W&T Offshore Inc (WTI) 2005 Q1 法說會逐字稿

Good morning, ladies and gentlemen, and welcome to the W&T Offshore first-quarter conference call. At this time, all participants are in a listen-only mode. Following today's presentation, instructions will be given for the question-and-answer session. (OPERATOR INSTRUCTIONS). As a reminder, this conference is being recorded Friday, May 6, 2005. I would now like to turn the conference over to Miss Lisa Elliott, Senior Vice President of DRG&E. Please go ahead, ma'am.

Thank you, operator, and good morning, everyone. We appreciate you joining us for W&T Offshore's conference call to review results for the first quarter of 2005.

Before I turn the call over to management, I do 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 experienced technical problems and didn't receive yours this morning, please call DRG&E's office at 713-529-6600 and someone will be glad to help you. If you would like 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 web site at www.wtoffshore.com or via a recorded replay until May 13, 2005. To use the replay feature, call 303-590-3000 and dial the pass code 11029672.

Information recorded on this call speaks only as of today, May 6, 12005 and therefore time sensitive information may longer be accurate as of the date of any replay.

Today, management is going to discuss certain topics that will contain forward-looking information that are 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 the second quarter and full year 2005. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, they can give no assurance that such 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 inherent in oil and gas production operations and estimating reserves, unexpected future capital expenditures, competition, the success of our risk-management activities, governmental regulations and other factors described in our most recent annual report on Form 10-K and other filings filed with the Securities and Exchange Commission. Should one or more of 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, CEO of W&T Offshore.

Thanks, Lisa. Good morning, everyone, and thanks for joining us for our first-quarter 2005 conference call. Again, I'm Tracy Krohn, CEO and founder of W&T Offshore. In the room with me today is our senior management team, including Dr. Reid Lea, our VP of Finance and Chief Financial Officer, Joe Slattery, our VP of Operations, Jeff Durrant, our VP of Exploration and Geosciences, Bill Talafuse, our VP of Accounting and Chief Accounting Officer, and Cliff Williams, our Reservoir Engineering Manager.

Today, we're going to talk about certain key events and some things that took place during this last quarter. Jeff Durrant, Joe Slattery and Cliff Williams will discuss their appropriate piece of it and Dr. Lea will review the financial results for the quarter as well. He'll also discuss the guidance for the second quarter of 2005 and reconfirm our annual guidance we provided in our earnings release, which is available on the web site. Following the formal presentation, we will go ahead and have the Q&A session.

I'd like to update you a little bit on our Company's operations and then I'm going to turn it over to do Jeff Durrant in a bit. I'm pleased to report that we produced 19.3 Bcf equivalent for the first quarter, which was within our targeted range. Additionally, our earnings per share was about $0.60 on a fully diluted basis, which was well above the consensus estimates.

During the first quarter of 2005, we participated in drilling seven gross exploration wells in the Gulf of Mexico. Six were on the shelf; on was in the deep water. We were successful on five out of those seven wells. All of these successes were on the conventional shelf. We had one deep water well in Green Canyon 8 that was a dry hole and we had one shelf well in the Ewing Bank 784 that was a dry hole as well. Even though we drilled that one with a floater, we consider it to be shelf if it is in water depths of 500 feet or less.

With that, I will turn it over to Jeff Durrant, our VP of Exploration, and he'll review the first-quarter drilling and update you on new (indiscernible).

Thanks, Tracy.

I'll start off with some of our successes (indiscernible) those five successful wells you just addressed. Three were 100% working interest infield exploration prospects we drilled in our Ship Shoal 149 field. Our first well, the G8, we drilled to 4850 feet and found 33 feet of gas in one sand. Following disappointing production result at the well was sidetracked to a downdip location, where 50 feet of oil and gas was found in three sands.

Our second well in the program, the G3, sidetracked, drilled to 5690 and found 100 feet of oil and gas in two sands. The last successful on the project, the G9, was drilled to 5400 feet and penetrated 92 feet of oil and gas in two sands. All three wells have been completed and combined, these wells are producing 5.2 million cubic feet equivalent per day and that is net to W&T's interest.

A fourth 100% W&T interest exploration well was drilled at Eugene Island 218; this is the I3 well. This was drilled and completed to a depth of 4852 feet and we found 80 feet of gas in two sands. This well has been completed, and we expect the first production to be in mid-May following a pipeline hookup.

Our final shelf discovery was the A-28 Sidetrack/832 well, and this was in West Cameron 638 field. The original well, the A-28 Sidetrack, drilled to 11,848 feet, and we found 106 feet of gas in our objective sand. Unfortunately, production casing was stuck above the production for Risin (ph) and this required us to redrill the well and call it the 832, where a similar gas section was again penetrated. The well was successfully completed and recently tested at 1.6 million cubic feet of gas equivalent per day, and once again, this is net to W&T's interest.

Additionally during this first quarter, we successfully reached a depth of 20,520 feet in the deeper development portion of our Mississippi Canyon 674 #3 deep water Pluto well. We encountered over 70 feet of gas, as expected. You may recall that this well begin drilling in late 2004, where we were successful in finding 60 feet of gas sand in the shallower exploratory portion of that well. Both of these zones have been completed, and initial rates for both of these zones have been obtained. The upper exploratory objective has tested at a gross rate of 21.5 million cubic feet of gas per day, and the lower development objective tested at a gross rate of 17.3 million cubic feet of gas per day and about 1000 barrels of condensate per day.

In April, W&T -- we were successful in delineating our 2004 cleanup arts (ph) discovery. The 100% working interest in Ewing Bank is 949 #2 Sidetrack 2. We drilled to a measured depth of 13,600 feet to a downdip structural position. We found 52 feet of oil in the shallow objective and 34 feet of oil or water in our primary deeper zone, where oil samples were collected. The well was sidetracked to a total depth of 12,323 feet to an updip optimal production position, where we encountered 146 net feet of oil in the well's two main objectives. Following logging operations, casing was run and the well was suspended pending final development plans. We expect first production from this project by second quarter of 2006.

We are still on schedule to complete our drilling program that we announced in March of drilling at least 30 exploration wells and five development wells by year-end. In fact, in the final three quarters of the year that we anticipate drilling 14 wells in the conventional shelf and onshore category, four in the deep shelf and five in the deepwater. During the remainder of the second quarter and the third quarter of this year, we will be drilling wells from all three of these categories.

Next, I'd like to discuss some examples from our upcoming higher-potential exploration programs in these second and third quarters. Joe Slattery will address the drilling rigs and the timing later in the presentation. From the shelf, we plan to begin a three-well exploration programs in June at High Island A-443. Two wells are in the infield exploration wells, while a third well we'll explore for higher-risk but higher-potential, deeper objectives. Also in June on the shelf, we plan to continue our Eugene Island 205 field redevelopment program with the drilling of two exploration wells, one of which is classified as a deep shelf well, and a third development well will also be drilled.

In our deepwater program, we expect to spud our Ewing Bank 989 prospect in May. This 100% working interest, well, it targets number of stack prospective intervals. If successful, the well will be a single subsea tie back to existing nearby W&T operated infrastructure.

Our deepest water exploration program this year is in about 3000 feet of water, and this is the (indiscernible) prospect and it is scheduled to begin operations during late in the third quarter.

In our last category, deep shelf, we hope to begin drilling an 18,800-foot exploration well in that shallow state of Louisiana waters. This well is scheduled for a third-quarter spud.

The total of the net unrisked exploration potential for these just-discussed exploration programs is about 150 Bcfe. For all of the remaining budgeted exploration wells for 2005, that number is approximately 275 Bcfe, and that potential could be 450 Bcfe depending upon our ability to secure rigs in the second half of this year.

Now, back to Tracy.

Thanks, Jeff.

A couple of things I'd like to add to Jeff's commentary there is that we are seeing some rig availability issues and possibly some slippage this year on certain projects. We're not 100% certain of that yet. I've been in this business long enough to know that rig schedules change with different operators, even though they look like they might have something tied up for the long-time, they hit dry hole and all of a sudden they've got a window, so we haven't given up on the year but it's possible that some of our projects could slip in the next year. It looks also like we're filling in some of those projects as well with other opportunities that are coming our way. We're looking at a couple of those now and we are getting ready to commit on a couple of those as well. So, I don't think that we will see a real slowdown in activity; in fact, probably more the opposite.

Having said that, let me talk a little bit about production for the first quarter. Total production was 12.4 Bcf of gas and 1.2 million barrels of oil or 19.3 Bcf equivalent, as we talked about earlier. That compares to 14.3 Bcf and 1.3 million barrels of oil or 21.8 Bcf for the first quarter of 2004. That production decline is as we predicted. The good news is that production is predicted to ramp up from the third and fourth quarters, and we will touch on that buildup in just a few minutes.

Overall, costs are higher than anticipated due to issues that relate to supply and demand. However, our projects remain economically viable at the current service rates and commodity levels, and we will continue to accomplish our objectives.

Now, I'm going to turn it over to Joe Slattery. He will discuss some of the business of specifics of our current program.

Thank you, Tracy.

As of May 5, W&T had six rigs working and we expect to maintain that level through the second quarter, which was very similar to the first.

Let me breakdown our current activity on the shelf, the deep shelf and the deepwater. On the shelf, we have three rigs running. The first one, the Pride of Florida, is a (indiscernible) jack up and it is currently completing the E-8 exploration well at Eugene Island block 218. We expect the completion to be finished by the end of the week. Following that, we will complete the interconnecting piping and then reactivate the gas sales line. We do not have an estimate of the initial production rate at this time. The second jack-up on the shelf is Nobles jack-up, the Jill Alford (ph) and it is drilling a development well at Eugene Island block 53. We anticipate that this well will reach total depth within a week. The third rig is a Roland's (ph) jack-up, the gorilla 3 (ph), and it is drilling an exploration well at High Island A-568 from an existing structure.

In the deepwater, we've one semisubmersible rig working for us; it is the Roland (ph) Midland, and this rig successfully ran casing on our Queen of Hearts project and is currently moving toward Ewing Bank's 989 project. We are the operator of the well and we expect to spud by mid-May.

In addition to these four rigs, we have two rigs performing workovers. They are the Pool rig 54 at Highland 110, and the Pride 210 platform rig at Green Canyon 18.

Now, we have also contracted three additional rigs for the second quarter. The first one we've contracted is the Roland jack-up, the Gorilla (ph) 4, and it is expected to move by mid-May to our Ship Shoal 349-A platform to drill a development well. We expect this well to take 75 days to drill, and the completion will follow. The second rig we have contracted is the Mack (ph) jack-up the Pride of Missouri. This rig is finishing its work at West Cameron 295 and is expected in mid-June to drill our High Island 443 program. The third rig is Noble's semisubmersible (indiscernible) and this rig is scheduled to complete our Green Canyon 178, our Baccarat (ph) project, starting in mid-June. That completes our rig activity report.

Now let's move onto the construction projects. We are on schedule for two of three planned project. The one exception is a Mississippi Canyon 674 #3, our Pluto 2. Following the release of the Ocean America, the drilling rig that performed the completion, an ocean service vessel, the oceaneering OE2 was mobilized to the field to install a 2-mile jumper pipeline but was unable to do so due to loop currents. For those of you who are not familiar with them, loop currents form when a portion of the Gulfstream enters the Gulf of Mexico through the Yucatan Straits, flows north, and then turns east and then finally turns south to exit the Gulf through the Florida Straits, forming a loop. The loop current can extend north far enough to impact the deepwater lease blocks in the central Gulf of Mexico. You may have seen a recent news release from Shell where they indicated that scheduled repairs to their Mars platform in the same area had been delayed for the same reason. So the Pluto 2 project has been suspended until June 15, when we will try again to complete the jumper installation. Now, fortunately for us, we only need a short pressure of time to complete this operation, as opposed to a major facility installation -- that is if mother nature will cooperate.

The second ongoing construction project is the installation of a 13-mile pipeline and umbilical to be installed from our Green Canyon 178 baccarat well to our -- I'm sorry Green Canyon 178 to our Eugene Island 397 platform. The lay barge is scheduled to be in the field in late May. In the last construction project is the laying of two pipelines from our South Timbalier 329-A platform to the Grand Isle 116-A platform. That project is scheduled for early June installation.

That concludes our activity report. Back to you, Tracy.

Thanks, Joe.

In the first quarter of 2005, we spent 30.3 million for development capital, 25.2 million for exploration and 0.5 million for other CapEx expenditures. Out of that, 8.4 million was dry hole costs. CapEx was for the three months ended March 31, 2005 was financed by net cash flow provided by operating activities. We didn't have to dig into any revolving credit lines at all. That is kind of the way we've operated most of our existence, in any event.

Drilling completion facilities expenditures for 2005, we spent 17.6 million in deepwater, 14.2 million on the deep shelf, and 23.7 million on conventional shelf and our (inaudible) projects, and again, another 0.5 million for other CapEx items.

We had several projects underway which are going to positively impact production in the second half of the year. I will let Cliff Williams describe some of that in regard to second-quarter and second-half impact (indiscernible) Cliff?

Thanks, Tracy.

First, let me start with our production guidance for the second quarter and full quarter of 2005.

In the second quarter, we expect to produce between 18.3 and 19.3 Bcfe, which is flat to slightly below the first quarter of 2005. Full-year guidance remains unchanged at 83.1 to 87.4 Bcfe. This production profile is expected and is consistent with the success we've had over the last 18 months.

Two offsetting events took place during the second quarter. As we discussed in our last conference call, the operator of a major offshore pipeline had informed us that the repairs mandated by the U.S. Department of Transportation would require a six-week pipeline shut-in beginning on June 1. This shut-in has since been rescheduled to July 5 and so the deferral but not the loss of approximately 1.1 Bcfe of production will now impact the third quarter of 2005 rather than the second and third quarters as originally expected. Offsetting this event, however, is the delay of initial production from the Pluto 2 project due to weather issues that Joe already discussed. On an annual basis, this delay results in a deferral but not the loss of approximately 1.5 Bcfe from Pluto 2.

Successful work programs in several field areas contributed to the second-quarter production levels. New production from discoveries in Eugene Island 205, Ship Shoal 149 and West Cameron 638 fields, discussed by Jeff earlier, are included in our second-quarter guidance. Several planned workovers in the Main Pass and Vermillion field areas also positively impacted our second-quarter guidance.

We expect to see production in the second half of the year to really begin to ramp up, and I'd like to detail some specific reasons. Production should be up 20% in the last half of the year as a result of several major projects that are currently underway and of several planned development wells. Let me walk you through some of the major projects scheduled for completion during the second and third quarters of 2005. These projects contribute to the majority of the expected increase, and it's important to note that the first three projects are facility-related following the successful drilling program at three separate Fields, and the fourth project is a development well in the Mahogany field targeting a major oil sands.

At South Timbalier 229 field, W&T successfully drilled four oil wells last year and this primarily gas-productive field located on the shelf. As Joe discussed earlier, we are on target to complete the oil pipeline installation to a nearby platform in June.

Last year, at Green Canyon 178 field, we drilled a gas discovery in 1400 feet of water. Later this month, a lay barge is scheduled to begin installing the 13-mile umbilical and flow line to tie this subsea well back to the W&T operator, the Eugene Island 397-A platform. As Joe mentioned, in mid-June, we expect the rig to be on location to complete this well.

At Mississippi Canyon 674, our Pluto 2 project, we successfully drilled and completed a subsea well located in 2300 feet of water. This well was completed using smart well technology with two productive zones, one an explosion target and the other a development target. During the initial flow back to the rig, one tested at a net 8.1 million cubic feet equivalent per day and other at a net 8.7 million cubic feet equivalent per day. However, we do anticipate higher rates following cleanup to the production system. As both Tracy and Joe mentioned earlier, the final tie-in has been delayed until mid-June because of the loop currents. Should these loop currents persist, this project could be further delayed.

Ship Shoal 349 in a shelf field. We have contracted a rig to drill a sub-salt well to a total depth of 14,600 feet from the existing platform, targeting that major oil sand in the field. Joe mentioned that we expect this rig in mid-May.

Also contributing to the second-half increase are several planned development wells, five operated and three nonoperated. All wells are located in shelf waters and are planned to be drilled from existing structures which will decrease the time to bring production online. All projects are being actively worked, operated and nonoperated alike. A reading is expected in the field early this month for one location, and AFEs have been prepared on the majority of the other prospects, although rigs are not currently under contract. We expect production contribution for both the projects and the planned development wells to be 4.3 Bcfe for the third quarter and 6.7 Bcfe for the fourth quarter.

Now, I'd like to turn it over to Reid for a financial review.

Thanks, Cliff, and good morning to everyone on the line.

Well, as Tracy already mentioned, earnings for the quarter were about $0.60 per diluted share. That was based on net income of 39.3 as compared to 38 million or $0.58 per share for the three months ending March 31, '04.

Cash flow by operating activities was 72.4 million compared to 97 million from the first quarter of the prior year. That decrease in cash provided by operating activities was attributable to reductions in our Accounts Payable in the first quarter of this year as compared to last year.

EBITDA for the first quarter was 101.5, and that compares to 98.7 for last year. Our EBITDA margin for the first quarter was 79% compared to 80% for 2004. Our consistently high EBITDA margin continues to be the hallmark of our ability to maintain costs and provide higher rates of return to our investors.

Commodity pricing for the third quarter was strong. Natural gas averaged $6.33 per Mcf and crude, $43.67 per barrel for an average price of $6.67 per Mcfe. That compares to an average price of $5.67 per Mcfe in the first quarter of '04. Once again, the Company did not have any hedges in place in the first quarter of '05 or '04, and we don't have any hedges in place at this time.

LOE for the first quarter decreased to 16.2 million, or $0.84 per equivalent unit of production, from 17.4 million or $0.80 per Mcfe in the first quarter of 2004. This was due primarily to lower-than-anticipated maintenance and work-over expense. One work-over planned in the first quarter was deferred until the second quarter due to weather. The rig is currently on location. Now that we've got the four winter weather months behind us and longer days, we anticipate more than twice as much planned maintenance and expense activity in the next two quarters. The second quarter LOE guidance reflects this activity. The last thing that I will say about base LOE is that it's somewhat lower than we anticipated, although we are not changing our annual guidance on LOE at this time.

Let's move on to DD&A and accretion, which increased $41.3 million or $2.14 per Mcfe in the first quarter, as compared to 39.6 million or $1.82 in the same period of '04. That increase in DD&A on a unit basis for the first quarter is obviously the result of higher depletable costs.

G&A -- the first quarter G&A increased to 6.9 million from 4.3 million in the same period of 2004, which was not at all a surprise. That increase is due primarily to higher personnel cost, partially as a result of our recent IPO, as well as the recognition of the special bonus paid to the employees for 2003 and 2004 performance, the first half of which will be paid on June 1. As I said, these changes were discussed in our last earnings conference call. The increases are within our prior guidance, and we're not changing our annual guidance.

Income tax for the quarter was 20.7 million. Our effective tax rate for '04 was 35%, and you can expect that to continue into '05. You will expect to continue to see about 20% of our book taxes to be deferred.

Our balance sheet continues to be really strong. At the end of '05, we had -- at the end of March of '05, excuse me, we had 45 million in cash and equivalents and 0 debt. Total assets were 744 million, and our shareholder equity was just under 400 million.

For those of you that have been investors for awhile, you may know that on March 28, the Board of Directors declared a cash dividend of $0.02 per share. That was payable on May 2 for shareholders of record April 15, so if you are a shareholder, you should be receiving the dividend check shortly.

The press release gives the details of our operating guidance; I will not go over it at this time. It has not changed from our prior press release. It hasn't changed since our last earnings call.

With that, I will turn it back over to Tracy to discuss some closing remarks on A&D and our recent success in the MMS lease sale.

Thanks, Reid.

Again, we don't forecast for acquisitions, although we are very aggressive in acquisitions in the Gulf Coast area and beyond. We were very active in several recently announced transactions in the Gulf of Mexico, including Devon and NCX (ph). Based on those purchase prices, we felt that our analysis produced a different valuation, and we are intent on sticking to what we've always done (indiscernible) pretty disciplined acquisition strategy, and that includes a very thorough evaluation of recoverable reserves. I still believe that this company will continue to make acquisitions and even larger acquisitions, and I look forward to that this year and beyond.

Lease sale -- we were the apparent high bidder in 9 of the 15 bids that we submitted at the last lease sale for the Central Gulf held on March 16 of this year. Of those nine blocks, seven are on the shelf, two are in the deep water. Our net financial exposure was right at 3.3 million. To date, seven of those blocks -- five on the shelf and two in the deep water -- had been awarded to W&T and the remaining two are pending the necessary approvals from MMS. So we continue to add acreage to our already pretty large holdings in the Gulf, that between 900,000 and 1 million acres. Depending upon what day of the month it is, sometimes we pick up a lease and lease that and every once in awhile we have to relinquish one. But we still view that as a legacy opportunity for us now and in the future.

That concludes our prepared remarks. We are ready to take questions, so operator, if you would please open the phone lines to Q&A.

Thank you, sir. Ladies and gentlemen, at this time, we will begin the question-and-answer session. (OPERATOR INSTRUCTIONS). Frank Bracken with Jefferies & Company.

Congratulations on Queen of Hearts. I think that's great news for '06. I was hoping -- without trying to force you to provide a guided production number on Queen of Hearts -- I was hoping maybe you could give some analogy in the surrounding area to maybe suggest what sort of rates have been achieved by comparable situations. That's my first question.

The second one also is related to the deep water. I was hoping you could give me a little update on the status of Dice (ph).

(technical difficulty) -- is a nice -- (technical difficulty) -- for us. The -- (technical difficulty) -- 2500 barrels of oil -- (technical difficulty). Although we already have a quote, we took some fluid samples and we have some pretty good -- (technical difficulty) -- significantly higher.

In regards to types, that -- (technical difficulty). Currently, -- (technical difficulty) -- tapped into a portion of the reservoir was a little bit smaller than we thought, so we're going to have a rig out there to drill another well in a more optimal position.

That well came on in the first quarter, is that right?

Yes.

Okay. You're going to remediate? You're going to try to get a different take point in there?

Yes, we are. (technical difficulty) -- about 10 or 12 million a day, and it dropped off. I think it's making, what, a couple of million a day now. So we're not satisfied with what we've got down in the reservoir and we believe there's more in it, so we're just going to move it to a better take point in the reservoir.

(inaudible) happens.

What's that?

When might that happen?

The scheduled rig for that is about fourth quarter.

Mr. Bracken, do you have any further questions?

I will let somebody else have a turn. Thank you.

Jeff Robertson with Lehman Brothers.

Good morning, Tracy. Can you talk a little bit about the lease position you all picked up at the Central Gulf sale, and in terms of when the prospects might be drilled, also what kind of sizes you're looking for?

I'm going to put that over to Jeff Durrant a little bit, because he's a lot more familiar with the exact details on that.

Jeff, this is Jeff Durrant. I think, of the nine blocks that we obtained, seven were on the shelf and two were in -- well, will obtain, hopefully -- seven are on the shelf and two were in the deeper water. The deeper water zones were (indiscernible) in the eastern Gulf and the (indiscernible) area in relatively shallow waters; that's 500 to 1500 feet of water depth. Then the shelf wells contain the entire spectrum from deep shelf opportunities, which you might expect to be larger, to more conventional shelf opportunities.

I'm not prepared to discuss the actual reserve numbers right now.

I will add a little bit of flavor to that. Normally in the deeper shelf, we're looking for about 15 Bcf and higher.

Okay. Are many of those prospects or will many of those prospects be included in a '05 capital program or get slotted in, or will they be more the '06-'07 drilling time Windows?

I believe you are looking at '06 and '07.

Okay. Thank you.

(OPERATOR INSTRUCTIONS). At this time, I show no further questions. I would like to turn the conference back over to Mr. Krohn for any concluding comments.

Thanks, operator. Well, since there's no more questions, I'll conclude by saying that we are on track to where we thought we would be at this point in the year. I'm very pleased with that. I do expect to see a ramp up in production in the third and fourth quarters, as we had predicted. Hopefully, we will have some even better opportunities heading our way before the end of the year. I do expect that we will see some changes in capital budget perhaps later on in the year after we look at it in midyear.

So thank you very much, and we will talk to you again soon!

Thank you. Ladies and gentlemen, this concludes the W&T Offshore first-quarter conference call. If you'd like to listen to the replay of today's conference, you may dial 303-590-3000 and you'll need to enter the access code of 1102-9672 followed by the #. Once again, thank you for participating in today's conference. At this time, you may now disconnect.