

Got it. And one last question I apologize going back to Kerr-McGee JV, what has changed since then that will allow for a better results, and then along the same lines you said 16 blocks for $13 million given how aggressive that biding was for these leases this time around that sounds that you got some of these pretty cheap. What are you seeing here than that the rest of the competitors did not see? (inaudible) your thoughts?

[David Heikkinen:]

Fair point. Let me tackle on lease sale question first and then I will come back to Kerr-McGee. On the lease sale, we had some proprietary data in one area where we happen to have two data sets that we were able to combine, that no one else have the capability to do and that's where we spent some of our money and got some good leases in that area. In another area we bid with Anadarko. And Anadarko had some proprietary data, which allowed the reduction of competition of the block. On about half the blocks that we did, we actually did outbid other parties. And so there were some recognized prospects on many of those blocks. Turning back to your question on Kerr-McGee. What's changed there, Rehan is that we have 3D data that now covers the whole regional area. So we have regional tie in of all the 3D data, and its latest depth migrated type of data, number one, that we have. Number two, we also have geomagnetic data, which allows us to understand hydrocarbon migration pathways. We have sand depositional data which we did not have back then that covers the regional area, and we have an exploration department focused on nothing but that. So those are four things that are different now than were existing back at the time of the original Kerr-McGee deal. And the reason we haven't done anything on the exploration side, really in the last couple of years, is it takes quite a while to mature all those things and to get in a position to be able to be successful with the program. You'll not see us swinging for the fences on these things, Rehan. You'll see us trying to hit some of the higher success probability projects that are out there.

[Rehan Rashid:]

Got you. One more quick one, Appalachia, the first test should be roughly what time of the year?

[David Welch:]

I would hope by second or third quarter we should have our two wells drilled. We're going to have to go through and do core analysis and that type of things, but we're very encouraged about this area. And I know you did follow the industry, you've seen others announcing commercial successes in Appalachia. So, we're hopeful that we have been good at picking the right places to go ourselves.

[Rehan Rashid:]

And this acreage was preexisting or did you just pick this up?

[David Welch:]

No. We've being buying it over the last year or so. And we're still engaged in building that inventory a little bit.

[Rehan Rashid:]

Okay. Thank you.

[David Welch:]

You bet.

[Operator:]

Your next question comes from Wei Romualdo with Stone Harbor.

[Wei Romualdo:]

Yeah. Can you elaborate a little more on the LOE? In the fourth quarter I know there was some one-time item of $84 million. If you add that back, fourth quarter was still pretty low compared to your guidance going into '08, and can you elaborate a little bit, are you seeing continued inflation?

[David Welch:]

Yeah. Ken went through that. Why don't you go back through that piece again?

[Ken Beer:]

Yeah, I think I've mentioned it. There's really the four parts to it. You've mentioned the first part is the $8.4 million, which is just a higher projected insurance recovery rate versus our previous estimate. And that is very much one-time and to a certain extent conceptually should be spread over the previous eight or nine quarters where we were using the lower rate. The second was just in the fourth quarter particularly we tend to have minimal activity with major maintenance projects. So kind of fourth and typically first quarters you'll see lower activity in things like painting. The winter weather makes a lot of activity somewhat prohibitive. The third was there was a small adjustment to some -- this will be a positive yearend adjustment to some of the previous LOE estimates. And then, fourth is just our base LOE had indeed been pushed down from where we started the year. So you're right, and we tried to, at least, suggest that the fourth quarter was kind of a one-time LOE anomaly. Looking ahead to '08, we did put out guidance, which I think gives you a better roadmap, albeit quarterly you might see first and fourth quarter being on the lower end and second and third quarter being a little bit higher. But the $140 million to $155 million should be a good number for '08.

[Wei Romualdo:]

Okay. Why don't they mention that the base LOE is down? Is that due to the asset divestiture? If so, why aren't we seeing even with assets sold, why is the LOE, at least on an absolute dollar basis still flat? I guess I was expecting some improvement in the LOE in '08 versus '07 but we are not getting that.

[David Welch:]

And again, our hope is that we will get that. If you look at the lower end of the range, it would certainly be down versus 2007. But there are always a lot of unknowns, particularly a lot of major maintenance projects that are unscheduled. So that's why we've provided a range. The sale of the Rocky Mountain assets did reduce LOE, if I remember, on an absolute basis. So that was a relatively small amount of with LOE. That's why, from a guidance standpoint, I think you will see it goes from -- our hope is that we can be lower in '08 versus '07, but the guidance just provided a range around that.

[Wei Romualdo:]

Okay, thanks. Now the last question I have is, we were looking at the cash on hand, you mentioned acquisition exploration project and share buybacks, and how do you rank those in terms of priority?

[David Welch:]

Well, let me just say that on our capital budget, we're going to live within our cash flow this year is our intent. So it's not going to be exactly to the capital program. So I think there are a number of complex factors that come into play, including what are the opportunities for acquisitions. And that's the real driver of which way we might end up going. And the share buyback is something that we know we can execute. So it's more of a certainty in terms of our ability to execute it.

[Wei Romualdo:]

So if you don't have any acquisitions opportunity, does that mean by the end of the year you look to spend some of that cash on hand to buyback stock?

[David Welch:]

I would think that would be fair.

[Wei Romualdo:]

Okay

[Ken Beer:]

Yeah. Again, one of the things that we are looking at is, as David mentioned, a wide range of different acquisition opportunities as well as drill to earn opportunities which brings capital commitments with it. There are a lot of variables that go into the decision to repurchase shares. So almost on a daily or a weekly basis we're going to have to revisit that.

[Wei Romualdo:]

Okay. Thank you.

[Operator:]

Your next question comes from Tom Nowak with Merrill Lynch.

[Tom Nowak:]

Hi, good morning.

[David Welch:]

Hi, Tom.

[Tom Nowak:]

So, is this the first time that you've ever had the probables and possibles calculated?

[David Welch:]

Yes, it is.

[Tom Nowak:]

So you don't have what they were at the end of the year?

[David Welch:]

No, we don't. But we do now have a benchmark that we can give you information based on that on annual basis going forward.

[Tom Nowak:]

I was kind of curious if this is important information that you actually use to allocate capital or if it's more just marketing information? I believe it's more of the latter if it's something that was never actually used to help with drilling or allocate capital spending. Do you have thoughts on that?

[David Welch:]

Sure. Actually, it does represent our inventory of things to do. So it is highly valuable to us in our capital allocation procedure, as well as helping us to achieve a goal that we aspire to, which is to be as transparent in the marketplace as possible?

[Ken Beer:]

Yeah. Tom, it's Ken. We had to start somewhere and rather than us put out internal probable and possible number, we felt it appropriate to put out one that was engineered by Netherland Sewell and that obviously takes time. So, really during the course of 2007, Netherland Sewell worked through our various projects. And so as David said, we have a starting point and we will be providing this year-after-year in both internally and I think externally, it should provide some thoughts or guidance as to how our whole program is doing. Because, as you know, with a drilling program you can -- some successes don't immediately go into the proved category, so this will at least provide an opportunity for us and the external world to take a look year-over-year as what happens to the probable and possible categories.

[Tom Nowak:]

So it sound likes you've had some of this information prepared internally just never externally prepared? Is that fair?

[Ken Beer:]

We have not had it -- we've never had Netherland Sewell prepare probable and possible reserves. That's why I said, we made that commitment in '07 and they spent the time in '07, so we have a good starting point.

[Tom Nowak:]

Okay. Thanks a lot.

[Operator:]

And you do have a follow-up question from David Heikkinen with Tudor, Pickering, Holt.

[David Heikkinen:]

Just had a question for Rick Smith, now that he's been there -- you been there for seven months--

[David Welch:]

David, Rich is out of town.

[David Heikkinen:]

He is not in? What I was trying to get an assessment at, with the disclosure of probable and possible and kind of risking of inventory and trying to quantify your prospect inventory, how has that changed since Rich has been there over the last seven months? I mean what cost have you instituted any new processes as far as how you risk prospect, how you're building up your prospect inventory, and then now you have an external measure of probables and possibles, I am just trying to get a feel for his impact on the firm?

[David Welch:]

Yeah. I think, well, probably the best and most intangible impact is just our results on the lease sale of October. But we do have an ever growing inventory of exploration prospects. Rich's clarify to each of the different categories in the exploration type wells, what working interest ownership we'd ideally like to have? And I as mentioned before he is coming about from the approach of five to hit some singles and doubles rather than home runs right off the back to try to continue to build credibility. But we're using risk assessment process which is then promulgated and fairly well know in the industry called the Rose Risking Process, which is a consulting company. I would say, it gives the guidelines and the way to rigorously assess risk. And we are utilizing that particular risk assessment methodology.

[David Heikkinen:]

Would you all be willing to disclose then what's your P10, P90 is around that 3P reserve report?

[David Welch:]

It's not done on a probabilistic basis.

[David Heikkinen:]

Okay.

[David Welch:]

You know, it's in common--

[David Heikkinen:]

The same way that you're doing internal risking? The prospect by prospect, field by field at Netherland Sewell.

[David Welch:]

Right

[Ken Beer:]

That's right. Netherland Sewell. As you know, internally when we're making we use the risk rating process, the reserve rules are such that you use the deterministic process. And that's the way but 2P and 3P are also done.

[David Heikkinen:]

Thanks a lot guys. And just my sincere condolences to the friends and families Jimmy. Wanted to just pass that on as well.

[David Welch:]

Thank you very much. We appreciate that.

[Operator:]

You do have follow-up question from Rehan Rashid with FBR.

[Rehan Rashid:]

Ken, just a couple of modern questions. First, you gave the future development costs. Did you indeed said $800 million for just a PUDs or did I not hear you right?

[Ken Beer:]

It's $800 for PUDs, PDNP and PNA.

[Rehan Rashid:]

Okay.

[Ken Beer:]

So everything is put is in there.

[Rehan Rashid:]

Got it. What about future operating cost?

[Ken Beer:]

Again, you'll see that, hopefully later on today, but we've got a number around $915 million.

[Rehan Rashid:]

Okay. Perfect. Thanks. Again, going back to this 2P, 3P discussion, I won't belabor too much. But if you indeed have a reasonable assessment of this and however you get there, why not aggressively buyback some more stock rather than looking forward just in M&A opportunity that you might or might not know what comes with it?

[Ken Beer:]

Yeah. Number one, we do acquisition, we're going to be pretty careful that we do know what comes with it. Second thing is just on the probables, for example, Rehan, lot of those probables reserves are things that are -- where we're already producing the well for those probables are located.

[Rehan Rashid:]

Okay.

[Ken Beer:]

So, overtime we would anticipate getting those reserves just by continued production. And there are things where, for example, if you drill a well you can only book your reserves down to the lowest proved level that your well proved. Well, you may have further reserves down depth that you would expect. Again, all you have to do is really keep producing to get those reserves. In fact, that 11 BCF that we added this year from our 2006 drilling program was an exact example to that. So I guess, we view both of the things you mentioned there's good opportunities and we have to weigh those. And we will weigh those and their relative benefit at the time the opportunities are represented to us.

[Rehan Rashid:]

Okay. Thank you again.

[Ken Beer:]

Thank you.

[David Welch:]

All right.

[Operator:]

At this time, there are no further questions. I would now like to turn the call over to Mr. Welch for any closing remarks.

[David Welch:]

Okay. Thank you, Amanda. I think we pretty well covered the waterfront this morning. Thank you again for joining the call and we look forward to our next interaction with you. So long.

[Operator:]

This concludes today's conference. You may now disconnect. Copyright policy