W&T Offshore Inc (WTI) 2007 Q3 法說會逐字稿

Good morning ladies and gentlemen and thank you for standing by and welcome to the W&T Offshore third-quarter earnings conference call. At this time, all participants are in a listen-only mode. Following the formal presentation, instructions will begin for the question-and-answer session. (OPERATOR INSTRUCTIONS). As a reminder, this conference is being recorded today, Wednesday, November 7, 2007. At this time, I would now like to turn the conference over to our host, Mr. Manny Mondragon, who is the Vice President of Finance. Sir, you may now begin the call.

Thank you, operator, and good morning to everyone. We appreciate you joining us for W&T Offshore's conference call to review the third quarter 2007 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 distribution list to receive future news releases or you experience 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 web cast by going to investor relations section of the Company's web site at (technical difficulty).

Thank you, operator, sorry about that. As we were saying, today management is going to discuss certain topics containing forward-looking information which is based on management's beliefs as well as assumptions made by and information currently available to management. Forward-looking information includes statements regarding expected production and expenses for 2007. Although management believes that expectations reflected in such forward-looking statements are reasonable, they can give no assurances that these expectations will prove to be correct.

Such statements are subject to certain risks, uncertainties and assumptions, including among other things, market conditions, oil and gas price volatility, uncertainties in shares in oil and gas production operations and estimated reserves; unexpected future capital expenditures, competition, the success of risk management activities, governmental regulations and other factors described in the Company's most recent annual report on Form 10-K and subsequent filings with the Securities and Exchange Commission. Should one or more these risks materialize, or should underlying assumptions prove incorrect, actual results may vary materially from those expected.

Please also note that this conference call contains references to non-GAAP financial measures. You can find reconciliations of these non-GAAP financial measures to GAAP financial measures in the Form 8-K filed by the Company earlier today, as well as in this morning's press release. Now I would like to turn the call over to Mr. Tracy Krohn.

Thanks, Manny, and good morning. Hopefully the phone line will stay up and we'll continue this quarterly conference call. Again, thanks for joining us for our third quarter 2007 conference call.

This morning, I'm going to discuss events that took place in the third quarter of 2007. With me is our team, Danny Gibbons, our CFO, who's going to review financial results for the third quarter of 2007; and Steve Schroeder, our Chief Operating Officer, who will discuss production operations, third quarter drilling projects, lease operating expense and also give fourth quarter guidance. Then, he will turn it over to Jeff Durrant, our Senior VP of Exploration Geoscience. Jeff is going to review our current drilling program and our drilling program going through 2008. Following the formal presentation, we will also have a Q&A session. So let's begin.

Our third quarter adjusted earnings per share were $0.53, beating the street estimates of $0.31. Many factors can explain the differences, such as the fact that we hit the midpoint of our production guidance, but the street had perhaps anticipated slightly lower production and had a lower realized price than what we actually realized. The market tends to believe Gulf of Mexico companies are gas-oriented and tends to forget that we, W&T, are about 34% liquids in the ground and 42% liquids production. Because W&T's mix of oil and liquids is higher than most Gulf of Mexico E&P companies, our overall realized price was likely higher than anticipated by the street.

Our adjusted EBITDA margin in the third quarter was 73% and moving back in line with our historic average in the 78 to 80% range. You know, many in the investment community look favorably on plays with repeatable results, such as resource plays, but they don't really think of the Gulf of Mexico in those terms. I believe that our track record for achieving very attractive EBITDA margins on an ongoing basis is indicative of our ability to repeatedly achieve attractive margins and high cash flow. In fact, I think you'll find that our EBITDA margins are consistently exceeding those of most companies that focus on natural gas resource plays in the U.S. with the added benefit of high cash flows.

I would characterize the third quarter as a quarter of blocking and tackling, i.e., basics -- just producing reserves and preparing to begin a pretty significant drilling program. This quarter, we focused on the fundamentals gaining ground in steady increments and setting us up for bigger and better things to come. The good news is that we met or exceeded positively all of our guidance numbers. Danny and Steve will be discussing this shortly, but base LOE was lower than guidance. This was primarily due to fewer workovers and reduced facility expense. Our LOEs associated with hurricane remediation came in lower than guidance as well.

Our gathering, marketing and transportation and production taxes expense was lower than guidance due to two of our (technical difficulty) in state waters, (inaudible) and [24-L] coming on in the fourth quarter versus the latter half of the third quarter, and therefore not impacting third quarter expense, as originally projected.

As anyone who has heard me say in the last call, we are ramping up our drilling program. From the time of our last announcement we believe that we will drill up to 50 wells by the end of 2008, and 10 of those 50 could be drilled or drilling by the ended of 2007. We currently have two rigs on location and have begun that program in earnest. As we said numerous times before, it takes about two years to properly evaluate a large acquisition, get our hands around it, especially the one the size of the Kerr-McGee transaction. And in 15 months since the closing of that transaction, I think we are on if not ahead of that schedule. In our 50-well program, 27 wells are identified to be drilled on the former KMG properties. Steve and Jeff will go into much more detail on that later in the call, but I just wanted to know that it has begun and we should be announcing some results soon. As I've said before, many of these wells will be drilled from platforms, so we can see them drilled in bunches and see production impact shortly thereafter.

Concurrent with the launching of our drilling program, our 2008 budgeting process is underway. Our various teams have been meeting to develop the projects and costs associated with those projects for 2008 consideration. The Board of Directors will review the proposed budget late in the fourth quarter and we will be in a position to announce something at the beginning of the year. But so far, I am pretty encouraged, very encouraged by what I have seen, and by the spread of prospects on both the KMG and W&T heritage properties. I'm also pleased about costs going into 2008, particularly jackup rig rates. I believe that for the most part, our costs have really come down for the types of drilling rigs that we'll use in our drilling program and we are hopeful that this trend will continue.

As rig rates come down, the cost of other goods and services, including transportation costs come down as well, and that is extremely encouraging as we look forward into 2008.

With that, I will turn it over to Danny Gibbons to expand on our financial results.

Thanks, Tracy. Let me begin with revenue. Revenue increased $41.8 million or 20% to $255.2 million in the third quarter of this year due in large part to an increase in production from the properties acquired by merger from Kerr-McGee.

For the third quarter of 2007, our realized natural gas price averaged $6.45 per Mcfe and crude oil and condensate averaged $72.72 per barrel for an all-in average realized price of $8.83 per Mcfe. This is $0.69 per Mcfe higher than the third quarter of 2006. In addition, the average realized price we received in the third quarter of 2007 of $8.83 per Mcfe was higher than last quarter of $8.74 per Mcfe. Net income for the third quarter of 2007 was $36.3 million.

Earnings for the 2007 period reflect the impact of a $6.4 million unrealized derivative loss, or $4.2 million after tax. The 2006 period included an unrealized derivative gain of $22.7 million. Excluding the unrealized gains and losses from both periods, earnings per share for the third quarter of 2007 would have been $0.53 per share compared to $0.71 per share for the 2006 third quarter.

Moving onto lease operating expense, lease operating expense for the third quarter of 2007 was $51.6 million. This is versus $35.2 million in the third quarter of last year. LOE per Mcfe in the third quarter was $1.79 compared to $1.34 in 2006. The increase of $16.4 million is attributable to increases in operating costs of $13.2 million, major maintenance expenses of $2.5 million -- $1.8 million of that is related to hurricane remediation -- and we had $1.4 million in higher insurance premiums. This is all partially offset by a decrease in workover expenditures of $700,000.

Approximately $7.8 million of the increases in operating costs are associated with properties acquired by merger in the Kerr-McGee transaction. Amounts spent in 2006 related to hurricane remediation efforts were covered by insurance, and therefore are not included in lease operating expenses.

During the third quarter of 2007, certain industry-related reimbursements for overhead expenses from joint interest owners have been reclassified from lease operating expense to G&A in order to better match the underlying reimbursement with the actual cost recording. All prior year amounts have been reclassified to conform with the 2007 presentation.

Moving onto depreciation, depletion amortization and accretion, which we refer to as DD&A, that was $123.1 million in the third quarter of 2007 representing an increase of $37.6 million over the comparable period of 2006. On an Mcfe basis, DD&A increased to $4.26 from $3.26 last year. The increase primarily reflects increases in finding and development cost and higher production volumes.

Moving onto cash flow, net cash provided by operating activities was $472.7 million for the first nine months of 2007. That is over a 34% increase versus the same period in 2006. Adjusted EBITDA was $567.6 million for the first nine months of 2007, up 31% over the comparable 2006 period. Our adjusted EBITDA margin was 73% for the third quarter and 72% for the nine months, getting back in line with our historical margins.

Moving on to general and administrative expenses, for the third quarter of 2007, G&A increased to $9.9 million from $8.8 million for the third quarter of 2006. This is due to an increase in the number of employees and therefore greater compensation costs and benefit costs, higher legal and professional fees and a termination benefit under an employment contract in 2007.

On an Mcfe basis, G&A was $0.34, and that was flat with the third quarter of last year. Again as a result of the reclass, amounts presented on the income statement line items for 2006 period have been changed to conform with the current classification.

Moving onto interest expense, interest incurred increased to $14.3 million for the third quarter of this year from $9.9 million for last year's third quarter primarily due to the fact that the debt incurred in connection with the Kerr-McGee transaction was only drawn for a little more than a month that quarter versus being drawn at full quarter in 2007. During the quarters ended September 30, 2007 and 2006, $6 million and $4.1 million, respectively, of interest was capitalized unevaluated oil & gas properties.

Now moving onto income tax expense, income tax expense was $18.8 million for the third quarter of 2007 compared to $35.4 million for the same period in 2006, primarily due to lower pretax income. Our effective tax rate for the three months ended September 30, 2007 was approximately 34%, and that reflects the utilization of the deduction attributable to qualified domestic production activities under Section 199 of the Internal Revenue Code. Our effective tax rate for the three months ended September 30, 2006 was approximately 35%.

Moving onto capital expenditures, for the first nine months of 2007, capital expenditures were $277.3 million, and that's before dispositions of $3.7 million. Of the $277.3 million, $162.3 million of that was spent for development activities, $71.6 million for exploration and $43.4 million for seismic, leasehold costs and other capital improvements. During the nine months ended September 30, 2007, development and exploration capital expenditures consisted of $98.7 million spent in the deepwater, $34.5 million on the deep shelf and $100.7 million on the conventional shelf and other projects.

At September 30, we had $187.8 million in cash and cash equivalents and $655.2 million in long-term debt. Our debt to total book capitalization ratio stood at 36.6%. However, net debt, which is debt less cash, to total book capitalization was 29.2%. Obviously we're in great shape financially.

I would also like to point out that, yesterday, we closed on an amendment to our bank credit agreement that increases our borrowing availability from $300 million to $500 million. The amendment was done in connection with the semiannual redetermination of the borrowing base. Please note that no amounts were outstanding under the revolver, and therefore, the full amount is available for future opportunities.

And with that, I will turn the call over to Steve Schroeder to discuss operations. Steve?

Thanks, Danny. During the last conference call, we discussed our expected buildup in the late third and fourth quarter. That buildup has occurred, and here is an update on the status of several key projects. In August, our Pluto 2 well was shifted to a new completion remotely using smart well technology. The well peaked at approximately 40 million cubic feet equivalent per day gross, or 18 million cubic feet equivalent per day net to W&T's interest. At our Bay Junop prospect, we received the necessary permits and installed all equipment. In October, we initiated production and are currently producing 13 million cubic feet equivalent per day, net. At our two Highland 24-L discoveries, the main processing structure was set and all pilings were completed. Initial production began in October and the wells are currently ramping up. Our current production is approximately 9 million cubic feet equivalent per day net.

All of the final tie-ins and commissioning work was completed at the third-party processing platform in October for our South Timbalier 299 project. We have been ramping up production from the four completions and are producing over 600 barrels of oil per day and 20 million cubic feet per day gross, or 9 million cubic feet equivalent per day net to W&T's interest.

In the third quarter, production averaged 314 million cubic feet equivalent per day. Current production is ranging between 320 and 330 million cubic feet equivalent per day.

We have been extremely busy with our recomplete and workover programs. During the third quarter, we performed 20 recompletes and workovers with 90% of the operations adding production. 12 of the projects were in former Kerr-McGee properties as we begin to exploit unutilized well bores. Of the aforementioned projects, W&T engineers and geologists generated two-thirds of the recompletes.

While the explorationists have been developing our future drilling plans, our exploitation teams have been actively pursuing other opportunities to add production, and therefore cash flow. As Tracy stated earlier, we're gearing up our drilling program and expect 2008 to be a busy year. Currently, we're drilling a semisubmersible rig and a platform rig and just released a [mat] cantilever rig. We project that we may be running between four and seven rigs by the end of this year. The types of rigs we will begin utilizing include platform, submersible, mat cantilever, independent leg jackup and a semisubmersible that is already under contract.

I am pleased to know that base LOE for the third quarter was $49.8 million, $1.2 million under the low-end of guidance, and hurricane remediation costs of $1.8 million were below the low-end of guidance as well. I'm happy to report that for the second quarter in a row, we had minimal well failures. The workovers we did have were mainly outside operated wells with minimal expenditures. Hurricane repairs were $1.8 million, or $1.2 million below low end of guidance and I believe the majority of the repair work is behind us and there is light at the end of the tunnel. We've completed the significant repairs a both our East Cameron 338 and Vermillion 226 facilities and currently bringing these properties back online.

To reflect our successes of beating or hitting the low end of our operating expense guidance in the second and third quarters of 2007, we have lowered the high side of our full-year guidance downward as is shown in this morning's release. For the fourth quarter and full year, we are not changing production guidance. While we recognize that there is some room in the guidance range, we believe there are a few factors that could stretch that range. The largest component is exploration success. We have not specifically added any exploration wedge, but believe there could be some upside if we complete several projects that Jeff will discuss shortly, such as the work being done in the Ship Shoal area.

Now I would like to turn the call over to Jeff Durrant to update you on our drilling program.

Thanks, Steve, and good morning to everyone. During the third quarter, we successfully completed the drilling of one exploration well, the B-3 Sidetrack and South Timbalier 41 field, and thus far through the third quarter in 2007 we were successful in all three exploration wells, two development wells and the deepening of the Healey No. 3. As I will discuss in a moment, so far in the fourth quarter we've had an initial indication of gas in our first Ship Shoal 300 well, but unfortunately, we've also drilled an uneconomic well in Main Pass 162.

Turning into the B-3 Sidetrack deep shelf discovery well in South Timbalier 41, we found 70 feet of oil and gas in five sands. We cased off this section of the hole and drilled ahead to test deeper exploratory objectives to a total measured depth of 18,814 feet, which is about 17,000 feet of a true vertical depth. We then completed to the well's main objective the Q-8 sand. This zone came on at a gross rate of 18 million cubic feet of gas per day and 1900 barrels of oil per day, or about 6 million cubic feet of gas per day, 630 barrels of oil per day, and that is net to W&T.

Now let me update you on our current exploration drilling program activity and give you an early look at our plans for the first part of 2008. In the deep water, we have positioned the Lower [Bossagard], the semisubmersible and re-entered the Healey 4 prospect in Green Canyon 82. You might recall that eddy currents forced us to move off location in June, but not before we (inaudible) [set] 22-inch casing at 3920 feet. This depth is approximately 600 feet above the first of four independent exploratory objectives in the well. The wells plan to go to 14,430 feet measured depth, or a little more than 14,000 feet of true vertical depth and should be finished drilling by year end.

Over on the conventional shelf, we just finished drilling the A-3 well in Main Pass 162. This 67% W&T working interest well is drilled at 12,188 feet and did not find economic quantities of hydrocarbon in the well's main objective (inaudible) section. Our share in the cost of the well is approximately $7.3 million.

We still have extensive drilling plans though for the Main Pass area that are designed to test areas independent from the Main Pass 162 block, including an open water [James lime] exploration well in [Viascanol] area for a total of about three to five exploration wells. This program is expected to begin before year-end and [we'd] like to continue to at least the first and second quarters of 2008.

Further west in the Central Gulf conventional shelf, we're actively drilling a three-well program off the A structure in Ship Shoal 300, while working interest areas from 75 to 100%. The first two wells, the A-1 Sidetrack and the A-3 Sidetrack, are designed as horizontal wells to exploit a shallow gas reservoir at about 2200 feet. The first well has been drilled down to 3621 feet and has built to an 87-degree angle with a logged gas show at the top of the sand. Pacing has been set at this point prior to drilling that. Plans are to drill the second well to a similar casing point before drilling 500 to 1000 feet of horizontal section, which should maximize reservoir connectivity and achieve higher gas production rates.

The third well in the program targets deeper oil and gas condensate sands that hopefully will be drilled and completed by year end. And also in this field, we anticipate using a jackup to drill a two-well exploration program from the Ship Shoal 315-A platform. These two wells will target an oil sand and a rich gas condensate sand, and this program should begin by mid-November and carry through the first quarter of 2008.

So that, in total for the Ship Shoal area, including these wells and other proposed Ship Shoal area drilling, we plan to drill nine to 12 wells in the fourth quarter of 2007 and the first and second quarters of 2008. And since nearly all of these wells will utilize existing infrastructure, we should see immediate production results.

Our last plan in 2007 drilling is in the High Island area deep shell exploratory well. This well is located near our recent Highland 24 discovery and is planned to test a similar lower Miocene age objective section. This well should begin drilling by late November to a proposed total depth of approximately 15,589 feet. And with that, I will turn a back to you, Tracy.

Thanks, Jeff. During the third quarter and thus far into the fourth, we have refocused on the basics, getting production online, cost containment and preparing and beginning our upcoming drilling program. Some of our much anticipated production is now online -- Bay Junop, Highland 24-L, South Tim 299, Cap Rock and others. Now production is up. I'm happy to see that we have two rigs working, including the one that we'll finish drilling, our Green Canyon 82 Healey deepwater well.

With the layer of long-term debt now in our capital structure, it has freed us from focusing on short-term debt repayment to focus on our longer-term strategy of drilling and production which is clearly a much better use of capital and time. We're in the middle of our budgeting process and our team us putting together a program that I'm sure both you and I will be pleased about. I am anticipating an announcement just after the new year.

We've executed our strategy of reducing and restructuring debt, getting our arms around the Kerr-McGee transaction and assimilating the necessary geological, geophysical and engineering data to explore and exploit not only the Kerr-McGee properties, but by virtue of newer (inaudible) seismic data, also to better explore and exploit legacy properties. Corporate liquidity has never been better. And although we expect to manage our drilling program within cash flow, we are seeking additional reserves through acquisition where we see good value. More specifically, when we find good value in acquisitions, we intend to take advantage of those opportunities as we always have, but we have the luxury through good planning of being able to be very patient and continue to execute our drilling program into the future.

With that, I will start to take questions. Operator, please open the phone lines for Q&A.

(OPERATOR INSTRUCTIONS). Neal Dingmann, Dahlman Rose.

Good morning, this is Jason Wangler for Neal. I'm just wondering, you kind of laid out a pretty good activity as far as well drilling going into '08. Are you looking to get anymore rigs during that time, or are you pretty set as far as your rig count right now?

Good morning, Neal (sic). The short answer to that is yes. We are looking to get more rigs, primary to jackup rigs and platform rigs.

And then just one other question is just your costs are starting to move down a little bit now that the Kerr-McGee is behind you. Do you see that going forward a little bit more, or is that kind of all the way through? And will we see it pretty much stabilize at where it's at?

That's really a tough question to answer. I think that, intuitively, I think yes, but again, that's going to be a function of commodity pricing going forward and rig availability. And again, the driver in that market is always drilling rig cost, dayrate cost, and also how many workovers that we'll end up doing, not only for our own account, but that come to us through outside operated events.

Last question. Do you have enough infrastructure already for the next 50 wells going into '08, or is there going to have to be more built up?

The short answer to that is yes.

The short answer is yes? Okay great, I will turn it back.

John White, Bleichroeder.

I understood your 50 -- drill 50 wells between now and the end of 2008. Could you tell me again how many you plan to have drilled by the end of '07? I missed that.

Actually, what I said, John, was from the date of our last announcement, which was our last earnings conference call. It just really is a function of how quickly we can get wells on -- rigs on location. But I expect that we'll have about 10 either drilled or drilling additionally what we've drilled so far by the end of the year.

Okay, thank you. And on the B-3 at South Tim 41, I missed your net share of the production.

The well was making around 18 million cubic feet a day net, and several hundred barrels of liquids a day net. I don't have that net number right in front of me. I'm sure we'll get it, hold on just a minute. About 7800 about -- I'm sorry -- about 7000 -- 7.8 million cubic feet a day, net.

Okay, well that is a really nice well and really nice results. I appreciate you taking the questions.

Richard Tullis, Capital One Southcoast.

Congratulations on a real nice quarter. Two quick questions for you, Tracy. I know you had a nice percentage of your total production with oil in this quarter. How do you see that going into the fourth quarter and then into the first half of '08? Do you see similar percentages -- 40, 45%?

With regard to liquids?

Yes.

Yes, I do. Our reserve mix was about 45% liquids.

Excellent. Did I hear you correctly, you could have four to seven rigs working by year end '07?

You did, that's correct.

Good. And I guess the last question would be -- what sort of unrisked reserves are you targeting for the fourth quarter with your drills?

That's an excellent question. I don't necessarily have that right at my fingertips, Richard. I know that in our previous announcement, unrisked for that 50-well program, we were looking at about 850 million cubic feet or so unrisked.

That's fine. I could touch back another time. That's that for me today. I appreciate it. Thanks a bunch.

Brian Kuzma, J.P. Morgan.

First question was on the CapEx side. You guys recently raised the CapEx budget, and are you really going to keep that target going forward for 2007? Maybe give us some color as to what that means for your spending rate going forward.

I don't really have an accurate number on that yet. Obviously, we're going to be drilling more wells. We had a lot of development expense at the beginning of this year associated with some of our deepwater stuff. Most of our activity is going to be on the shelf. I don't really have what I would consider to be a good handle on CapEx expense going through next year. Intuitively, you would think that since you're drilling more wells that it would be higher, but I'm not sure that that's necessarily the case because we're drilling more wells on the shelf. And also, the cost of goods and services is going down. So I don't have a great handle on that yet. I just -- it's a little bit premature. We'll have some better answers for you just after the first part of the year. But certainly if rig prices keep going down, cost of goods and services keep going down, that's going to be favorable to us on our total well number and CapEx number going forward.

Sure. So the 50 wells you talked about drilling over that 18-month period, how many of those are going to be deepwater wells?

Two -- one of them at Healey and one of them at another location we have not released yet.

And is that Blackbird well -- is that off the table now, or whatever happened to that?

No comment.

(OPERATOR INSTRUCTIONS). Kevin Wenck, Polynous Capital Management, Inc.

Well, I'm glad to know I'm Polynesia, that's fine. Good morning Tracy, Danny and Manny.

Good morning, Kevin.

The oil production for the quarter dropped about 5% from Q2. If you look at the guidance for Q4, it looks like it could drop another -- I mean, depending on where you end up inn that range, it could drop another 10 to 30%. And so what causes the drop in Q3, and then some more color on the wide range in Q4 for oil.

First of all, I need to confirm your numbers, Kevin, so give me a moment here and I will do that. But intuitively, it doesn't seem to me like it's that large a drop, if it's dropping at all. Our production seems to be going up. So, there is a -- I don't know that our oil production is dropping. I think what you may see is a relative drop as opposed to production of gas since our production is going up. Those mixes may change. But I don't necessarily see where oil production is dropping. As a function total production, yes, that could be true. But I think total production is up.

Sorry, it takes me a minute to look through the various parts of the press release, but it's 2 million barrels in Q3 and a range of 1.5 to 1.9 in Q4. And then, if I have numbers right in my model, it was 2.1 million in Q2. So it's a slight drop from Q2 and Q3, the 2.1 to 2. And then the range that you have given us for guidance in Q4 is 1.5 to 1.9.

Okay. The total production is not dropping. Oil as a function of total production is dropping somewhat. Probably more in line with the fact that we are bringing on projects at Junop and Highland 24 where we have a larger gas component. I don't know how to predict that for you necessarily because we will be drilling some wells in the fourth quarter, platform drilling, that could come on fairly quickly and going also into the first quarter. So rather than try and predict with a great deal of certainty, because there is none, going into last quarter and first quarter of 2008, I think that will be largely a function of what we actually put online before the end of the year and into the first quarter.

That's one reason why I'm asking the question. Because from other comments you have made on the call, I cannot see oil production dropping at all unless there's some other information that hasn't been shared with us.

Kevin, that is a possibility. Again, I don't know what kind of results we're going to have yet. We've stated that we don't really have an exploration wedge built into it. But yes, that's a possibility. But because I cannot predict it, I really cannot built it into the models.

Because if you end up at the low end of the range, the 1.5, that's a 25% drop from what you just did in Q3. But I haven't heard any other color as to why you're going to have a 25% drop. We'll move onto another thing. The credit line increasing is kind of interesting given your cash flows because you probably should be able to come close to paying off the credit line sometime in the next quarter or two. And so, is there enough stuff out there that could cause you to potentially acquire, that would cause you to want to increase the credit line at this point?

Kevin, we did increase the credit line. We could certainly pay off some debt. I'm not sure that that's the most effective use of capital. It is -- there are a lot of assets on the market right now, and we are in a very good liquidity position to take advantage of that. I told the market that we are a creditor and that we intend to be in that market for a long time. So that's very astute, and now you can draw from that, that we are out beating the bushes looking for value.

Congratulations on the projected increase in gas production for Q4. That's pretty impressive looking at this point. One other follow-up question. For October, what was the realized price for oil?

I don't know that I have an October realized price for oil yet. I don't think I will have that for you for another several days. But I don't think that we would probably normally release that. Reasonable to assume that average realized prices are going up as a function of (MULTIPLE SPEAKERS) production and increase in price of oil.

I thought I would catch you at a weak moment.

Thanks.

John White, Bleichroeder.

Following a little bit on that last question on the M&A activity, how would you characterize the supply/demand situation in the Gulf of Mexico relative to second quarter? Do you think there's more properties on the market or less, or how would you describe it?

Clearly, there are more. Without a doubt, there are more. We -- this wasn't anything that caught us by surprise. We have tried to position the Company to put ourselves -- to have the ability to take advantage of that. Again, we are very patient, John. We're not to go out and buy something just because we feel like we need to do a deal. We don't. We have a very balanced approach. We have a lot of properties to drill up. We have done what we have always done, and this is make value acquisitions that create a lot of cash flow, and that is the point.

Thanks. Is it fair to say that a lot of the oversupply or a lot of the supply is dominated by PDP properties with a very high PDP ratio?

I don't know if it's dominated. There's certainly one or two of them out there that have those kind of characteristics, and that's okay. We like to see upside in things that -- and it doesn't mean necessarily that there is an upside just because there's a lot of PDP, or proved developed. However, as a criteria, we certainly like to see upside in the form of drilling and additional prospects.

Gary Stromberg, Lehman Brothers.

This is actually [Chris Gault]. As kind of a follow-up to the earlier question concerning cash and potential acquisitions, would any of that cash be used for possible share buybacks? I know in the past, you all have said that that was not part of your strategy, but I just wanted to get an update on that.

I was waiting for somebody to ask me that. The truth is that, we certainly could do that. That's not a high priority on my list. One of the issues we've had with this company because insiders own so much of the shares is float. We see plenty of opportunity out there, and you have seen a couple of examples recently with companies, peer group type companies that have repurchased shares, and the results have been mixed. I guess the best thing I saw was about a 20 to 25% pop as a result of a share buyback. To me, we've just got a lot more opportunity. We think that a 20% rate of return is -- if an engineer brought me a project with a 20% rate of return, I would probably fire him. So that is not high on our priority list. I have learned in this business to never say never. However, I never thought we would go public, but here we are. But certainly, that's not high on our priority list. Again, there's plenty of acquisitions out there. It doesn't mean that that wouldn't be something we would ever do, but certainly as we look at it right now that's not the highest thing on our priority list.

[John Malloy], [Sound] Energy.

So Cap Rock -- did that come online in October?

It did.

It did? What did that come on at?

About 18 million a day, and about 1900 barrels of oil a day, gross.

And what is your working interest there?

About 40%.

And Danny, what was deferred taxes for the third quarter?

We have about $92,000 for the whole year.

$92,000 for the whole year?

That's deferred tax expense. Obviously, we have $240 million on the balance sheet, but deferred tax expense, there's just very little as you can see from the statement of cash flow.

Yes, I saw that.

We screwed up and made too much money.

Yes, you guys need to quit that. Okay, great. Thanks guys.

I hope we don't quit it, John, thanks.

That was a joke.

Brian Kuzma, J.P. Morgan,

It was actually just a follow-up on the deferred taxes. (technical difficulty) is ramping up your program, your CapEx program going into the first half of next year. I saw that you guided fourth-quarter deferred taxes to about 10%, but I'm just thinking about more long-term, do you think you will go back to that 80% level based off of increased spending?

Gee, Brian, that's a really good question. I don't have a really great answer for you. It's hopefully in my ideal scheme of things, we would just find so much production that we would be making too much money to worry about it. But the truth is, I don't really have an accurate answer for you. We will be drilling more, so you might assume that you have a higher deferred tax rate. But again, a lot of these things, if they are successful, will come online fairly quickly. I don't really have a good, accurate way to estimate that for any kind of model that you might be building.

Okay. And then, when you look at Cap Rock --.

Actually, we'll have a little better handle on that after we figure out what our budget is going to be for next year as well.

Okay. When you look at Cap Rock, I didn't quite understand -- are you producing from a zone below the 70 feet that you initially found, or is it just the lower-most zone of that 70 feet?

I think it's a lower zone in that 70 feet. Q-8 sand, I believe, is what it is.

Okay so --.

It's a field [pack].

Okay. So are there plans to maybe follow up with additional wells out there or possibly even twins, some of the other sands?

You know, I think there's some more drilling to do out there, but it would be premature to comment on that at this time.

Kevin Wenck, Polynous Capital Management.

Tracy, with day rates dropping and with the type of wells you're currently drilling, what's a rough range for cost per well at this point? I know you have a lot of different types of projects, but -- .

I think really, Kevin, it's easier to look at, rather than a cost per well at a range of reserves. I know we have discussed this in the past. I don't really have an average cost per well for you because it's -- some of them are off-platform, some of them are open water. At least one of them is a deepwater well coming up this year. In fact, we're on it now at Green Canyon 82. So, I tend to think of it in kind of minimal reserve targets. Open water shelf Gulf of Mexico for about the last 20 years has been about 6 Bcf, is kind of a target that we look at. You put a rig on a platform if you're going to drill more than one well, about three Bcf as a kind of a minimal target. And then it can get lower than that, depending on how many wells you're going to drill and how far you're going to drill and what you're -- whether you're going to sidetrack out of an existing well bore. I think you're continuing to see weakness in the jackup drilling market. So I think that as you continue ramp down -- and again, that's going to be very weather dependent -- if we have a warm winter, then I think you will see gas prices lowering. If you have a cold one, then I think you will see them going up. It's still the same as it has been ever since I've been in this business. If you have a seasonal change in weather characteristics during the winter, it really affects it. Bigger over recent years is the fact that the December cooling season has much more of an effect on it than it used to.

Gentlemen, at this time, there are no further questions. Please continue with any comments that you may have.

Okay, that's great then. We appreciate your interest and participation this morning and we'll talk to you the next time. Thanks so much.

Thank you. Ladies and gentlemen, this does conclude the W&T Offshore third quarter earnings conference call. If you would like to listen to a replay of today's conference, please dial 303-590-3000, or 1-800-405-2236. You will need to enter the access code of 11099965. ACT would like to thank you for your participation, you may now disconnect your lines at this time.