W&T Offshore Inc (WTI) 2014 Q1 法說會逐字稿

Good morning ladies and gentlemen. Thank you for standing by. Welcome to the W&T Offshore 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 of the first quarter of 2014.

Before I turn the call over to the Company, I have a few items that 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 at www.wtoffshore.com or via recorded replay until May 14. To use the replay feature call 303-590-3030 and our 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. Please refer to our first-quarter 2013 earnings release for disclosure on forward-looking statements.

At this time I would 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 the 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 multi-year projects, increased 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 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 operating wells in 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 analyst 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 and 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 is 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, multi-year 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 part of projects of Mississippi Canyon 699 Troubadour and Mississippi Canyon 782 Dantzler, both discoveries in 2013.

We're now committing to a second Dantzler well inspired by our 2014 deepwater drilling plans. The best thing about this is the reserve additions and production impact are very significant. These are substantial products 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 hookup, production, and development.

Completion operations were finalized at Big Bend in March. And 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 mining 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 the P50 case and have a full cycle pretax NPV 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 completion phase as well. We're also pleased that the operators decided to go with a second well at Dantzler, which will be another exploration well to potentially expand this field.

We've exercised our right to participate with 20% working interest like previous well and expect it to spud in 2014. The 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 assume a P50 case and a gross restores 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 the well in 2014. With more to come in the year in which the well goes on production which will probably be in 2016. Obviously, the second successful well out there could just make this a lot bigger.

If you'll recall, late last year required 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 is 900 barrels per day, which is 90% oil.

Production from our nearby operator, 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 prospect activity that we see in the field area. We're currently planning to drill a new well at Medusa this year and covert what we see as probable reserves into 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 stack 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 are still in fact -- gathering stage as we work our way to developing a more standard process to 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 we're 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 of 2014 to be approximately 661,000 barrels of oil equivalent or 4 Bcf equivalent.

A few of these issues remain unresolved and we expect to continue to see some production deferrals 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 an ongoing discussion with the governmental agencies to address the two 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 industry average in the Gulf of Mexico.

Next I'll summarize the projects underway in our second-quarter drilling plan. Offshore, we have two rigs operating. One rig currently on location at Ship Shoal 349, our Mahogany field, and the other at East Cameron 321.

At Mahogany, we initiated a sub-salt development as a three-well drilling program in 2010. Well, here it is in 2014, some four 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 at 470% since 2011. We're in the process of obtaining new Wide Azimuth seismic data over this field which can help us expand the field further, including perspective deeper zones.

Our 2014 capital program includes three drill wells and one re-completion at Mahogany. We've 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 re-completion 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-sands 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 for the T-sands with the 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 of this year. An additional exploration well, the A-17, is likely to spud near the end of this year.

One final comment on Mahogany and its sub-salt characteristics, is that it's continued success is helping us unearth other potential targets at our other operated fields that are in and around sub-salt structures on the conventional shelf. This is why we're so enthusiastic about our success in Mahogany. As we learn more we can apply it elsewhere. In fact, we're acquiring higher quality seismic data around other sub-salt features which we believe will assist us greatly with field studies, and should identify new opportunities in these producing fields.

Let's move to the East Cameron 321, the A-2 side-track well. We've already logged approximately 120 feet of potential pay in four 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 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 are 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 path.

In Andrews County, our joint venture Wolfcamp B horizontal well has been completed and began flowback operations within the last week. We expect flowback results in the coming weeks.

Our vertical drilling program at Yellow Rose has remained active with two rigs running. In the first quarter we completed six wells on 80-acre spacing and two wells on 40-acre spacing. 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 would 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 field has increased substantially in value of 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 the 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 access and anticipate more acquisitions for this year and beyond. Our approach toward growth in deepwater is progressing well. We're finding world-class assets in this basin.

Now operator, with that we're ready to take questions.

Thank you Mr. Krohn.

(Operator Instructions)

Neal Dingmann, SunTrust.

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

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-lateral's. First pad drilling is now going on at our Chablis well. I believe 13H Chablis is that number.

We expect to see a little bit longer lateral's, probably somewhere in the round range of 7000 to 7500 feet. So that's what we're looking at.

Obviously, we're looking at this with an eye of driving the F&D costs down over time. 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 trying to optimize that and optimize the completions. We do see potential in the Wolfcamp, of course. But also in the Sprayberry 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. In addition to that, Tracy, I guess it's fair to say you'll continue to be active just on a -- what is the M&A market look like offshore? Is it a bit more competitive than it has been or is there still just 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 is getting tight. The opportunities aren't there.

You're going to have to go to a different basin. You're going to have to do this. You're going to have to -- Gulf of Mexico is dead and there's nothing left on the shelf. There's plenty left on both the shelf and the deepwater and we prove that every year.

We like the opportunities out there. We're seeing opportunities on land as well. 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 the cash flow environment.

Got it. Lastly, you continue to throw out just a ton of cash flow. More than most of your peers. Your thoughts as far as -- do you have enough places to go with this or would you return this to shareholders in the -- either buy some stocks back or a big dividend?

We've done a special dividend six out of the last seven years. So that's always near and dear to my heart. Yes, if the stock gets to an unacceptable level to us, 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. 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 employee incentives and things like that.

I still favor dividends. I still favor going forward with growing the Company in multiple basins and we think we'll have lots of opportunities for years to come.

That makes a lot of sense. Thanks, Tracy.

Richard Tullis, 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. Our 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.

That's down, I guess 12 million, 14 million a day. Then we've got Wrigley that we had expected to come online -- literally for the last six months. It keeps getting delayed one more month.

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.

We should be online fairly soon. Shell is the operator there. That's about 12 million to 14 million a day as well.

Then we've 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 go on for several weeks. So all in all, maybe down 30 million to 35 million a day for a period of time.

CapEx spending for the quarter looked below 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 as well.

As I mentioned, Dantzler is going to come up. It looks like we're going to be doing Medusa as well.

Okay. Is there many potential cost impact from season operations at the Star Project and reassigning the acreage back to the original holder?

No, not really. We've spent the money there already. There's nothing more to spend there in the way of P&A liability or anything like that. We don't have much concern about that.

It was worth trying and we did have some encouraging results at first. We did find some oil. It just wasn't enough.

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

No. Near-term is a relative term, right? 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. You just deal with it 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.

That's all for me. Thank you Tracy.

Brian Foote, Clarksons.

Good morning. 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? I know the original guidance was $17 million to $18.9 million.

How much of that variance was related to things that you were contemplating? And then how much -- you've already answered that in Richard's question how much was related to the delays and --?

It was only a few Bcf, Brian. It wasn't substantial. It was just a few Bcf. I never like 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. We expect to buy them at certain prices. Sometimes things work out and most of the time they do, sometimes they don't. When there's uncertainty around it, then we'll peel back a little bit.

We normally don't put acquisitions into our predictions. So this is 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've got 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.

A deal at the right price is what we're going to do. If it doesn't work out at the right price then we won't do it.

Just one more in terms of the 3-D seismic reinterpretation and the new seismic data you're acquiring on the sub-salt 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 3-D that we already have.

Once we get it in the machine, it takes just a few weeks to analyze that. Of course, it takes a little while after that to make plans and get wells drilled.

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 date issue around there.

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.

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 built on data going from 2015 to 2016. And so we expect to see that inventory build in that same timeframe and even beyond. Of course, that's the idea.

Great. Thanks very much.

Noel Parks, Ladenburg Thalmann.

Just some thinking about the gas strip. It's the best we've seen in a while. What sort of a -- the lowest hanging fruit you'd have to go after if those gas [stage stayed strong or] are strengthened from here.

That's a really good question. I guess the thing that we look at is a comparison of economics across our entire base. We have things that would emanate from platforms. Projects that would probably be platform drilling related, in terms of gas target, that we'd probably go after first. I think that's probably -- would be the best low hanging fruit.

I guess I was thinking about, I didn't know if there were -- in the re-completion 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 work overs or re-completion.

Got it. Then 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 benches.

In West Texas?

Yes.

Sure. The industry has given us a lot of insight into that. We're starting to see success in the Wolfcamp B and also the Sprayberry, which is a little bit higher. The Wolfcamp B looks to be very successful.

We're not quite ready to go drill any wells in the B yet. But they're drilling some wells around us that -- they're pretty prolific. So we're encouraged about that.

We have actual targets up and down from our existing current targets at Wolfcamp A and Wolfcamp B.

Okay, great. That's it for me.

Michael Glick, Johnson Rice.

Just a question on Big Bend. What are the key variables associated with the timing of first production there? What could push it closer to the second half or third quarter versus end of 2015?

We're not the operator there. As a general function, it's long lead time items, pipelines and umbilicals and wellhead's.

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 found?

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

All right. Thank you.

(Operator Instructions)

Patrick Rigamer, Global Hunter Securities.

Good morning. With Texas behind us, just curious if you'd comment on the new venture opportunities. Whether or not you're continuing to look outside of the Gulf and the Permian or if you think you focused on four, it would be primarily in those two areas?

That's another good question. Yes, sir, 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 and we've looked at those opportunities as well. Of course my standard reply to all this is, we're not going to go anyplace where they are going to shoot at us or not pay us.

And then offshore or onshore, international or --?

Either one.

Okay. Thank you very much.

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.