W&T Offshore Inc (WTI) 2009 Q3 法說會逐字稿

Thank you for joining us for the W&T Offshore, Inc., 2009 earnings conference call. (Operator Instructions). This call is being recorded, November 5, 2009.

I would now like to turn the conference over to Miss Janet Yang, Finance Manager with W&T Offshore.

Thank you, operator. Good morning, everyone. We appreciate you joining us for W&T Offshore conference call to review the third quarter 2009 results. Before I turn the call over, I have a few items to go over. If you would like to be on the Company's e-mail distribution list to receive future news releases or you have experienced a technical problem and didn't receive yours, please call DRG&E's office at 713-529-6600 and someone will be glad to help you.

If you wish to listen to a replay of today's call it will be available in a few hours via webcast by going to the investor relations section of the Company's website at www.WToffshore.com or via recorded replay until November 12, 2009. To use the replay feature call 303-590-3030 and dial the pass code 4173824. Information recorded on this call speaks only as of today, November 5th, 2009, and therefore time sensitive information may no longer be accurate as of the date of any replay. Please refer to our third quarter, 2009, earnings release for our disclosure on forward-looking statements.

Now I would like to turn the call over to Mr. Tracy Krohn.

Good morning, and thank you for joining us for our third quarter 2009 conference call. Today we are going to review the significant events that took place in the third quarter 2009 and provide an update on how the Company is looking going forward. Today, I have Danny Gibbons, our Chief Financial Officer, and Steve Schroeder, our Chief Operating Officer with us, also Jamie Vazquez, our President, and Jeff Durrant, our Senior VP of Exploration and Geosciences are all going to be available for the Q&A session.

Throughout the year, 2009, we have been working to add value, not just with our drilling program. As you know, we limited our spending this year to build cash and let service costs come down. That's definitely going according to plan and in the meantime we have been working to lower operating expenses, lower DD&A and create new opportunities for future growth.

Despite our reduced capital program, production is up 20% from the first quarter and 3% from the second quarter. This is due to the drilling successes from the latter part of 2008 and early 2009, success from recompletes and workovers and from shut-in production from hurricanes coming back online.

With the continued strength in oil prices, we are focusing on oil specific targets, production mix was approximately 47% oil in the month of September versus 41% during the first quarter of this year. Daniel Boone, which began producing at the end of the third quarter, has got to significantly contribute to cash flow of the Company going forward, especially since it's mostly oil.

Earlier this year we lost a profitability initiative with the goal of implementing better controls throughout the Company. We directed our attention to identifying and divesting non-core assets to reduce both operating costs and long-term asset retirement obligations. We have been successful with both initiatives. As for divesting non-core assets, we just closed the sale of the package of thirty-six non-core fields last week, subject to the terms of the purchase and sale agreements. This is in addition to the package we sold in June.

Through the two divestures we have completed year-to-date we believe we have reduced LOE by two to $3 million a month going forward, decreased our amendment retirement obligation and reduced the number of structures, including pipelines, by approximately 320 and well bores over by over 400 net. All in all, including the divestures and other changes Danny will discuss with you later, ARO is down almost about $179 million for the year.

Although our capital program for 2009 is mostly complete, we still have a lot of activity. For instance, our A and D team has been extremely busy. We have continued to evaluate various acquisition and joint venture opportunities as well as evaluate the potential to divest other non-core fields. On the acquisition side, there's still a lot of packages to consider. We don't intend to purchase something just for the sake of doing a deal and we never have. A good portion of our historic success was built by being opportunistic and we see no reason to change that. Our objectives haven't changed and we remain disciplined and patient. As we have explained many times before, we don't budget acquisitions so we can maintain this disciplined approach. As you know, I'm a majority shareholder, so I have the most at stake and I want to take care of your interests as well as my own.

With that, here's Danny Gibbons to highlight the financials.

Thanks, Tracy, and good morning, everyone.

Today, I'd like to discuss some income statement items, our cash balance and liquidity, had movements in our P&A liabilities. As I did in our last conference call I'm going to make sequential comparisons rather than year-over-year comparisons of our financial performance, giving the considerable difference between this year and last year in terms of operations. For year-over-year comparisons, please refer to our press release.

Compared to the second quarter of 2009, revenue increased 11% to $167 million driven by higher production as well as higher average realized price per Mcfe. Reduction increased 3% to 25.7 Bcfe, from 24.8 Bcfe in the second quarter. The increase in production is primarily the result of successful wells drilled in earlier periods that are well performanced and production coming back online following hurricane remediation efforts by various pipeline operators. Average realized prices increased 4% to $6.30 per Mcfe, from $6.06 per Mcfe during the second quarter 2009, due to higher oil prices, somewhat offset by lower natural gas prices.

Adjusted EBITDA increased 22% to $97.5 million from $79.8 million in the second quarter. The growth in adjusted EBITDA is largely due to growth in revenues due to higher production volumes and higher oil prices. As it relates to lease operating expenses or LOE, internally we split LOE into five components, base LOE, insurance premiums, workovers, facilities work, and hurricane mediation. The hurricane mediation component is further broken down into expenditures and then insurance reimbursements for such cost. For the last two quarters, we have been reducing base LOE, especially compared to last year; for the sequential quarter comparison base LOE was much lower and net hurricane remediation costs were down as well. But this was almost entirely offset by higher insurance premiums and increased workover activity.

Moving onto our 2009 capital expenditure program, the program that we envisioned at the beginning of the year is nearly complete. During the nine months ended September 30, 2009, we spent $276 million and we were successful at eight out of eleven wells, including six of eight exploration wells and two of three development wells. After the close of the quarter we drilled one more successful exploration well. We will likely spend closer to $290 million this year, also allowing us to complete our scheduled recompletion efforts. This is somewhat higher than our originally announced budget, but we have some additional drilling opportunities that we have added recently and we have incurred additional costs on some wells and taken higher working interest on others.

Our cash balance at September 30, 2009, was $107.3 million, up $6.6 million over last quarter. Let me help you reconcile the changes in cash from last quarter. Cash flow from operations before changes of working capital was $90.9 million and we spent $36.3 million on capital expenditures, $1.3 million in accounts payable reductions and other working capital changes, $44.4 million in P&A expenditures, and $2.3 million for dividends. Today, our cash balance is approximately $146 million and ungrowing capacity under our revolving credit facility is still $262 million. We are also in compliance with all of our bank covenants. We just completed the semiannual re-determination of our borrowing base and has been reaffirmed at $405.5 million.

During the quarter we entered into various financial hedges of our estimated 2010 production. The main purpose of hedging was to enhance the 2010 capital budget and our semiannual borrowing base re-determination. Thus, the hedges are not speculative in nature. During the third quarter we hedged 12.1 Bcfe of natural gas and 1.4 million barrels of crude oil or 22.2 Bcfe for 2010. Natural gas production is hedged with floors as low as $5 and ceilings as high as $9.40 per Mcfe, and crude oil production is registered with floors as low as $65 per barely and ceilings as high as $90.35.

Turning to asset retirement obligations, we have good news. During the third quarter we further reduced our asset retirement obligations or short net to ARO, largely through cost revisions and work performed. Thus far in 2009, we have reduced our ARO by $75 million for work performed and by $75 million for asset dispositions. In addition, we decreased our estimated -- estimates of future ARO by $67 million, the majority of which relates to recent cost reductions we experienced in the marketplace for decommissioning, site clearance, and removal of certain of our operated structures and pipelines.

Conversely, our estimated ARO increased by $63 million, the majority of which relates to revised estimates for the dismantlement of two operating platforms that were toppled during Hurricane Ike and the plugging and abandonment of the associated wells. The majority of this change is covered by insurance, as I will discuss momentarily. One final note of ARO, we estimate that we have decreased our ARO by an additional $53 million through the divesture package that was recently completed and that will be reported at our year-end financials. We are excited about the reductions we have seen in ARO and hopeful that we will be -- able to make further reductions in this as costs come down further. We believe this is another example of the Company taking active measures to position itself for future growth.

Let me move on to insurance receivables and claims for a moment. As we have explained in the past, we don't budget hurricane expense or insurance for mediation reimbursements in our guidance which makes both LOE both difficult to explain and harder to forecast. Included in lease operating expenses for the third quarter and first nine months of 2009 are $4 million and $19.3 million respectively of hurricane remediation costs related to Hurricane Ike that were either not yet recovered from insurance underwriters or are not covered by insurance. We anticipate that lease operating expenses will be offset in future periods to the extent that these costs are recovered under our insurance policy.

During 2009, we have collected $31.2 million from our insurance underwriters and have $43.5 million in accounts receivable for insurance claims yet to be reimbursed as of the end of the quarter. A significant portion of the insurance receivable related to the P&A of wells and abandonment facilities damaged by Hurricane Ike. Accordingly, the increase in ARO that I referred to earlier as a result of hurricane remediation is actually covered by insurance.

Closing items, taxes, year-to-date we received approximately 17.7 million in tax reimbursements that relate to 2008 federal estimated tax payments and $4.6 million for a tax loss carry back. We also expect to receive an additional $8.9 million related to tax loss carrybacks with treasury before the end of the year and the remainder of our tax receivable will be collected sometime in 2010, after we file our 2009 federal income tax return. During the third quarter we recorded a $3.8 million derivative loss. Of this amount, $3.3 million is related to our commodity derivatives position for 2010 and the remainder is related to our interest rate swaps. In September, we also recorded $5.3 million in other revenue. This relates to allowable reductions of cash payments for royalties owed to the minerals management service or MMS for transportation of their Deep Water production through our sub-sea pipeline systems. That I'll turn the call over to Steve Schroeder. Steve?

Thanks, Danny.

Let me start with an update on our drilling program. During the third quarter, we drilled one successful development well on a conventional shelf. This was the South Timbalier 316-A6 well which commenced production on September 16th. Additionally, following the close of the third quarter, we drilled to total depth a 50% working interest, non-operated exploration well in the marsh lands of South Louisiana. The well was drilled under budget with total project costs of about $4 million net to W&T. First production is anticipated in the third quarter, 2010, following construction of facilities and flow lines.

This marks a small step from the Gulf of Mexico which we hope to expand this concept in the future. As we have mentioned in previous calls, we are looking for joint ventures and partners to gain experience and expertise in other basins. As we previously announced, our Daniel Boone field is up and producing. The good news is we started production as promised late in the third quarter, actually on September 28th and under-anticipated project costs. The current rate is approximately 6,000 barrels of oil and 6 million cubic feet of natural gas per day, gross.

Production for the third quarter was 25.7 Bcfe and was at the high end of guidance. We have experienced increased production from our recomplete program which is a cost-effective way to increase production at a minimal cost. Through the end of September, we have performed 20 recompletes this year for a total net cost of $11 million for an increase of 35.2 million cubic feet equivalent per day of production to net to W&T. During the third quarter oil and natural gas liquids represented 45% of total production and, as a matter of fact, 47% of the total production in September was oil and natural gas liquids. Currently, we are producing about 255 million cubic feet equivalent per day, which excludes production related to divesture package.

Additional production during the fourth quarter will come from several sources. We expect Daniel Boone to make significant contribution of fourth quarter production. We also anticipate some new incremental production from several scheduled recompletes. Additionally, we recently brought approximately 5 million cubic feet equivalent per day back online from the A and R pipeline that was shut in due to repairs after Hurricane Ike. We do have other production that is still shut in from Hurricane Ike of approximately 9 cubic feet equivalent per day, but don't expect any of this back online until sometime after the first half of 2010.

Offsetting these items will be the effect of recent divesture package which reduced production by 25 million cubic feet equivalent per day and base decline. Relative to production guidance for full year 2009, we have of tightened the range and raised the midpoint of our production guidance. We were able to revise our guidance because the uncertainties related to the timing of Daniel Boone and the threat of down time associated with hurricanes have been eliminated. For the fourth quarter our guidance is impacted by our recent divesture which is primarily cause for the anticipated 5% production decrease from the third quarter. Production contribution from Daniel Boone and workover and recomplete related activity will aid in offsetting additional near-term natural production decline.

Lease operating expenses for the third quarter of 2009 were $53.8 million, which include $4 million for hurricane remediation. Excluding the hurricane remediation costs, we were at the low end of guidance. The lower costs are a function of lower facility expenses which were approximately $2.1 million under projections. As we have discussed in the past, we have continued our profitability initiative which refocused the staff to review facility optimization, well performance reviews, well bore utility utilization analysis and overall reduction in costs. To date through this initiative, we have meaningfully lowered our costs, particularly with respect to transportation and labor.

Another way we have decreased transportation and labor costs this year is through the sale of some non-core properties. As Tracy mentioned earlier, we believe that we have reduced lease operating expenses by approximately $2 million to $3 million per month through the two divestures we have completed to date. We will not see the full effect of this until November. Combining the effects of the profitability initiative and the two divestures, we have eliminated five of sixteen boats, four of nine helicopters and approximately 100 of 260 contract employees since the beginning of the year. As a result, our costs are lower and our full-year guidance has improved.

LOE guidance for the fourth quarter is essentially flat with the third quarter. The fourth quarter includes cost savings from the profitability initiative and from the divesture package, but is offset by an increase in facility and workover expenses forecasted in the fourth quarter and the incremental expense associated with the Daniel Boone prospect. LOE guidance for full year has moved down significantly. The midpoint of the new annual guidance is down $30 million from the last time we reported it.

There are two factors driving this guidance downward. First and most important is the result of successful cost controls, cost deflation and less than projected insurance premiums. The second factor was savings from the non-forecasted items such as divestures and major rig workovers. As a matter of fact, for the last three quarters, our lease operating expenses was $22 million under the estimated midpoints given for each individual quarter. We like the trends going forward and we still believe that there are more savings coming down the line. Gathering transportation and production taxes for the third quarter were $4.2 million or at the low end of guidance.

Now let me turn it back to Tracy for closing remarks.

Thanks, Steve.

In these final couple months of 2009, we were extremely enthusiastic about our position and opportunities. Beyond bringing Daniel Boone on production performing select recompletions, we are actively building and evaluating a pretty robust prospect inventory. For the use of our seismic teams of geocientists and specialized knowledge of the basin, we now have over 160 prospects in various stages of development of which about two-thirds are held by production. Some are AFE ready while others are working towards that end. That's an increase of about 30 since year-end 2008.

In 2010, we will focus on projects that target oil reserves basically because economics dictate that we do so. While our capital budget for 2010 isn't finalized, what I can say is that as usual, we plan to grow with cash flow and cash on hand. We will stay flexible and attentive to the best opportunities. If nothing else, the last 18 months reminded me that discipline, patience, and timing are key elements to our success.

Our strong and growing cash position gives us lots of options. I like these so-called down times because they always seem to allow for growth opportunities at reasonable pricing. Timing is always the question and while we are working to get that right, our growth profile can appear lumpy. Absent an acquisition before the end of the year, crude reserves will go down, but at less than what many would consider an average decline rate for the Gulf of Mexico. Believe this, W&T has substantial cash and credit, we will and are taking advantage of our liquidity. There are acquisitions out there that we could have made if we had been willing to pay a higher price but we didn't believe the economics make since. In other words, we know what those prices are and we just don't think they made sense. We still don't.

Suffice it to say that the "bid-ask" gap is narrowing and we expect to have our fair share of success in making acquisitions at reasonable prices. We expect to enter 2010 with more cash, strong oil production, reduced costs, and a lot of good opportunities to continue to grow this Company. This year in particular, we have done a lot of work at evaluating assets and opportunities, both our own and those of other companies. We intend to go into 2010 with a renewed focus on superior operating metrics. As always, we believe that cash is king and our ability to create and build cash flow is our strength.

We'll be glad to take you questions. Operator, if you would, open the lines for Q & A.

Thank you. We will now begin the question-and-answer session. (Operator instructions). Please ask one question and one follow-up question and re-queue for additional questions. Our first question comes from the line of Scott Hanold with RBC Capital Markets. Go ahead.

Yes, thanks. Good morning, guys.

Hi, Scott.

When you look at your -- the inventory you have in the Gulf of Mexico and your plans on potentially looking at other basins and even going on-shore, where do you rank things in terms of where your next best dollar is spent? Where would you really like to focus your capital here over the next, say, 12 months?

That's a really good question, Scott. I wish I had a really great answer for you. We have been looking at different basins not just in the US, but in different parts of the world. The criteria is again cash flow. Whether or not we can do the financing at reasonable rates, what kind of opportunistic drilling and exploitation we can do and whether those properties have been neglected in the past or didn't have enough capital to make them worthwhile.

I would tell you that I've had difficulty getting a cash flow model in shale plays that I think is appropriate. I see a lot of data. We got guys banging on our door to come buy them, but I -- the full cycle economics still appear to us to be $6 to $7 and, yes, maybe you can go out and hedge it for something close to that, but it appears that you're just spinning your wheels on a full cycle economic basis, so I would tell you that shale plays, unless there's something really peculiarly good about them, such as a little more liquids in them, aren't the top priority for us. It doesn't mean we wouldn't do one or get involved in a play if I could see full cycle economic return, but that's where I pause because I just don't see the full cycle economic return on that.

People talk about drilling -- finding drilling costs, drill and evaluate costs, but rarely do I see all costs quoted on the shale plays. It's a real tough go so far. So I would just -- that's a lot of talk to tell you that that's not my top priority, and having said that, I'll qualify that with saying, if it shows up and it makes sense, then of course we would do it, probably more in the form of a joint venture than going out and make the acquisitions, start a drilling team and ramp up.

Beyond that, we have looked, certainly, around the Gulf Coast and in other parts of Texas and mid-continent, gosh, we have looked overseas, in places where we have rule of law. I haven't looked too much in Canada, not that I'm opposed to doing business in some places that has rule of law, but just because the opportunities really hadn't presented themselves to us. We have looked at some things south of the border that have some appeal. We have looked at more conventional plays that may require some horizontal drilling.

Okay. So if I'm hearing you right, and correct me if I'm wrong, to keep -- get the growth engine moving again, you all think you need to look for acquisition opportunities and just relative to your core asset base you currently have, what do you think you could do with just your core asset base?

The core asset base, we see a lot of opportunity in the Gulf of Mexico. The difficulty that we have seen is that "bid-ask" is still a little bit too wide. Some of the data rooms we have been into, we look at the reserves, and our numbers just come out different. It's not necessarily a Gulf of Mexico specific ,but there are a lot of packages floating out there.

We expect to see some more, as I told you -- or as I told everybody in the last conference call -- as these hedges start rolling off for everybody, those opportunities will increase and, in fact, we are starting to see that it's an intuitive thing to tell you that, we have been here before, we have seen this. We think that things are going to start landing in our lap here pretty quick, that we will require somebody that can move quickly and efficiently to close. Gulf of Mexico is always our bailiwick and it has been. I like it because it has a great cash flow. The biggest thing you have to worry about is where you're going to deploy your cash next.

You really didn't mention much about the Deep Water Gulf of Mexico in that. Is that something that we could see you guys do?

Again, that's a -- the short answer to that is yes, but, again, it's a function of finding something that has production associated with it.

Understood. Appreciate it. Thanks, guys.

Sure.

Thank you. Our next question comes from the line of Neal Dingmann with Wunderlich Securities. Go ahead.

Good morning, guys. Good quarter. Say, Tracy was wondering where do you think now, as you generally have a pretty good opinion on rig and service cost and based on where they are and where you think they are headed in the next quarter or two, would you become more aggressive and start contracting anything near term?

That's a great question, Neal. Thanks.

It seems to change every week. We are looking at our budget right now. Assuming that costs stay about where they are, I would certainly tell you that I don't think we will see a whole lot more drop in service costs. You may see some, depending upon what kind of winter you have here. It really is weather dependent, again, and the big question, as you know, is "what are gas prices going to be?". I see all kinds of different predictions. I wish I knew. If I just knew it one day in advance, life would be pretty good, but I haven't figured out how to do that yet.

The bottom line is that rigs, the operating costs for the rigs themselves has certainly dropped some from what it was before, so even though you have seen drops in jackup rigs, that possibility exists for those rig costs to go down. I wouldn't expect it to be too much more. We are getting into winter right now wherein activity levels normally drop off on rigs because of weather considerations in the Gulf.

Believe it or not, we do tend to lower the activity level in the Gulf of Mexico because of winters rather than summers. But the truth is that right now I don't expect to see a whole lot of price change unless we have a warm winter and you could see some -- if things stay static, I think you'll see a normal pickup in rig activity early in the year. People talk about putting equipment to work, but, you got to temper that a little bit with where everybody's hedge positions have been during the year. What we see is a lot of talk and not a whole lot of action just yet.

Got you. And then question, differentials look just a bit wider on the gas side. I was wondering either for yourself or Danny on a go forward basis next quarter to what are you suspecting there and has that changed here recently or do you suspect that to change?

Go ahead. I'll turn that over to Danny.

We have seen differentials narrow on the gas side, and we internally are modeling a little bit narrower differential. As we get into the -- into next year, it may be an aberration for all we know, just, we have seen a lot of pressure on the cash prices at the hubs and so not real sure. It's definitely different than what we have seen historically so, Neal, we are just -- we are not ready to give an answer on that yet, I guess is what I'll say.

But, I mean, it was apparent on this last quarter that they did change a bit on that third quarter versus what you had historically seen?

Absolutely, they did.

Okay. And then just last question real quick. Tracy, are you pretty comfortable now after the last divestures that you're pretty set now on the core properties that you're sitting with or could we possibly see a little bit more on that aspect?

Yes, I mean, we are looking at our portfolio all the time, Neal, and as prices change and as fields decline and become more non-core, then we are constantly looking at that, and, of course, we do have part of our A and D function as a team looking at those opportunities for us all the time. Right now, I'm certainly seeing more activity toward buying properties than I am disposing of them.

Thanks, guys.

Thank you. And our next question comes from the line of Richard Tullis with Capital One Southcoast. Go ahead.

Thank you. Good morning.

Hi, Richard.

Getting back to the divestitures, could you give us what the year-end '08 proved reserves were associated with those properties disposed of?

Year-end '08. I'm not sure I had that right off the tip of my hand here, Richard. I'm sorry. I just don't recall.

All right. That's fine. And I think you said it represented, what, around $20 million a day?

25.

25?

Equivalent.

Okay. How much P&A was associated with those properties?

$67 million is what we have said.

I'm sorry?

I think we said $57 million.

Okay.

I've got it (inaudible)

Okay. Going back to 2010 outlook, I know, it's early --

$53 million.

$53 million, Richard.

All right. Thank you. And that's not captured in your 3Q ARO in the balance sheet?

No. It is not.

Okay. I know you talked just a little bit about 2010, it's early in the process at this point, but assuming no acquisitions, what production growth or outlook do you think you would have, assuming no acquisitions for next year?

Well, if you assume no acquisitions and no increase in drilling activity, then, of course, you would expect it to go down. That's one of the things that we are looking at right now, is how much do we think we can reasonably increase our drilling position. A lot of the prospects that we have aren't oil. So we are focusing more on oily prospects, primarily because of the difference in parity with oil and gas.

So I guess the long story for your short question is, absent acquisitions and absent an increase in drilling, we will go down, so the question is how do we balance that with the drill bit. We don't have that complete answer yet. We are working on it. Assuming the prices are about the same and prices continue to hold up strong for oil, well, that's going to influence our decision on how much drilling we do.

Okay. What percentage of your prospects are oil?

They are mostly oil.

Okay. You know, looking at the big picture, what would prevent you from getting pretty aggressive drilling next year for oil given the current prices and the drop in service cost over, say, the last year?

What prevents me if oil stays the same and price -- and service costs stay the same?

Yes.

Well, there's -- the only thing that prevents us from other activity is going to be a look at any kind of geopolitical or government changes, regulatory changes that might affect us.

Okay. Okay. I got you.

Those are always -- those are always concerns. I think that -- I really think that the price of natural gas is -- will have an effect on what everybody does for 2010. Again, we keep telling everyone that hedges rolling off will have a definite effect on the market. I'm not sure that the market has felt all of that yet.

Okay.

I'm not sure that, you know -- I certainly don't think that production has peaked onshore for gas yet. So until that changes, that's going -- the onshore gas prices, I just don't see a whole lot of change, but, again, that's going to be weather and geopolitical affected.

Okay. And just finally, on reserves for year-end '09, barring no acquisitions, I know you talked about it going down. What sort of range are you thinking about there?

I hadn't given a range yet but certainly I think it would be less than our normal decline rates in the Gulf of Mexico.

Okay. Well thank you very much. Appreciate it.

Thank you, sir.

Thank you. Our next question comes from Phil McPherson with Global. Go ahead.

Hello, Phil?

Can you hear me?

Yes, I got you now, Phil. Can you hear me?

Yes, yes. Can you tell us the split on oil and the gas of that 9% of the production that you divested?

The split on oil and gas, what was it? About two thirds, one third oil/gas.

Two thirds oil, one third gas?

One third oil, two thirds gas.

Got you. Got you. And that was really the only question. I think all the others ones have been answered so nice work on the quarter. Appreciate it.

Thanks, Phil. I appreciate it.

Thank you. And our next question comes from the line of Noel Park with Ladenburg Thalmann. Go ahead.

Good morning. Just had a few things I wanted to run by you. Well, I guess just starting with what you're talking about as far as the "bid-ask" spread narrowing a bit on potential deals, just interested to hear what you attributed that to, whether it's working capital constrained or people getting less optimistic on long-term prices? And, also as far as the pace of deals that you've seen or potential deals that you've seen, how has that sort of ebbed and flowed over the course of the year? We began the year in the depths of the credit crisis and so forth.

That's a pretty comprehensive question. Let me see if I can give you a little insight in what's happened historically. Whenever you have a rapid decline in prices for commodity prices, there's always the sticker shock type of effect where people look at their portfolio and say, "well, gee, you know, it was $145 this time last year and, you know, it's still worth a lot of money" and, yes, that's true. And maybe they have hedges in place that affect their thinking. Maybe they have different considerations, financial considerations. We see generally a lot more activity in the third and fourth quarters of every year because people take a look at their balance sheets and figure out what they think they need to do in the way of divestures and what not. So there's some of that.

Some of it has to do with continuing strength in oil prices and continuing weakness in gas prices. So depending upon whether you're oil rich or gas rich will also affect what your thought is about selling reserves and also your production. So a number of things affect people as to how they look at their portfolio and what they want to sell and what they want to do. What we do see, we do see some gaps out there with regard to people that want to move into shale plays and now they are faced with the idea of having to pay for it and afford it. So that lends itself perhaps to selling some other reserves that are more conventional.

That's one of the things that we see, and that's kind of a catchall for several different companies, "well, you know, we are going to go into shales and, but here's how we are going to finance it, either we sell equity or we sell assets or both." So it's come along that way, but I think that some of it's driven by fact that, we are just not making as much money as we were before and how are we going to pay for the rest of our program.

Great. That's really helpful. On the natural gas side with the assets, and I'm sure on the oil side it's a lot easier to have an interesting conversation with folks on those assets. On the gas side, with the prices being weak, are you at all drawn to save projects that -- where you might be buying PDPs with just a fair amount of good upside there or would you more likely stick to something that you just thought was gassy, but very promising on the exploration side?

Well, the priority is always cash flow. That's never changed and I don't think that will ever change for us is cash flow. We always look at cash flow first. Reserves are important, but if you can't get them economically, it doesn't mean anything. In fact, it means something bad. But, no, I don't see that looking at conventional plays or shale makes any difference. I think the priority is to try to figure out for us what full cycle economics are.

I take a little bit different view maybe than some other companies because I have a fairly large stake in the Company itself. A lot of stock. We try to look at projects from cradle to grave and figure out what that return might be, and we kind of prioritize along those lines, so it makes it a little more difficult for us to go out and buy a whole bunch of PUDs and a whole bunch of probables and possibles that you have to go out and drill for, particularly on the gas side wherein you have a lot of unknowns as to what pricing is.

Now, yes, you can sit there and you can hedge it and you can hedge it for a period of time, but if it's a 40-year life project and you can only hedge it reasonably for three or four years max, then you still got a lot of unknown out there for full cycle economics, and either you go in and you buy it and you drill a bunch and you sell it to the next guy, then that's what you're faced with and there are people that employ that model and do quite well at it. That's not what I would say flipping properties is not necessarily our core strength. I think making money for the properties that we have is more of a core strength for us.

Great. And just on the prospects, did you say 160 prospects with 100 held by production? Did I get that right?

Yes, about that, yes, about 160 prospects with about 100 of them HBP. Yes, that's about right.

Okay. Great and also if you could refresh my memory, Daniel Boone, is there further development slated for the field?

Not at this time.

Okay. And also I wanted to ask about Mahogany Deep. Gas prices, of course, are down but I was thinking about service costs being down as well.

Service costs are down. Drilling rig costs are down. We are continuing to look at that. I'm not sure that that will be on the budget for this year. But it might. It might show up.

I'm just not sure, we haven't finished strategizing for 2010, but I expect that right now it's still a little bit tough with -- you have to realize you got to use a pretty premium drilling rig and those costs have gone down, I'm not sure they have gone down proportionally.

Oh, I see. That's it for me. Thanks very much.

Great. Thank you, sir.

Thank you. (Operator Instructions). Our next question comes from Biju Perincheril with Jefferies & Company. Go ahead.

Good morning. Trying to get a little more color on your prospect inventory. If you considered the projects that you have drill ready going into 2010, let's say if oil prices hang around this $80 level, how many projects can you -- how many prospects can you drill next year if you're not in a cash preservation mode?

If I'm not in a cash preservation mode?

Well, if you're not preserving cash liquidity for a potential acquisition and if you are ramping up activities, how many projects can you drill next year?

That's the question we are trying to answer right now, Biju, and that's going to be a function of what we think the cash flows will be for 2010. We haven't quite got to that answer. We expect that we will -- around January we will come out with a more public statement on that.

Let me ask it in a little different way. If you're just looking at just the economics of the projects on a stand alone basis, at an $80 oil price, what is your inventory, regardless of whether or not you will go after those projects in 2010?

I'm sorry, sir, you've asked me something I just don't know how to answer at this time. We are running different sensitivities for our projects, but as for a specific price, I'm not sure I can really give you an answer at this time.

Okay. Okay.

The prospects that we have are, indeed, prospects; they are all going to be as any drilling program would be sensitive to what you think the cash flows are, so we will have -- the way we normally do it is we come up with a range of what we think pricing could be and we try to figure out what we think is a best choice for that and then we, like anybody else, we adjust for it as conditions change and warrant.

Okay.

Just haven't got it quite ready for 2010. I wish I could give you a better chance ahead of time, but I just don't have that answer yet, sir.

Okay. Let me see if I hear you correctly. Let me say -- let me know if I'm completely off base here, the reluctance at this point you ramp up activities in 2010 is you're weighing the options of potential acquisition opportunities opening up and having the liquidity for that versus returns on your existing projects? Is that fair to say?

You know, we always balance that and that's -- that's a fair statement. We don't budget for acquisitions so when we look at the budget, we look at it, we say, "well, we can't predict acquisitions, so we are going to try to look at our budget as if we won't have any acquisitions."

We do understand that we feel like we are going to have some and hopefully next year that will happen and if it does, then we will manage it accordingly, but because we drill within cash flow, that gives us an advantage. Drilling within cash flow is very important because it means you don't borrow money to drill and we don't take away from our credit facilities in the event that we do have an acquisition.

Got it. Okay. Thanks.

Yes, sir. Thank you.

Thank you. And Mr. Krohn, there are no further questions at this point. Please continue with any closing comments.

I think we are done. We appreciate you interest and participation this morning. We will have more for you next time. Thanks so much.

Thank you. Ladies and gentlemen, this concludes the W&T Offshore third quarter earnings conference call. If you'd like to listen to a replay of today's conference, please dial 303-590-3030 with access code 417-3824. ACT would like to thank you for your participation. You may now disconnect.