W&T Offshore, Inc. (WTI) Q1 2014 Earnings Report, Transcript and Summary

Good morning, ladies and gentlemen. Thank you for standing by. Welcome to the W&T Offshore's First Quarter Earnings Conference Call. [Operator Instructions] This conference is being recorded today, Wednesday, May 7, 2014. I would now like to turn the conference over to Ms. Lisa Elliott. 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 the results for the first quarter of 2014. And before I turn the call over to the company, I have a few items I'd like 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, that's www.wtoffshore.com, or via recorded replay until May 14. To use the replay feature, call (303) 590-3030, and dial passcode 4679511. Information recorded on this call speaks only as of today, May 7, 2014, and therefore, time-sensitive information may no longer be accurate as of the date of any replay. And please refer to our first quarter 2014 earnings release for disclosure on forward-looking statements. At this time, I'd like to turn the call over to Mr. Tracy Krohn, W&T Offshore's Chairman and CEO.

Thanks, Lisa. Good morning, everyone. Thanks for joining us this morning for our first quarter 2014 earnings conference call. As usual, with me today is Jamie Vazquez, our President; Danny Gibbons, our Chief Financial Officer; Tom Murphy our Chief Operations Officer; and Steve Schroeder, our Chief Technical Officer. Yesterday, we made known our financial and operating results in a press release, and this morning, we'll review some of the key items that were presented in that release, and then we'll open it up for Q&A. As we discussed in our last call, we've been focusing on enhancing our portfolio of multiyear projects to increase visibility into future production and reserve additions. In today's market, we're rich with opportunities to create value and build long-term growth. We're working hard to realize those opportunities, meaning that if we are to continue to grow, we will always have need of additional ways to execute on those opportunities. Our opportunities in both the conventional shelf and deepwater in the Gulf of Mexico are substantial. That includes projects in our current plan, as well as projects under consideration. Our 2014 offshore program includes numerous exploration wells, all with large reserve targets. This program is weighted towards operated wells and fields where we have 100% working interest and where our exploration efforts have been expanding the field's reserve base for several years. These include fields like Mahogany and East Cameron 321 on the shelf, and Matterhorn in the deepwater. As we've previously discussed, a large percentage of our 2014 CapEx budget is dedicated to deepwater exploration and development. Now a couple of weeks ago, I was at a financial conference and one of the analysts investors said, "What you guys really need to do is sell all your offshore assets and go onshore. Go out in the Permian Basin." And about 20 minutes later, another investor analyst came in said, "What you guys really need to do is sell all your onshore assets and go offshore." And he was definitely an investor and analyst in our stock. So we get a variety of opinions. Told you all that to tell you this that we believe we're well suited to be in both of those basins, and it's our intent to continue to do that for a long time. So we're enhancing our 2014 program with several non-operated projects, in which we hold a 15% or 20% working interest. These projects increase our exposure to high-impact opportunities that, if successful, could become multi-well, multiyear projects. Our deepwater Mississippi Canyon 698 #1 well, Big Bend, is one of those successes. Our 20% working interest in that discovery well drilled in late 2012 led to opportunities to be a part of projects with Mississippi Canyon 699 Troubadour and Mississippi Canyon 782 Dantzler, both discoveries in 2013. We're now committing to a second Dantzler well as part of our 2014 deepwater drilling plans. The best thing about this is the reserve additions and production impact are very significant. These are substantial projects that require meaningful financial commitment and some patience. Additionally, since these deepwater discoveries are relatively near to each other with the same operator, we should benefit from economies of scale and hook-up, production and development. Completion operations were finalized at Big Bend in March, and it will take until the back half of 2015 to bring that well into production as we execute on all the subsea tie-in and infrastructure that's needed to make this a producing well. Since we've booked only minimal reserves associated with this discovery, we'll likely see reserve additions in 2016 after we see well performance and production characteristics. These longer lead-time projects necessary to create lumpy financial results, initially inflating DD&A or finding cost, but we think the long-term value addition from these high-impact projects is more than a fair trade-off. We anticipate gross peak rate from production from Big Bend to be approximately 22,000 barrels of oil equivalent per day in a P50 case, and have a full cycle pretax entity of about $145 million. Gross resource estimate is between 30 million and 65 million barrels of oil equivalent, which is a P75 to P25 range. The next oil discovery after Big Bend was Dantzler. Again, a 20% working interest at Mississippi Canyon block 782. We anticipate this discovery will be sanctioned by the operator shortly, and that we will go ahead with the completion phase this well. Also pleased the operators decided to drill a second well at Dantzler, which will be another exploration well to potential expand this field. We've exercised our right to participate with 20% working interest like the previous well, and expect it to spud in 2014. First Dantzler well is expected to have a gross peak production rate of 23,000 barrels of oil equivalent per day. As a pretax NPV of about $110 million assumed at a P50 case, and a gross restore's estimate of between 55 million to 95 million barrels of oil equivalent, which is again a P75 to P25 case. We expect to add a portion of reserves that will be associated with well in 2014, with more to come in the year in which the well goes on production, which will probably be in 2016. Obviously, a second successful well out there could just make this a lot bigger. If you'll recall, late last year, we acquired Callon's interest in Mississippi Canyon's block 538 and 582, referred to as Medusa. It's another high-potential project in early stages of possible expansion where we have a 15% working interest. Production from the associated spar platform net to our interest at 900 barrels per day, which is 90% oil. Production from our nearby operated Gladden field also flows into that spar platform, which provides us data around the area. The thing that excited us last year about this acquisition is not only the current production reserves of Medusa, but the significant future drilling prospectivity that we see in the [indiscernible]. We're currently planning to drill a new well at Medusa this year and convert what we see is probable reserves and the proved reserves. Onshore in the Permian Basin, operators are very active around our Yellow Rose acreage and we're continuing to see valuations and expectations rise. New data about drilling and completion techniques that enhance production rates and ultimately, recoveries are being released, and we're benefiting from what other operators are devoting large amounts of capital to discover. We continue to see operators in the Midland Basin announce substantial well results across multiple stacked targets. We believe the industry is only just beginning to realize the potential value of horizontal development in the Permian Basin, particularly in the northern Permian Basin. As you've heard me say lately, we're all still -- we are still, in fact, gathering stage as we work our way to developing a more standard process of drilling and completing horizontal wells in the northern Permian Basin. More on that discussion will come late in the year or early next year as we complete this year's horizontal drilling program. For the first quarter of 2014, total production volumes averaged 48,400 barrels of oil equivalent per day, and were split 52% liquids and 48% natural gas. Some production was and is deferred due to third-party pipeline outages, severe weather platform and maintenance issues and some disruptions caused by various operational issues. Additionally, our West Texas production was impacted in the first quarter by severe winter weather. We estimate the total impact of these deferrals on the first quarter 2014 to be approximately 661,000 barrels of oil equivalent or 4 Bcf equivalent. Two of these issues remain unresolved, and we expect to continue to see some production referrals again in the second quarter. We're adjusting our annual production guidance to reflect these continuing disruptions. And out of an abundance of caution, we're peeling back a few Bcfe of production additions attributable to potential acquisitions that were previously included in our guidance. Now I'll turn the call over to Jamie Vazquez to review some key items and update you on current operations. Jamie?

Thank you, Tracy. Revenues in the first quarter were $254.5 million, and our adjusted EBITDA was $168 million and our adjusted EBITDA margin was strong at 66%. As in our ongoing discussions with the governmental agencies to address the 2 notices we received in November 2013, we do not have any updates at this time. As an operator for over 30 years in the Gulf of Mexico, we believe that our focus on operating safety, properly and reliably will allow us to continue to build on our solid track record for excellence. In fact, our safety record or DART ratio for 2013 was far better than the industry average in the Gulf of Mexico. Next, I'll summarize the projects underway in our second quarter drilling plan. Offshore. We have 2 rigs operating, 1 rig currently on location at Ship Shoal 349 or Mahogany field, and the other at East Cameron 321. At Mahogany, we initiated a subsalt development as a 3-well drilling program in 2010. Well, here it is in 2014, some 4 years later, and we're continuing to drill more wells and find more oil. The field just keeps getting bigger. Net sales at Mahogany are up 470% since 2011. We are in the process of obtaining new, wide azimuth seismic data over this field, which can help us expand the field further, including prospective deeper zones. Our 2014 capital program includes 3 drill wells and 1 recompletion at Mahogany. We just completed and commenced production of the A-15 exploratory well at an initial rate of approximately 840 barrels of oil equivalent per day, with 82% liquids, which logged over 65 feet of measured depth pay in the P sand. The well is still cleaning up and has only been on production for a few days. The rig has moved over to the A-6 well to conduct a recompletion in the new N sand, which was a successful operation we should reinstate production in the A-6 in the second quarter. Following the A-6, we plan to drill the A-16 development well, which targets reserves in the M, N, O and P sand identified during the logging of the A-14 exploration well last year. As you recall, the A-14 well was drilled to test multiple sands, including the T sand, resulting in new field pays beyond the main field pay of the P sand. This successful discovery is still producing very well from the T sand with a current rate of over 3,000 barrels of oil equivalent per day net to W&T. We plan to drill the A-16 well to 15,000 feet total vertical depth and has a target IP rate of 1,800 barrels of oil equivalent per day, likely sometime in the fourth quarter this year. An additional exploration well, the A-17, is likely to spud near the end of the year. One final comment on Mahogany and its subsalt characteristics is that its continued success is helping us unearth other potential targets at our other operated fields that are in and around subsalt structures on the conventional shelf. This is why we're so enthusiastic about our success at Mahogany, as we learn more, we can imply it elsewhere. In fact, we are acquiring higher-quality seismic data around other subsalt features, which we believe will assist us greatly with field studies and should identify new opportunities in these producing fields. Let's move to East Cameron 321, the A-2 side-track well. We've already logged approximately 120 feet of potential pay in 4 upper zones and are drilling to total depth. Additional exploration targets have not yet been reached. Our initial production estimate for this exploration well is approximately 850 barrels of oil equivalent per day net to W&T, and about 60% of the production is expected to be crude oil. Assuming that these efforts are successful, we expect productions to be on in mid to late June. Moving onshore at Yellow Rose. We are working to identify horizontal potential of our acreage and are in the very early stages of testing the Wolfcamp B zone, which is our initial horizontal test program. We recently completed drilling the lateral section of the second operated Wolfcamp B horizontal well, the Chablis 13H in Martin County. The well was drilled to a total depth of 15,350 feet and that included a lateral length of 5,375 feet. The third horizontal Wolfcamp B well will follow the Chablis 13H from the same drilling pad. In Andrews County, our joint venture Wolfcamp B horizontal well has been completed and began flowback operations within the last week. We expect to see flowback results in the coming weeks. Our vertical drilling program at Yellow Rose has remained active with 2 rigs running. In the first quarter, we completed 6 wells on 80 acre spacing and 2 wells on 40 acre spacing. And as an update in East Texas at the Star Project, we reassigned approximately 145,000 net acres back to the original assignor and do not have further drilling plans in East Texas at this time. Now I'd like to turn the call back over to Tracy.

Thanks, Jamie. We're continuing to make excellent progress building the value of our assets, in particular our Yellow Rose fields has increased substantially in value over last year or so, and we've been approached by various parties about potentially monetizing that value. We've always said that we're going to monetize any asset at the right price. As a result, we chose to open a data room and conduct limited process. We didn't receive any acceptable bids. That process is now behind us. And we're very enthusiastic about continuing to add production reserves at Yellow Rose as we start to plan for a robust drilling and development effort in the future. The acquisition market also is robust and presents many more opportunities. We're seeing more quality assets, anticipate more acquisitions for this year and beyond. Our approach toward growth in the deepwater is progressing well. We're finding world-class assets in this basin. Now, operator, with that, we're ready to take questions.

[Operator Instructions] Our first question comes from the line of Neal Dingmann with SunTrust.

The question I was wondering on, just Tracy, I know you're going to continue both on and offshore, and you mentioned kind of the details of that. When you look at, I guess, first, onshore, your thoughts about extending some of the laterals and some of the completions, or I guess, how should we think about you guys tackling or developing this?

Yes, that's a great question, Neal. Thanks. What we expect at Yellow Rose is a continuing effort toward different sands in the area. We'll be pushing pad drilling in the future and multi-laterals. First pad drilling is now going on at our Chablis well, I believe, 13H Chablis is that number. And we expect to see a little bit longer laterals probably somewhere at around a range of 7,000 to 7,500 feet, so that's kind of what we're looking at. Obviously, we're looking at this with an eye of driving the F&D cost down over time and doing this as a more standardized process, which will, of course, lower the cost as we go forward. We're pretty confident that we've got good economics going forward. Now it's just a matter of time to optimize that and optimize the completions. We do see potential in the Wolfcamp, of course, but also in the Spraberry and the Jo Mill and maybe a couple of other formations in the area.

Okay. And then I like to always ask you on, you guys have a ton of offshore projects it looks like coming online here in the next coming quarters. I guess, in addition to that, Tracy, I guess, is it's fair to say you'll continue to be active just -- I guess, what is the M&A market look like offshore? Is it a bit more competitive than it's been, or is there still a ton of opportunities?

I think there's a lot of opportunities. We've been doing this a long time, and I've heard this mantra over years and years. Well, you know it's getting tight, the opportunities aren't there, you're going to have to go to a different basin, you're going to do this, you're going to have to -- Gulf of Mexico is dead and there's nothing left on the shelf. Well, there's plenty left on both the shelf and the deepwater. We prove that every year. We like the opportunities out there. We're seeing opportunities on land as well. So the problem isn't whether we're going to be able to have opportunities the issue is having to figure out how to manage your finances, so that we still operate in a cash flow environment.

Got it. And then lastly, you continue to throw off just a ton of cash flow more than most of your peers. Your thoughts as far as -- I mean, do you have enough places to go with this, or would you return this to shareholders, I don't know, either buy some stock back or a big dividend?

We've done a special dividend 6 out of the last 7 years, so that's always near and dear to my heart. Yes, I mean, if the stock just to on unacceptable level to us, so we'll look at buying that as well. I don't really care whether I buy reserves in the open market or I buy it off the shelf from W&T. That's fine with me, but it's not the primary focus for us to buy our shares back. We do it occasionally, anyway, as a function of providing shares for employees' incentives and things like that. But I still favor dividends, I still favor, going forward, with growing the company in multiple basins and we think we'll have lots of opportunity for years to come.

Our next question comes from the line of Richard Tullis with Capital One.

Tracy, could you give us a little more detail on how much downtime you have built into your second quarter guidance, and what the current production rate is?

Yes, current production rate is between 48,000 and 49,000 barrels of oil equivalent per day. We've had a shutdown at Tahoe due to a pod problem, which is part of the infrastructure for getting the gas to the platform. We're waiting for parts. So that's down, I guess, 12 million, 14 million a day. And then we've got Wrigley that we had expected to come online, I don't know, literally, for about the last 6 months. It keeps getting delayed 1 more month. The platform is now -- the work on the platform has now been completed. The well isn't quite back online yet. They're still having some infrastructure issues they need to deal with. But we should be online fairly soon. Shell is the operator there, and that's about 12 million to 14 million a day as well. And then we got another little pipeline outage, that we didn't anticipate earlier in the year, it's about 8 million cubic feet a day or so probably going on for several weeks. So all in all, maybe down 30 million to 35 million a day for a period of time.

Okay. CapEx spending for the quarter looked below, say, a prorated rate for the full year. How do you see spending over the rest of the year? Do you think that you may come in under your budget?

No, I don't think we'll come in under budget. I think we'll have more CapEx. We're going to start drilling some more wells in the deepwater also. So as I mentioned, Dantzler is going to come up and looks like we're going to be doing Medusa as well.

Okay. Is there any potential cost impact from, I guess, ceasing operations at the Star Project and returning the -- reassigning the acreage back to the original holder?

No, not really. I mean, there's -- we've spent the money there already. There's nothing more to spend there in the way of being a liability or anything like that. We don't have much concern about that. So it was worth trying. And we did have some encouraging results at first, we did find some oil. It just wasn't enough.

Okay. And just lastly, I know Jamie mentioned it, about the status of the issue -- regulatory issues with the federal government. Anything more you can add to it? I mean, where do things stand right now, and any potential for resolution near term?

Well, near term is a relative term, right? So it's a process. We're working through it. I think things are going reasonably well. I'm not under concerned with it; I'm not over concerned with it. We've dealt with regulatory issues over several decades that you just deal with as a normal part of your business. I'm not trying to minimize this or maximize it. I'm just telling you that we're continuing to do what we need to do to resolve it, and I believe we will resolve it sooner rather than later.

Our next question comes from the line of Brian Foote with Clarkson.

Tracy, within the original guidance, which was rather wide, you did mention this morning that you had peeled back some of the guidance related to acquisitions that were originally contemplated or coming in. Can you give any specificity as to the size of that? And I know the original guidance was 17 to 18.9. How much of that variance was related to things that you are contemplating? And then how much -- I mean, you've already answered that with Richard's question, how much was related to the delays?

It was only a few Bcf, Brian. It wasn't substantial. It was just a few Bcf. I've never liked to give a whole lot of detail about any of the ongoing acquisition efforts that we have. We do acquisitions because we think they're going to be profitable to the company, and we expect to buy them at certain prices. And sometimes, things work out, and most of the time, they do, sometimes they don't. When there is uncertainty around it, then we'll peel back a little bit. We normally don't put acquisitions into our predictions, so this is kind of a first-year effort. It's probably a mistake on my part to think about it originally, as practically a done deal when we do that. People pick it up in the press and they think that's what we're going to do just because we've already said we're going to do it. So we're not here to get into much more detail about that. But a deal at the right price is what we're going to do. And if it doesn't work out at the right price, then we won't do it.

Great. And just one more. In terms of the 3D seismic reinterpretation and the new seismic data you're acquiring on the subsalt accumulations, when should we expect you to start drilling those opportunities? How long does that seismic acquisition and interpretation take for these things?

It really doesn't take long once we get the data. Most of the places, we already have a pretty good knowledge base. We're just enhancing the 3D that we already have. So once we get it in the machine, it takes just a few weeks to analyze that. But of course, it takes a little while after that to make plans and get wells drilled. But analyzing the data is a fairly quick process. We expect to have that data latter part of this year, early part of next year. So it's a pretty big day to shoot around there, so we're pretty excited about it. We see opportunities that we think will translate into dollars going forward. Clearly, at Mahogany, that's been the case. I mean, the thing I like about that field is, every time we get new data, we find more wells to drill and find more reserves so that's very encouraging. We've got a pretty good inventory build on data going from 2015 to 2016, and so we expect to see that inventory build in that same time frame and even beyond, of course, that's the idea.

Our next question comes from the line of Noel Parks with Ladenburg Thalmann. Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division: Just some thinking about the gas strip, it's the best we've seen in a while. What's some of the lowest hanging fruit you'd have to go after if gas stayed strong or strengthened from here?

Well, that's a really good question. I guess, the thing that we look at is a comparison of economics across our entire base. I mean, we have things that would emanate from platforms, projects that would probably be platform drilling-related in terms of gas targets that we would probably go after first, I guess, probably be the best low-hanging fruit. Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division: I guess I was thinking about, I didn't know if there were in the recompletion inventory, there might be things you'd look at near term.

That's what I'm talking about as well. These would be platform projects where we don't have to get a rig out there, a jack-up or a floater or anything like that. These would be issues that we would undertake as workovers or recompletions. Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division: Got it. And then just at Yellow Rose, just talk a little bit more about your thoughts about what might be next, as far as deeper targets or your priorities in looking at the different ventures [ph].

In West Texas? Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division: Yes.

Yes, sure. Well, the industry has given us a lot of insight into that. We're starting to see success in the Wolfcamp B and also the Spraberry, which is a little bit higher. The Wolfcamp B looks to be very successful. We're not quite ready to go drilling wells in D yet, but they're drilling some wells around us but their pretty prolific, so we're encouraged about that. So we have actually targets up and down from our existing current targets in Wolfcamp A, Wolfcamp B.

Our next question comes from the line of Michael Glick with Johnson Rice. Michael A. Glick - Johnson Rice & Company, L.L.C., Research Division: Just a question on Big Bend. What are kind of the key variables associated with the timing of first production there? I mean, what could push it closer to the second half or third quarter versus kind of into '15?

Well, that's -- we're not the operator there, but as a general function, it's long lead-time items, pipelines and umbilicals and wellheads. Michael A. Glick - Johnson Rice & Company, L.L.C., Research Division: Got you. I know you're not the operator at Dantzler, but what's the second-well testing? Is that testing the down-dip extent of what you've found?

I'm not going to comment on exactly what it is, but yes, I mean, it would be an extension to the field.

[Operator Instructions] Our next question comes from the line of Patrick Rigamer with Global Hunter Securities.

With East Texas behind us, just curious if you could comment on kind of the new venture opportunities, and whether or not you're continuing to look outside of the Gulf and the Permian, or if you think your focus going forward would primarily those 2 areas?

That's another good question. Yes, we are. Not only are we looking outside of the Gulf and other basins, but also internationally.

Any additional comments on what you might be looking for internationally?

Yes, the first thing we'd look for is a piece of cash flow, so that would be important to us. Wouldn't necessarily want to jump out there and just do exploration. We could -- we've looked at those opportunities as well. And of course, my standard reply to all this is we're not going to go any place where they're going to shoot at us or not pay us.

All right. And then offshore or onshore international, or...

Either one.

Mr. Krohn, there are no further questions at this time. Please continue with your closing remarks.

I appreciate it, operator. We're done, and we'll talk to you next quarter, if not, before. Thank you very much.

Ladies and gentlemen, this concludes the W&T Offshore's First Quarter Earnings Conference Call. If you'd like to listen to a replay of today's conference, please dial 303-590-3030, and enter code 4679511. ACT would like to thank you for your participation. You may now disconnect.