W&T Offshore Inc (WTI) 2012 Q2 法說會逐字稿

Ladies and gentlemen, thank you for standing by. Welcome to the W&T Offshore second quarter earnings conference call. During today's presentation, parties will be in a listen-only mode. Following the presentation, the conference will be open for questions.

(Operator Instructions)

This conference is being recorded today, Tuesday, July 31, 2012. I would now like to turn the call over to Mark Brewer. Please go ahead.

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 second quarter of 2012.

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 selection of the company's web site at www.wtoffshore.com or via recorded replay until August 7, 2012. To use the replay feature, call 303-590-3030 and dial the pass code 4549376. Information recorded on this call speaks only as of today, July 31, 2012, and therefore time-sensitive information may no longer be accurate as of the date of any replay. Please refer to our second quarter 2012 earnings release for a 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, Mark. Good morning, everyone.

We appreciate your interest in W&T and we thank you for joining us on our second quarter 2012 earnings conference call. Here with me today are several members of our Management including Jamie Vazquez, our President; Danny Gibbons, our Chief Financial Officer; Steve Schroeder, our Chief Technical Officer; and I'd also like to introduce Tom Murphy, who joined W&T in June as Senior Vice President and Chief Operations Officer. Tom obtained a BS in petroleum engineering from the Colorado School of Mines and over the last 28 years has gained extensive operating and management expertise while working at companies such as Woodside Energy, PetroQuest, Devon and Arco. He's held a variety of engineering, operational, and commercial positions domestically and internationally, onshore and offshore, including Gulf of Mexico deep water and the onshore unconventional plays. Steve Schroeder has agreed to take on the newly created position of Chief Technical Officer, where he can lend his technical expertise to the company with specific focus on our acquisitions and other special projects.

As historically during our quarterly conference call, various members of our Management team delivered prepared remarks regarding our quarterly results and operating activities. This quarter, we thought it would be a bit more efficient to include a lot of the information in the earnings release that we would normally provide in our conference calls to facilitate your review and understanding. This way, you have the information in advance, which should help facilitate a more active question-and-answer session. So we're assuming you've had a chance to review the release we put out yesterday and hopefully we'll spend most of our time on this call addressing your questions. I'll provide a brief review of some of the quarter's key highlights and I'll update you on current events and plans and then we'll be happy to take your questions. So let's get started.

In the second quarter, we had another strong performance, with production volumes averaging 48,600 barrels of oil equivalent per day. That is up 6.8% from the same time last year. Volumes are up this year as a result of the acquisitions that we did last year with not only the west Texas properties but also the Fairway Field acquisition.

Additionally, we've continued to have good success with the drill bit in the Gulf of Mexico as well as in west Texas. In fact, second quarter production came in around expectations, despite the down time we experienced during the quarter. Between the third-party pipeline outages that happened in April and the downtime associated with tropical storm Debbie, we deferred about 2,200 barrels of oil equivalent per day.

For most of July, we were producing around 49,000 barrels of oil equivalent per day. We're currently experiencing some down time at Matterhorn due to a third-party pipeline outage that's expected to be a short-lived event. In fact, our guys tell us that's probably going be online this weekend. Regardless, we're reaffirming our prior full-year guidance. Those guidance details are in the earnings release.

So, good things are happening. We've been successful at focusing on crude oil and our production mix. In the second quarter, oil sales represented 71% of total revenues while NGLs represented 12% and natural gas represented 17% of total revenues.

In our deep water Matterhorn field located in Mississippi canyon 243, we have increased production 75% in the past 12 months. That is going from 3,390 barrels of oil equivalent per day net in July of 2011 to 6,027 barrels of oil equivalent per day net in July of 2012 As a result of drilling the A4 side track well and re-completing the A7 well, we own 100% of this oil field.

At our Mahogany field located on the shelf in ship shoal 349/359, we've increased production 115% in the past 12 months with our ongoing drilling program. Basically it took it from 1,921 barrels oil equivalent per day net in July of 2011 to 4,139 barrels oil equivalent per day net in July of this year, as a result of drilling three wells, the A11, A1 sidetrack 4, and the A13 wells. This doesn't include the a5 sidetrack well that we anticipate will come on production later this week, adding about another 900 barrels oil equivalent per day to our production. We own 100% of this oil field as well.

We were apparent high bidder on 11 of 13 bids submitted in the recent OCS sale held on June 22, 2012. That exposed approximately $2.8 million and $2.5 million in high bids. We will continue to add prospects to our prospect inventory using lease sales and third party submittals, both on the shelf and in the deep water Gulf of Mexico as well as our own existing acreage inventory.

In west Texas, we have successfully decreased the drilling days per well from 23 to 12 in our Yellow Rose field. This is about a 50% improvement in our rig utilization. We're well ahead of schedule in our lease obligations. We have made fundamental well design changes, as well as significant time reductions by using newer technology rigs and top drive systems. We have also drilled our first horizontal well in the field. We're in the process of performing a 20-stage frac treatment.

Further to that, we're making strides improving our completion methodology to improve recovery and production rates in the field. We currently have seven wells waiting on frac treatments and see the opportunity to further increase field production by streamlining our timing from rig release to frac treatment. As a reminder, we currently have reserves booked on only 80 acres spacing for the Wolfberry. So there's still a lot of upside in the field with down-spacing and with the potential results of our horizontal well, which is currently in the completion phase.

In east Texas, we have completed our second well of the four well delineation program. The well is currently flowing back. We are on schedule to complete the four-well program in 2012, which will provide the information needed to determine if we want to launch a development program in 2013 on our 143,000 acres. We believe this project has tremendous upside.

All of our 2012 budgeted wells are currently on schedule. The company is in a really good position. We expect to see a continuing transformation onshore in both west and east Texas. We expect to be in at least one other basin on shore. We expect to spud a deep water exploration well in the third or fourth quarter of this year.

Finally, we expect more acquisitions in the not too distant future. We note that the bid/ass spread has been too high since the fall in prices this year, but we're seeing a plethora of assets for sale. We think there will be more M&A activity in the second half of this year and beyond. W&T is very well positioned, with about $600 million in liquidity.

With that, operator, I'll open up the lines for Q and A.

Thank you. We will now begin the question-and-answer session. (Operator Instructions)

Noel Parks of Ladenburg Thalmann & Company.

I had a couple of questions. In the James lime, I seem to remember that you had previously commented that you expected rich gas out of it. I noticed in the operations update that it described it as an oil-rich play. Are you thinking more it's going to be oil or condensate, as opposed to NGLs?

You're very observant. The answer to that is yes.

Has anything changed in your understanding to lead to that conclusion?

Yes.

Anything -- could you be a little more specific? (laughter)

No. (laughter) Actually, we're in the process of flowing the second well back. We changed it to oil rich because we've noticed some crude in that flow back.

Okay, great. And then, just wanted to check a little bit of housekeeping. I noticed there was a pretty big asset retirement item for the quarter in the cash flow statement. And if I read it right, it looked like it was a cash item. Is that something in particular, or something nonrecurring this quarter, or something we should see more of going forward?

I would appreciate it if you would be a little bit more specific which -- what that is, Noel.

Oh, I'm sorry. In the statement of cash flows for the quarter, it looked like there was a $20 million or so item for asset retirement. And it was just a larger amount than I'm used to seeing in a given quarter. So, I just wondered if there was anything particular behind that?

No. We've got ongoing obligations to plug and abandon. And either we do the work, or the work gets deferred depending upon what the rest of our schedule is. So, I do not think that is unusual. The item that I think you're looking at was approximately the same as it was in 2011 as well.

Michael Glick with Johnson Rice.

Just a quick question on Yellow Rose. What's the potential timeline for releasing results from the first horizontal well there? And too, if you like what you see, any plans to drill additional horizontals out there this year?

Right now, we're doing the frac. So, as soon as we get the frac done, and we get flow back on it, we can establish some sort of result, then we'll evaluate that. But I do expect that we'll be drilling more horizontal wells in west Texas. That's kind of the point. We've got two more wells that we've got scheduled to drill before the end of the year.

And is the rig going from Yellow Rose to Terry County to drill the horizontals out there?

No. Those are separate rigs.

In Terry County, is that also going to be a Wolfcamp test?

What's that?

Is Terry County also going to be a Wolfcamp test?

No, we haven't announced that, but I will tell you that, that rig is moving on first of September.

Richard Tullis with Capital One Southcoast

Congratulations on a good quarter.

Thank you, sir.

Tracy, jumping over to the acquisitions front, how likely do you see it as having something to announce by year end on that front, whether it's onshore or offshore?

I never know how to answer that question. People ask me that question a lot -- when are you going to do the next one? What we're seeing is a pretty big disparity in bid ask. I think a lot of that's a little bit of sticker shock from the reduction in prices of oil and gas, and then, you know, they're all different types of transactions. All I know is that we're in a lot of data rooms. There's a lot more assets for sale than there have traditionally been in the past. I just have to believe that we'll get our fair share of them. I believe that we'll get something done by the end of the year. But I'm certainly not going to warrant that.

And with that $600 million in liquidity, or thereabouts, what would you be comfortable doing size-wise?

It really kind of depends on the size of the deal. If you mortgaged it like you do your house, where you put a 20% down payment, well then, about $3 billion. If it's something that doesn't have a lot of cash flow, then of course, it'll be less than that. But it's really -- every single deal is a bit of a hybrid.

Biju Perincheril with Jefferies.

Tracy, have you guys done a mid-year reserve update? Can you give us some color there?

We haven't included a mid-year reserve update.

At the Yellow Rose project, have you drilled any 40-acre wells? What is the timing of testing that? And can you remind us again how much were the reserve seat booked so far at Yellow Rose?

Since we haven't given a mid-year update, we haven't updated reserves at Yellow Rose in particular. Year-end reserves were about 28.1 million barrels. We are currently evaluating 40-acre spacing, and even down to 20 acres as well.

So, you do have 40-acre and 20-acre wells producing currently?

We believe that this particular field will operate as low as 20 acres. We haven't booked it like that, but that's our belief in-house. We think that it's there. We think that -- and that's, of course, on a purely vertical case. So, when you throw in horizontal wells, you have to make that determination on how many wells you're going to drill horizontally and how many vertically. And that's what we're really trying to evaluate right now.

And at this point, is your expectation that this entire area could be prospective for horizontal development?

Well, not all of the acreage, because it doesn't all fit in a nice little box for horizontal drilling. So, if you can imagine this -- if you had a horizontal well going north and south, and east and west from a single point, because of the curvature of the wells, you'd still have to drill a vertical well right in the middle of those four wells. So that you could recover the wells that are encapsulated in that area between the curvature of all those wells going north, south, east and west. That's kind of an idealized case, but there will be cases where we will still drill vertical wells, but we believe that we'll get more efficient with the horizontal wells.

And then one last question. On your NGL barrels, can you give us a breakdown of how much ethane do you have, and heavier molecules?

I'm not sure if I have that breakdown for you. Andy? I've asked that question before; I just don't remember the numbers. Ethane is probably a larger component than anything else. Probably -- I seem to remember about 30% ethane. I could be wrong on that, but I think that's what it is.

Adam France with 1492 Capital.

Thanks for squeezing me in, Tracy. Any details you could give us as to the size of these three exploration wells you're going to be chasing in the main pass area, or any more details on your deep water test?

We don't normally give out reserves prior to drilling exploration wells, but I will tell you that with regard to the deep water well that we -- I'm hoping we'll get that thing spudded in the third quarter. I can't warrant that because we're not the operator. But that's what I -- kind of gut feel that is what I think we'll end up doing.

Anything about these three exploration wells in Main Pass that are particularly more difficult than what you usually do out there?

We'll update that when it gets a little bit closer. Right now, it is probably not appropriate to do that, but, no, I don't see anything terribly different.

Phil McPherson with Global Hunter Securities.

Nice job on the quarter. Since you threw it out there on the deep water spud in the third quarter, I was wondering -- do you think that is something that you would then press release or put an 8K out and tell us when it's been spudded, or give us more details once that occurs?

Yes, I'm sure that we will, yes.

As far as the west Texas stuff on the -- would you think you'd include the horizontal wells, since so many people are focused on that? Do you think you'd give us results before the next quarter on that well, or will you kind of stick to just doing your quarterly operations update?

In west Texas, if we can get all of the results by next quarter, I'll give that to -- I'll give that out. It takes a period of time for these things to flow back. And flowback is sometimes relative to whether you're flowing it or pumping it. So, if we get results before then, I'll give it out.

Great. Appreciate it. Good luck on hunting for some M&A, too.

Thank you, sir.

(Operator Instructions) Joe Bachmann with Howard Weil.

Good morning, Tracy.

I know how to pronounce your last name.

(laughter) Thanks. A quick question from me. Have you guys looked at doing any horizontal drilling on your shelf properties to increase the recovery of the oil and gas in place?

Yes. That's not an unusual function for offshore. Sometimes you don't necessarily call them horizontal wells, but that's primarily what we do in the Gulf, is drill directional wells. A lot of times you'll see them in shallower depths, particularly for shallower gas sands. But where you have areas that will warrant horizontal drilling and will justify the additional cost in that, it makes sense.

(Operator Instructions) At this time, I'm not showing any further questions. I would now like to turn it back to Mr. Krohn for any closing remarks. Please go ahead.

Thank you, operator. I think we're done. We'll talk to everyone next quarter, if not sooner. Thank you very much.

Thank you, ladies and gentlemen. That does conclude our conference call for today. If you would like to listen to the replay of today's call, you may do so by dialing 303-590-3030, using the access code 4549376. Thank you for your participation. You may now disconnect.