W&T Offshore Inc (WTI) 2010 Q4 法說會逐字稿

Good morning, ladies and gentlemen. Thank you for standing by, and welcome to the W&T Offshore, Inc., fourth quarter and year-end 2010 earnings conference call. During today's presentation all participants will be in a listen-only mode. Following the presentation the conference will be open for questions. (Operator Instructions) Today's conference is being recorded March 2, 2011. I would now like to turn the conference over to our host, Janet Yang. Please go ahead.

Thank you, Operator. Good morning, everyone. We appreciate you joining us for W&T Offshore's conference call to review the results of the fourth quarter of 2010. Before I turn the call over to management I have a few items to point out. 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 March 9, 2011. To use the replay feature, call 303-590-3030 and dial the pass code 4400979 followed by the pound sign. Information recorded on this call speaks only as of today, March 2, 2011, and therefore time sensitive information may no longer be accurate as of the date of any replay. Please refer to our fourth quarter 2010 Earnings Release for our disclosure on Forward-looking statements.

Now I would like to turn the call over to Mr. Tracy Krohn, W&T's Chairman and CEO.

Thanks, Jan. Good morning, everyone. We appreciate you joining us for our fourth quarter 2010 earnings conference call. With me today are Danny Gibbons, our Chief Financial Officer; Jamie Vazquez, our President; and Steve Schroeder, our Chief Operating Officer. Other members of management are here for the Q&A session that will follow our prepared remarks.

In short, we had another great quarter, highlight by the acquisition of three deep water properties from Shell, strong operating results and also bolstered by higher production volumes and escalating oil prices. Our production exceeded the high side of guidance and expenses generally came in at the midpoint of guidance. Production for the quarter was 47.6% oil, which really helps us in such a strong crude oil price environment. As a result, earnings per share came in on the high side of analyst estimates. The GAAP earnings were $0.27 per share and, excluding special items adjusted, earnings per share was $0.40 per share. Compare that to the First Call consensus of $0.36 per share.

For the year EPS was $1.58 per share, or $4.09 higher than last year. $4.09 higher than last year, I will say that twice. It represents a pretty stark contrast to the loss per share $2.51 last year. So what a difference a year makes. Thanks to all the hard work and focus of our staff in 2009 and 2010. We were able to have a really good 2010 and we anticipate a really good 2011 as well. In 2010 we were able to fund our entire capital program, including the acquisitions and the special dividend, with internally generated cash flow and cash on hand with no increase in debt or dilution of equity. I'm going to say that again because it is really important. We didn't take on any more debt and we didn't dilute our shares. Our total proved reserve replacement was 231% and our liquidity continues to be strong and our revolver is undrawn and available.

Since the close of the quarter we drilled two successful wells, an exploration well in the Gulf of Mexico and the other exploration well is in south Texas, so we're off to a good start. As we discussed in the last call, we've been managing for cash while focusing on increasing reserves with acquisitions, joint ventures, and drilling internally generated prospects. We think this is a really good time for acquisitions and we're keeping the Company in that position. Production is approximately 50% oil. We're able to take advantage of the current high oil price. So, having said that, the market was improving, and we are actively looking at opportunities such as acquisition and joint ventures in the marketplace.

If you recall, a couple of days following last quarter's conference call, we announced the Deep Water Shell transaction. We've been very active in seeking acquisitions. We continue to believe the market is very favorable and that we will be finding acquisitions that are accretive to our earnings and the borrowing base as well.

Jamie will discuss details of the Shell transaction shortly, so let me talk a little bit about the 2011 capital budget excluding the acquisitions. In early January, we announced our 2011 capital expenditures budget of $310 million. This amount includes any amounts that we might spend -- I am sorry, excludes any amounts we might spend on acquisitions. Our 2011 capital expenditure budget contemplates 14 gross wells, 10 of which are exploratory and four of which are developed. We'll be discussing some of these wells later on in the call.

We're currently executing a plan which allows the Company to grow reserves and production year-after-year using a balance of exploration drilling and acquisitions. This isn't a new thing for W&T. I am proud to say that with the completed acquisitions and drilling successes we had in 2010, proved reserves ended the year at 485 Bcfe, up from 371 Bcfe last year. Or, in other words, total proved reserve replacement was 231%.

If we could have closed on the four Shell properties before the end of 2010, that number would obviously have been higher. In 2011 we clearly expect to grow production and exceed production levels in 2010. The Company's currently marketing a package of properties on the conventional shelf that are not core properties. We feel it is a good group of property that other operators will find attractive and the early indication is that that's the case. Expectations again, we believe that 2011 shapes up to be another really good year for W&T.

Now I will turn it over to Dan to discuss the financial results.

Thanks, Tracy. Good morning, everyone. Revenues for the fourth quarter were $187 million. That's up from $176 million in the fourth quarter last year, and $170 million sequentially due to higher prices and lower cost. Our average realized sales price for oil was $77.27 per barrel in the fourth quarter. That's up considerably from $69.47 per barrel in the fourth quarter last year, and $68.35 sequentially. The average realized sales price for natural gas was $4.01 per Mcf in the fourth quarter. That's up from $3.92 per Mcf a year ago, but down from $4.47 per Mcf sequentially.

Production in the fourth quarter was 22.6 Bcfe, compared to 22.9 Bcfe in the fourth quarter last year, and 21.6 Bcfe sequentially. Volumes are up sequentially with the contribution of the new Shell acquisition production volumes beginning in November of 2010. For the year-over-year quarter comparisons volumes are lower because of the third party pipeline outage that has continued since early June, 2010. Steve will be discussing the status of that field shortly.

Let me move on to a discussion of lease operating expense, or LOE, which is made up of five components; base LOE, insurance premiums, work overs, facilities work, and hurricane remediation. For the fourth quarter total LOE was $47.5 million, and that's up slightly from $45.8 million recorded in last year's fourth quarter. Most of the components of LOE were lower this year compared to last year despite adding the Shell Deep Water properties with the exception of one item.

Facilities costs, which is a component of LOE, increased $6.8 million, and about 40% of which is attributable to repairs to newly acquired properties, while the remainder relates to pipeline and compressor repairs and blast and paint work. Also of note for both the current quarter and the fourth quarter last year, our insurance reimbursements exceeded the hurricane remediation costs that are included in LOE. The biggest decrease in the components of LOE was in insurance premiums, which decreased $3.4 million due to a policy renewal effective June 1, 2010, covered [log] control and hurricane damage.

DD&A was $73.6 million for the quarter, which is lower than both last year's fourth quarter and sequentially. DD&A was lower due to lower production volumes and an increase in proved reserves. General administrative expenses were $15.1 million in the fourth quarter of 2010, compared to $11.1 million in the fourth quarter of 2009, and $13.4 million sequentially.

During 2010 we implemented a new incentive compensation plan based 100% on performance goals. As a result of dramatically improved results in 2010 versus 2009, and the new plan, our [accretive incentive] compensation is up from last year and could be higher in 2011 depending on our performance. Part of the amount in 2011 will be related to grants and awards made in 2010 that are amortized as compensation expense over the service period and due to anticipated continuing good company performance. Our guidance for G&A expenses for the first quarter of 2011 is between $19 million and $21 million, and for the year between $67 million and $78 million.

Our financial performance was strong every quarter in 2010 and that really started in the fourth quarter of 2009. For the fourth quarter of 2010 we reported net income of $20.5 million, or $0.27 per share, which is down sequentially and down from the $0.84 per share reported in last year's fourth quarter when we had a large one-time tax benefit that added to pre-tax income. Adjusted to exclude special items for the same period, net income was $29.6 million, or $0.40 per share, in the fourth quarter of 2010, compared to $26.7 million, or $0.35 per share, in the fourth quarter of 2009 and earnings of $32 million, or $0.43 per share, sequentially. The special items are explained in today's Earnings Release.

For 2010 adjusted EBITDA was $450.2 million and that's compared to $341.4 million for the prior year. Net cash provided by operating activities for 2010 was $464.8 million and that's a significant increase over the $156.3 million generated in 2009. The dramatic increase in cash flow was primarily a result of higher prices, lower operating expenses, and a net reduction of working capital including $99.8 million of tax refunds and $65.5 million in insurance reimbursements.

Our cash balance at the end of the year was $28.7 million, compared to an ending balance of September 30 of $180.5 million. During the quarter we spent $121.9 million to acquire the properties from Shell, paid regular and special dividends of $52.1 million and made a final post-closing settlement with Anadarko for $11.9 million. Our capital expenditures during the quarter were $38.4 million, including completion work at our Main Pass fields for both Main Pass 108, and Main Pass 98, and obtaining an additional interest in fields in which we are already active in.

Although or cash balance declined during the quarter, we have nothing drawn under our revolver and availability remains at $405 million. Because the reserves acquired in the Shell transaction where virtually all PDP, our borrowing base can be expanded. However, we will wait until the spring re-determination to effect any change in the borrowing base or the revolver size. In addition, although our credit facility doesn't mature until July of 2012, we will look at redoing our revolver in connection with the spring re-determination and extending maturity of the facility. All in all, our liquidity continues to be strong and will allow us to continue to grow the Company.

Expenditures for our asset retirement obligations, or ARO, was $24.5 million in the fourth quarter and insurance reimbursements related to P&A work was $11.8 million. We expect to make additional recoveries in the future as we perform plug and abandonment work of facilities and platforms that were damaged during Hurricane Ike. Please note that we have received $53.9 million for the year from our insurance carriers related to P&A work. Our other changes of interest in the quarter to ARO included $18 million related to Shell properties and $16 million of upward revisions for changes in work scope and changes in (inaudible).

Let me move onto a discussion of Federal income taxes. During 2008 and 2009 we established a valuation allowance on our deferred tax assets as we were not reasonably assured we could use the tax benefits in future periods. Because of the dramatically improved financial performance in 2010, we were able to completely reverse the previously established valuation allowance and reduce the tax expense of both the fourth quarter and for the year. As a result of reversing the valuation allowance and utilizing the deduction attributable to qualified domestic production activities under Section 199 of the Internal Revenue Code, our effective tax rate was extremely low. For the year it was around 9.2%.

For 2011 we expect the effective tax rate to be around a statutory rate of 35%, most of which is expected to be deferred. During the third quarter we added full hedge positions for both 2011 and 2012 which should enhance our financing alternatives, should the need arise. The summary hedge schedule can be found within our investor slide presentations posted on our website. No other provisions -- positions were entered into during the fourth quarter of 2010.

With that I will turn the call over to Jamie Vasquez. Jamie.

Thank you, Danny. Let me bring you up to date on a couple of items. Just briefly, on the Shell transaction, we closed on the acquisition of three Deep Water properties from Shell on November 4, 2010. The properties include a 70% working interest in Tahoe, which is Viosca Knoll 783, a 100% working interest in southeast Tahoe, Viosca Knoll 784, and a 6.25% overriding royalty interest in Droshky, which is Green Canyon 244. At the same time, we entered into a letter of intent to acquire a fourth property which is comprised of a 64.3% working interest in a Gulf of Mexico shelf property, and related ownership interest in a Gas Treatment plant. We are still working to close the acquisition of this fourth property and anticipate it will occur sometime during the second quarter, if not before.

The Shell acquisition, the Total acquisition earlier in 2010, along with our 2010 drilling program, contributed to a total proved reserve replacement of 231%. We are very proud of that. During the fourth quarter we reached total depth on two wells. One successful well, offshore, and one unsuccessful well, on shore. The successful well was the Main Pass 108 E-3 well, where we logged over 300 feet of net vertical pay in six bands. The well, along with the Main Pass 98 well that was drilled in the second quarter, have since been completed. The facilities have been completed and constructed and the flow lines have been installed making both wells ready to flow.

Subsequently to the quarter we have additional good news in the Main Pass area. The Main Pass 180 A-2 well reached total measured depth of 13,950 feet in the middle of February, and we found 91 feet of net vertical pay of high quality gas sands in three separate zones. We are currently completing that well, and we expect first production to commence in March, along with Main Pass 108 field, and the new well that we found in Main Pass 98. In addition to the Main Pass 180 well, we commenced the drilling of two other exploration wells located on shore.

The two on shore exploration wells are located in Texas and both are non-operated. We have a 50% working interest in one well and a 25% working interest in the other. The well in which we have a 50% interest has found 22 feet of gas condensate and we expect to be online today. The second well is drilling ahead as we speak. The capital budget for 2011 contemplates drilling six wells on shore and these are the first two of those six. In the future we plan to continue with our strategy of drilling higher risk wells both on shore and offshore that have the potential to add drilling locations and reserves at a reasonable rate.

For the year 2010 our capital expenditures were $415.7 million, which included $115 million to acquire the Total properties, $122 million for the Shell properties, and $60.2 million for exploration, $77.2 million for development, and $41.3 million for seismic, leasehold and other costs. We feel like that money was well spent with our year end results.

As Tracy mentioned, our capital budget for 2011 is $310 million, not including acquisitions. Our current plan is to drill 14 wells, which includes 10 exploration and four development wells. The 14 wells are comprised of five located on the conventional shelf, one in deep water, two on the deep shelf and six on shore. Obviously, the timing of the Deep Water well is solely dependent on the permitting process, whenever that loosens up. And, as I explained earlier, three of the 14 wells are drilled or currently drilling.

We have a lot of other activity planned for this year, including well completions, facility work like compressor projects at Tahoe and Main Pass 108, also numerous re-completions -- we also plan to acquire additional leasehold and we will continue to obtain more seismic and future exploration projects. We think this budget will provide a balance of on shore, offshore, high potential exploration, and low risk exploitation development activity with an emphasis on oil projects.

We are currently evaluating several other opportunities and expect to complement our drilling and exploitation projects with acquisitions providing exceptional rates of return. I also want you to know that as a part of this process we look at both operated and non-operated opportunities. We are indifferent, as long as the operator has a good track record and acts in a prudent, safe and professional manner.

With that I will turn the call over to Steve Schroeder.

Thanks, Jamie. During 2010 we participated in the drilling of six offshore and two on shore wells. We were successful in five of the six offshore wells, and the two on shore wells were noncommercial. Both were high risk, high potential opportunity. All five of the successful wells we were -- all five of the successful wells were on the conventional shelf, and four were exploration wells and one was a development well. We operated three of the five successful wells. Also during 2010 we performed 32 re-completes that added net incremental initial production of approximately 57.8 million cubic feet equivalent per day at a cost of $19.8 million. For the quarter, those same statistics were seven re-completes costing $2.4 million and adding 10.2 million cubic feet equivalent per day of initial production.

During 2010 we did 19 work overs at a cost of $15.8 million that added 17.3 million cubic feet equivalent per day of initial production. Amounts for the fourth quarter were three work overs costing $2.1 million, that added 3.3 million cubic feet equivalent per day of initial production. As these numbers show, re-completes and work overs are a great and relatively inexpensive way to maintain or increase production.

During the quarter we saw improvements in some of the permitting processes, but not all. We have been delayed in bringing the Main Pass 108 field back on production, waiting for the pipeline permits, as have other operators in the area. Fortunately, we received the necessary permits and expect the field to begin flowing by the end of the first quarter. We did receive a permit to drill and are currently completing the Main Pass 180 A-2 well. We also received the necessary permits to do the completions at the Main Pass 108 E-3 and Main Pass 98 A-1 wells. We continue to work with the BOEM RE to get the necessary work permits approved, including face-to-face discussions to improve communications.

Obviously the big change in the quarter was the acquisition of the three Deep Water fields from Shell and the integration process that followed. All of that is going well from an operations perspective, as we have had personnel on the operated facility since December and are in the final stages of transferring the operations.

Let me update you on production. Fourth quarter production exceeded guidance because better [than] well performance, and the addition of the Shell properties, partially offset by down time at our Ship Shoal 299 field. At our Ship Shoal 299 field we experienced an increase in pressure in our departing oil pipeline due to the pipeline plugging with paraffin. The problem has been resolved at the end of February, and we are currently bringing the field back up to rate. In addition, we continue to be negatively impacted by the continued outage of the Main Pass 108 third-party pipeline. As discussed, the latest delays at our Main Pass 108 field were caused by permitting issues. Those issues are now behind us and production is expected to be restored to full capacity in April for both fields, at approximately 40 million cubic feet equivalent per day combined.

For the first quarter, we anticipate our oil and natural gas liquids production to be between 1.5 million and 1.6 million barrels, and our natural gas production to be between 12 Bcf and 12.6 Bcf, and our total production to be in the range of 20.8 Bcfe to 21.9 Bcfe. For all of 2011, we anticipate our oil and natural gas liquids production to be between 5.5 million and 6.3 million barrels, and our natural gas production to be between 50.2 Bcf and 58.9 Bcf, for a total production for the year to be between 83.2 Bcfe and 96.7 Bcfe. Out of an abundance of caution, this guidance includes only fields which we currently own and does not include the pending fourth property from the Shell transaction, or any other transactions. Further, it includes five days of down time associated with hurricanes.

Lease operating expenses for the fourth quarter were within guidance. All costs were lower in the quarter, except facilities costs which were up due to the reasons Danny previously explained. As you can tell from the LOE guidance in the first quarter, we are expecting LOE to be slightly higher with a full quarter of the Shell properties, along with approximately $5 million to repair the Ship Shoal 299 oil pipeline. Our guidance for lease operating expenses for the fourth quarter of 2011 is between $51 million and $57 million, and for the year between $188 million and $218 million. These estimates do not include any allowance for hurricane related expenses or insurance reimbursements.

Our guidance for gathering transportation and production taxes for the first quarter 2011 is between $5 million and $7 million, and for the year between $22 million and $25 million. Now let me turn the call over to Tracy for closing remarks. Tracy.

Thanks, Steve. One thing I think we need to clarify for the market is that when we do these acquisitions, I think perhaps the market may anticipate a little bit higher production because we're taking these acquisitions on at a future date. And what really happens is that we reduce our purchase price because of the timing difference between effective date and closing date. So, I think perhaps some of the estimates may have been a little higher from the market as a result of expecting that production. What we do is we reduce our basis, or our purchase price, in those properties as opposed to including those production numbers. So, I think that's probably part of the disconnect.

All along we've stated that our strategy is to grow production reserves with both drill bit and through acquisitions. Obviously, the acquisitions completed in 2010 helps us achieve those goals and increase shareholder value. Total increase in our stock price last year was over 50% as the market rewarded us in part for making substantial accretive acquisitions. I believe as we continue to do the things we did in 2010, the market continues to be good, that we will see a further increase to the stock price in 2011. As you know, the stock is up another 30% thus far in 2011.

We continue to strive to find the right assets to add to our portfolio. We believe that there are many more acquisition opportunities for us out there, both on shore and offshore. Further, we think that the combination of acquisitions and drilling activities should continue to provide the best opportunities to achieve our strategy. We believe that we have got sufficient liquidity and the cash on hand, cash flow from operating activities, availability under our bank credit facility, and access to other capital Markets should be more than adequate to fund most of our opportunities.

As we think about the remainder of 2011, we're continuing to evaluate numerous acquisition drilling opportunities, and again that's drilling opportunities as well, and expect to complement our activities thus far with those opportunities that we believe have the best chance of increasing shareholder value.

That said, I will turn it over to you, Operator, for questions.

Thank you, sir.

We will now begin the question-and-answer session.

(Operator Instructions)

Our first question comes from the line of Steve Berman with Pritchard Capital Partners. Please go ahead.

Good morning, everyone.

Good morning, Steve.

You said the Shell properties were not in the guidance. Can you say what current production -- I am sorry the fourth Shell property is not in the guidance. Can you say what the current net production is from that, and also did you back out production from the shelf stuff you're looking to sell? Has that been taken out of the guidance?

The answer to your first question is, the approximate production with Shell is about $24 million a day.

That's net?

Yes, that's net. And then, no, we did not take out the production from the sale of assets.

All right. Can you say what that production is, or too soon to give that kind of --?

We haven't made that public, but it is a substantial amount, but it's not anything we don't think we'll overcome with our program.

You commented several times, Tracy, about strong oil prices. Can you talk about any benefit you're getting from pricing off of some of these other benchmarks down in the Gulf Coast that are much higher than WTI?

I will turn that over to Danny.

Hi, Steve. You know, I guess 65% or so of our production is either LLS or HLS priced. Some of it's priced off of Eugene, Ireland, pilot offshore, a couple of the other pipes. So, we're seeing premiums over WTI. In February, we're seeing $17 premium LLS over WTI. So, yes, we are benefiting from the differential between (inaudible) and WTI. All the Gulf Coast crudes are selling at premium to WTI.

Thanks, Danny. Let me sneak one more in. Tracy, are you ready to talk about any more detail on where your on shore activity is or is it a little --?

Yes. I will. I will tell you that some of it is not going to be in the Gulf Coast area. That's about all I can tell you about that.

All right. I appreciate it. I will let someone else go. Thanks.

Thank you, sir.

Thank you. Our next question comes from the line of Noel Parks, Ladenburg Thalmann. Please go ahead.

Good morning.

Good morning, Noel.

I wanted to circle back and look at the reserve adds. Your drill bit reserve adds were a little longer than I was expecting for the year. Did the Main Pass 108 E-3, did that count at the in the year end proved reserves?

Yes.

Okay. And how much of a contribution did that make?

You're asking me for specific well reserves. We don't give out specific well reserves, Noel.

Sure. I just meant, was it a major or minor contributor to what you booked at year end?

I would say it was a pretty good contributor.

Okay. And can you tell me, just refresh my memory, were there any other major wells from earlier in the year that also had a big piece or a significant piece of your drill bit adds?

I would say that Main Pass 98 probably had some effect on us.

Okay. Great. And my second one -- wondering, from the Shell properties that you've acquired, just wondering if now that you have had access to the data in there, have you encountered anything interesting that may suggest analogies either for other deep water projects or other things you might be interested in drilling or putting some capital into either near term or longer term?

I think it is still just a little bit preliminary for that. Our shop has been pretty busy, and I don't think that I can definitively tell you whether we're looking at offset information that may be of benefit to us at this point yet or not. I think we're still continuing to evaluate.

Okay. Fair enough. Thanks a lot.

Thank you.

[ Operator Instructions ]

Our next question comes from the line of Richard Tullis with Capital One Southcoast. Please go ahead.

Thank you. Good morning.

Good morning, Richard.

Tracy, could you give the current status of Daniel Boone, what's going on there right now?

This is Steve. Yes, the well's actually making about 500 barrels, 600 barrels per day, but it is cutting water right now.

Okay. Was there any reserve impact from Daniel Boone at year-end?

Actually, we had already taken any reserve write-downs we needed to. So, end of the year it had already been taken care of.

In 2009 you took --?

Yes, a substantial amount of it in 2009.

Okay. How much of the 2011 production guidance is related to the properties acquired from Shell? I guess they were producing mid-50s per day at the time of the announcement.

I'm not sure I have a great answer for that right now. I have to do a little bit of research and come back with you on that, Richard.

Okay. As far as 2011 acquisition potential, are you going to favor gas over oil, or just no preference?

Yes. Traditionally we don't really care. It's an economic situation, or it is an economic consideration, I should say. Preferably, you would always like to see something that has a higher price, but the economics may not drive you that way. I am fairly contrarian, so gas to me seems like that's going to be easier to purchase than oil, so it is just a matter of finding out whether we can purchase it at a price that makes sense.

Okay. That's all I have right now. Thank you.

Thank you, Richard.

Thank you. Our next question comes from the line of Brian Kuzma with Weiss Multi-Strategy. Please go ahead.

Good morning, guys.

Good morning, Brian.

You give a number of 40 million a day from Main Pass when that comes online in March. I couldn't tell, though, is that total net production including the new discoveries that you guys made last year? Is that right?

Yes, that's correct. Main Pass 108 is about 87% gas, and we had a little bit of consideration in there for Ship Shoal 299. We had a pipeline outage due to a paraffin plug, and that is about 87% oil. So, the combined combination is about 40 million cubic feet a day equivalent.

I got it. Okay. And then I also wanted to ask -- deferred taxes are, you said they're going to be -- excuse me, cash taxes are going to be somewhat minimal this year. I am curious, how does that play out over the next couple of years as you keep making acquisitions? Is the number going to change, basically I guess is what I am trying to get at?

Yes. It is going to change based on what we drill and what we acquire. But basically I think Danny told you that right now we look at it as a deferred tax.

Okay.

Brian, with all the drilling that we're going to do, most all of it will be deferred. The only thing that will be a cash component will be the ( inaudible ) tax, and with all the IDC, we'll probably end up paying it off and getting it refunded in the following year. So, the way I look at it is primarily all ( inaudible ).

Okay. So, if you can keep up a $200 million-type of drilling budget, that's enough to offset the cash taxes? Is that for the next couple of years, or do you think that's just for '11?

I think it can continue on for a long time. IDC is being able to deduct all that in the current period. Unless you make an enormous amount of money, I think it is going to defer.

Okay. That's what I needed. Thanks.

Thank you.

Mr. Krohn, there are no further questions at this time. Please continue.

Okay. Look, that does it for the fourth quarter. We'll look forward to talking to you again very soon and thank you very much for your participation.

Ladies and gentlemen, this concludes the W&T Offshore, Inc., fourth quarter and year-end 2010 earnings conference call. You may now disconnect. Thank you for using ACT conferencing.