W&T Offshore, Inc. (WTI) Q3 2014 Earnings Report, Transcript and Summary

Greetings, and welcome to the W&T Offshore Third Quarter 2014 Earnings Conference Call. [Operator Instructions] As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Lisa Elliott. Thank you. You may begin.

Thank you, Christine, and good morning, everyone. We appreciate you joining us for W&T Offshore's conference call to review the results for the third quarter of 2014. Before I turn the call over to the company, I have a few items to point out. If you wish to listen to a replay of today's call, it will be available in a few hours via webcast by going to the Investor Relations section of the company's website at www.wtoffshore.com or via recorded replay until October 13. To use -- excuse me, that's not the right date, I apologize, November 13. To use the replay feature, call (201) 612-7415 and dial the passcode 13593502. Information reported on this call speaks only as of today, November 6, 2014, and therefore, time-sensitive information may no longer be accurate as of the date of any replay. Please refer to our third quarter 2014 earnings release for a disclosure on forward-looking statements. At this time, I'd like to turn the call over to Tracy Krohn, W&T Offshore's Chairman and CEO.

Thanks, Lisa, and good morning, everyone. Thanks for attending our third quarter 2014 earnings conference call. Joining me this morning is Danny Gibbons, our Chief Financial Officer; Tom Murphy, our Chief Operations Officer; and Steve Schroeder, our Chief Technical Officer. Yesterday afternoon, we announced the third quarter results in a pretty detailed news release, so we'll let you refer to that for the numbers, and we'll primarily focus on some of the key operations and then take your questions. We had good operating results in the third quarter as production of oil, natural gas liquids and natural gas all came in above our expectations, and operating expenses came in substantially below expectations. We produced an average of 46,700 barrels of oil equivalent per day, of which 53% was oil and liquids. As anticipated, our financial results were impacted by a decline in product pricing and an increase in our DD&A rate. That DD&A rate reflects our investment in high-impact, longer-term deepwater projects, which we expect will add significant reserves and production going forward in 2015 and 2016. These deepwater projects will require less incremental capital contributions in the future because the substantial portion of those investments have already been made, as reflected by the current DD&A rate. So we do expect growth in 2015 and 2016 while maintaining a more flexible capital plan with this liquidity. We committed the projects we have underway. Our capital plan for 2014 includes some projects that will require additional capital in 2015 in addition to commitments made to develop early successes such as Big Bend and Dantzler in 2015. Of course, if prices remain lower or trend lower, the capital plan for new drilling projects will be adjusted accordingly. Also, the acquisition environment may become very attractive and we may want to use our capital for those opportunities. We're well positioned to manage our growth next year. Our borrowing base under our revolving credit facility was reaffirmed at $750 million effective October 22, 2014. We have strong cash flow, with adjusted EBITDA for the trailing 12 months of about $612 million. We continue to have excellent drilling results with a 100% success rate so far this year, and that includes the drilling program weighted toward deepwater exploration. This program is driving substantial growth in reserves and production. We've had 2 discoveries in the third quarter, both of which are currently being completed. We successfully drilled the Dantzler No. 2 well at Mississippi Canyon Block 782 and the SB-03 well at Atwater Valley 574 Neptune Field. The Dantzler No. 2 well found over 121 net feet of oil pay in the target intervals. This well increased the operator's estimate of total gross resources in the field to between 65 million and 100 million barrels of oil equivalent. Recall that we own 20%. The Neptune SB-03 well logged over 300 feet of net pay and is in the final stages of completion and should be on production before year-end. We currently have 4 rigs working in the deepwater, including the one completing the Dantzler No. 2 and one rig completing the Neptune SB-03 discoveries. The third rig is drilling well at Medusa, and we have a rig mobilizing to spud the Ewing Bank 910 A-5 sidetrack. After the Dantzler No. 2 is completed, the rig will complete the Dantzler No. 1, and the first production from those 2 discoveries are planned for the first quarter of 2016. So during the middle of the year, we expanded our budget to add several high-quality projects. Neptune was one of those projects. Medusa and Ewing Bank 910 are 2 others. This year we acquired an interest in both Medusa and Neptune and increased our working interest in the Ewing Bank 910 field. We anticipate that these wells and fields will have a meaningful impact on our production volumes throughout 2015 and beyond. During September of 2014, we commenced batch drilling operations of the Ship -- SS No. 6 and SS No. 7 wells at the Mississippi Canyon 538 Medusa field. Both wells are targeting stacked oil sands down to 12,500 feet. We're currently drilling the SS No. 6 well, with the SS No. 7 well to follow immediately thereafter. As we mentioned in the press release, the timing of first oil is a function of the infrastructure installation to the Medusa Spar but likely the middle of 2015. We're discussing with the partnership other drilling opportunities at Medusa. This new wells at our Medusa field are another example of the project that will be put online fairly quickly. We're currently mobilizing the rig to the platform at Ewing Bank 910 to spud the first well, what we refer to as our Phase 1 redevelopment project. This is comprised of a 2-well drilling program with the possibility of a third well. If successful, this project -- well, assuming success, this project could contribute production in the second quarter of 2015 with the first well. Using improved seismic data and analysis, we have identified several additional targets beyond our Phase 1 redevelopment project. Resource potential at Ewing Bank 910 is pretty significant. This exploration project is characteristic of a well strategy, having recently acquired more interest in this Ewing Bank 910 field. Our Medusa and Neptune projects were also based on the same acquisition and exploitation concept. Immediate production contributions are coming from recent successful wells in our Gulf of Mexico shelf program. Successful exploration discovery at the East Cameron 321 A-2 sidetrack well is currently being completed and should be online before year-end. We continue to have tremendous success at our Ship Shoal 349 Mahogany field. The A-16 development well was brought online in October 2014 and is currently producing over 2,500 barrels of oil equivalent per day gross, so about 2,000 barrels of oil per day and about 3 million cubic feet of gas per day and about 80% liquids. The A-17 well, as planned, is the next well at Mahogany. We will begin drilling that well as soon as we complete other well and field optimization work currently ongoing at Mahogany. The A-17 well is targeting an up dip P sand location and will spud in the coming weeks. In fact, we're trying to get over the wellhead as we speak. The A-14 well was our first well in the T sand and continues to perform at a very strong rate. If you remember, the T sand is 3,000 feet deeper than the main field pay, which is the P sand. The well has cumulatively produced over 1.47 million barrels of oil equivalent gross or 1.23 million barrels net since it was placed on production in July of 2013. So let's talk about the Permian Basin a little bit. In the Permian Basin, our horizontal drilling program is progressing well as we continue to optimize our drilling and completion processes. Like other operators in the area, we are having success with drilling longer intervals, fracking more stages and using more proppant per stage, which is yielding results similar to our nearby offset operators. We normalized for 7,500-foot lateral section our last 3 wells achieved a peak rate of over 1,000 barrels per day. You can find more details on these wells in our investor presentation on our website. Drilling and completing the last 3 horizontal wells, we substantially changed the completion techniques from our earlier Wolfcamp A well completions. The spacing between frac stages was reduced, the target stages were increased -- the target volume per stage increased and the amount of proppant per stage was increased significantly. These solid results reflect the kind of progress we've made in optimizing drilling and completion techniques to improve production and lower cost. The Chablis 13H and the Chablis 10H were drilled from the same pad. That includes -- that provides cost savings and efficiency. One well was completed with slickwater hydraulic fracturing, while on the other we used a hybrid fracturing process, so part slick and -- part slickwater and part gel. Well performance results in the Wolfcamp B formation were similar between the stimulation methods. We're now moving to specific frac formulations, i.e. slickwater versus hybrid, by zone, which is driven by formation characteristics in order to optimize that production performance. We expect that certain formations within our vertical column in the pay will be treated with hybrid fracs, while other formations will be treated with slickwater fracs. We will continue to analyze field results, and we'll continue our frac optimization both in terms of formation response and cost optimization to further reduce cost, in other words, pretty engineered approach. So during the third quarter, we completed 2 Wolfcamp B wells and 1 Lower Spraberry Shale horizontal well using more optimal completion techniques. We're very encouraged by the results, including the early results of our Lower Spraberry Shale test, the Pinot 65 15H, which is in the southeastern part of the field. We wanted to continue this bench across the field area. We are currently completing another Wolfcamp B well. The next 3 wells will target the Lower Spraberry Shale. Thus far, we've demonstrated commercial production rates in the Wolfcamp A and B and Lower Spraberry Shale, which represents 3 out of a total of about 7 identified horizontal target formations at this point. I think there may be more, but we're honing in on about 7 right now. As part of our longer-term onshore strategy, we anticipate investing in some or all of these yet untested horizontal target formations. So the decision as to which one to test next hasn't been made as we monitor both our internal well results and well results from other operators. We're working to derisk as many formations or horizons as we can to determine a more ideal development plan. Once we go into development mode, the idea would be to drill into each of these formations from the pad, move over a few hundred feet and repeat the process. So our acreage is about 85% held by production. So we can manage our capital program with the pace that makes the best sense. If oil remain -- if oil prices, rather, remain low, we've got a lot of flexibility to wait for the cost of goods and services to adjust and incorporate this flexibility into our forward capital plans. So our recent horizontal drilling results at Yellow Rose have been very good, and we're seeing the benefit of our disciplined and thoughtful approach to not letting our drilling program get ahead of the industry learning curve and our well results and analysis. We have hundreds of drilling locations, so we have a lot of running room. Our horizontal wells are now contributing about 24% of the production output of the Yellow Rose field. A little bit about acquisitions. Acquisitions, like they always have, continue to make contributions to reserve and production growth year in and year out, and the Neptune and Fairway acquisitions completed so far this year are no exception. We remain active in the acquisition market, and we believe that the lower price environment will lend itself to more opportunities. For over 30 years, we've built this company on an acquire right and intelligently exploit attitude in all types of pricing environments. And right now, we see a lot of opportunity ahead. So with that, operator, we're going to take questions.

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

Tracy, how do you think about the capital allocation? Obviously, to me, 2 things. One, you certainly have a lot more coming online offshore, as demonstrated by all the well results you walked through there. But then you also have, obviously, in the West Perm there, West Texas area, it looks like these wells now in the horizontal program are certainly starting to improve. So I guess as you go into 2015, sort of 2 questions around that. I mean, just number one, macro. How do you think about spending overall into next year versus your cash flow? And then secondly, how do you think about allocating that capital between offshore and onshore?

Yes, we're doing a lot of thought about that right now. Certainly the prices falling affects the way we think about it. We haven't come up with budget proposals for our board yet. We are working on that as we speak. We're assessing all of our capital needs. A lot of the money that we spent for deepwater has already been spent for further production and development at Dantzler and Big Bend, so that's encouraging. We do have some more expense going forward into '15 for both of those fields, but not as much as we had in '14. So that's encouraging. And it's encouraging to see the kind of results we're having out at Yellow Rose. We're not quite ready to pull the trigger on what I would call a full-scale development, but we're getting there. Our offset operators are helping us -- helping to guide us that way as well with their results and our own results. So we'll have a clearer picture here in the next few months. So I don't really have a direct answer for your capital allocation yet, Neal, but we're working on it really hard.

Okay. And then just one more follow-up, if I could, separately. It looks to me, obviously, on that Mahogany, as you mentioned, the A-16 well was certainly a good well. It came on in October. But it also looks like you certainly have a lot of other pay sands available there. I guess sort of 2 thoughts around that. I mean, one, how do you think -- seeing how that one came on in October, how do you compare that versus some of your other prospects? I guess where I'm going with that is does that -- after seeing what came on in October, does it make you more aggressively want to drill some of the other wells there? And then the second question around that same play. Is there any cost savings around there by -- you already have drilled, obviously, the A-16 and just obviously, staying on location, although you're going after any other sands. Or is it just -- simply is just drilling another well?

Yes. Well, it's a fairly complex problem. It's a quality problem. If you'll recall, we had that rig on location initially for just a couple of wells, and now we've been out there for over 3 years. So as we drill more wells and we get better data, we find more locations. We are waiting on next iteration of WOS data out in the field, so we will have that early part of next year, and then we'll start assessing what we want to do. But we've got plenty to do to keep us busy out there. One of the things that's been really good is that, as we've continued to develop the field, we've kind of come to the point where we needed to drill some development wells, some acceleration wells. So that's kind of one of the things that we're considering for the budget next year as well.

Okay. And last question if I could. Just real quickly, how do you think about overall acquisitions here in this kind of macro environment? I mean, are things getting still cheap enough that it does make sense to still add some leases in different blocks offshore? Or in this kind of environment, you've obviously looked through this several times before. Does it pay to sit back and wait a bit?

It's an odd type of scenario. We've been able to buy properties in high-price and low-price environments. So it's a normal part of our business. I mean, obviously if prices are higher, the fields are worth more. If they're lower, they're worth less. A lot of it comes in as a psychology experiment. Sometimes when prices drop precipitously, people get shell-shocked and are waiting for the price to go up, and it doesn't. Or it doesn't go up as quickly as they think, and they kind of pause on pulling the trigger to sell properties. I don't know, really, how to fully assess that, and we will as we go through the year here. But there's plenty of properties available for sale onshore and offshore, and we expect to see that in the future. We're kind of -- we don't really care whether it's onshore or offshore. But certainly some of the things offshore have been very attractive lately, and that's where we've put most of our acquisition efforts, Neal, so hopefully, that will continue.

[Operator Instructions] Our next question comes from the line of Noel Parks with Ladenburg Thalmann. Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division: I was wondering about the Permian. Good to see the nice results you had there recently. Have you been using the same service providers all along back from your initial verticals, drilling up to the present? Or have you changed up or experimented with different guys?

No, we've mixed it up a bit. And of course, that's a really good question because as we get further into a wider-scale development program, that will become a key factor for us. Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division: Right, right. And you said that you have identified which formation you want to test next out there. And then you're talking about the range of options. You said development, probably some sort of pad arrangement and drill -- I guess drill a couple of the formations then move a few hundred feet. So are you pretty much narrowing down an approach like that? Or are there different permutations of sort of cost and return consideration that might widen the set of options?

Right now, Noel, it looks like we're going to be doing stacked laterals from a pad and then be able to move the rig a few hundred feet. Obviously, we haven't identified all the wells that we'd want to drill from a single pad, but I would anticipate it would be a fairly standardized process. Of course, as we get more information, we'll offer it as the need comes. But assume that it's going to be stacked laterals with moving the rig a few hundred feet. Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division: Right. And then what would the completions be like then? Would you be completing simultaneous laterals or do you have to sort of stagger them?

We haven't quite come up with that full plan yet. I could spout off a number of different possibilities. We could do it in a north-south arrangement. We could do it with zipper fracs. We could do it with different types of proppants and stuff like that. But right now, we're still not quite to that point, but we are thinking along the path -- along the lines of a little bit longer laterals, probably around 7,500 feet, depending upon what the geography is, stacked, moving in a kind of a north-south direction, moving the rig in an east-west direction. Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division: Just the last one for me. What's the current status of takeaway at Yellow Rose right now, having so much activity in the area?

I'll let Mr. Murphy answer that question because he's intimately familiar with it.

Actually, Noel, the takeaway is good. In fact, we've made some changes in this last year where we've actually worked very closely with a group and put a dedicated gas plant on our field because we weren't overly happy with some of the gas and NGL takeaway and the interruptions associated with a lot of the aged infrastructure. And we've actually just brought that online, that gas plant online in the last 30 days or so, and so we're ramping up into that. They're taking 100% of our gas now, 0 flaring, so we're -- we kind of preemptively looked ahead and solved the complications that others in the basin were seeing from the aged gas plant. So it's looking real good. Of course, oil takeaway is not really an issue. So we like where we're at with our new gas plant coming on, and we're going to get higher netbacks, higher NGL yields, better cuts and even some condensate netbacks on, so it looks very good.

[Operator Instructions] Our next question comes from the line of Gail Nicholson with KLR Group.

I'm just looking at the 618 SB-03 well right at Neptune, you kind of defined a good amount of net pay, an excellent 300 feet. Is that initial rate target of 5,400 barrels per day gross still a good expectation based upon the net feet -- net pay you guys encountered?

I don't really have that information right in front of me, Gail, but it is a lot of pay. It will certainly be a function of what the reservoir characteristics are when we complete it and also the reservoir pressure.

Our next question comes from the line of Joe Myers [ph] with CJ Securities.

I just had a question in terms of your dividend. You've obviously been -- paid dividends pretty consistently and increased those in December last few years. And I'm wondering how you think about that in context of both the oil price, the data and also the kind of opportunities that you're looking at on the CapEx side?

Yes, sure. When we get to the point where we're ready to discuss that with our board, we'll do it. We're not quite to that point yet, so it'd be a little bit later on before we make any decisions.

Ladies and gentlemen, we have reached the end of the question-and-answer session. I would now like to turn it back to Mr. Krohn for closing remarks.

Just a moment, operator. I think we have another question here showed up.

Our next question comes from the line of John Sullivan [ph] with Capital Securities [ph].

There's been a lot of scary talk in the news as far as the low prices of oil and Saudi Arabia cutting prices and potentially putting pressure on U.S. producers. And if you believe Goldman Sachs, we're in a $75 price market. I'm curious if you believe that. And just being devil's advocate, if that was true in your crystal ball and you knew that we would be in a situation of continued lower oil prices for the foreseeable future, do you think there could be a profitable scenario for a full year of depressed oil prices? Or would you have to take radical steps in terms of production to rightsize production with that type of reality, which a lot of people who watch the market and pundits and experts are saying could happen?

John, that's a pretty detailed question. Let me give you an analogy. If a pig had wings, would it be an eagle or would it just be a pig with wings? I mean, it's kind of hard to speculate on that. Clearly, when the cost of goods and services is affected by oil price, it generally lags those prices. So it's really a function of how fast the cost of goods and services drop as a function of how fast the price of oil drops. That really is one of the controlling factors to it, so I don't know how to speculate on that. Generally out in the Gulf of Mexico it's about 6 to 9 months because rigs come off contract, and rigs are the highest price portion of the drilling operation.

Okay. I guess as a follow-up to that, I know you played the derivatives market to kind of hedge against future changes. How far out do you generally hedge? I mean, are you hedging out 90 days or longer? When I see price dropping $20 a barrel, how fast does it take to actually impact the company revenues? So I assume you've got some protection for some period of time.

John, we use hedging as a tool, so it's not a speculative instrument. So by that definition, we don't "play" the derivatives market. It's not a speculative tool for us. It's simply a tool that we use to manage financials of the company. I would tell you that right now, we detail our current hedges in our presentations and also our quarterly reports to the market, 10-Qs and 10-Ks and whatnot. So you can find that information there. Right now, I think we're in pretty good shape.

Our next question comes from the line of Richard Dearnley [ph] with Longport Partners.

Could you put some numbers to the amount of outspend or forward spend in the deepwater that you're doing this year that won't recur in '15?

We're -- no, I can't do it right off the top of my head. I think we give pretty good detailed information in our investor presentation that we've got up on the website as regards our capital budget and how it changed over the years. So if you'll refer to that, they can give you those numbers fairly quickly. As far as 2015 is concerned, we haven't finished our budgeting process for 2015. Again, that will be a function of our success in drilling wells going into 2015, although we do expect that when we have success, that we'll have a higher spend. So we have to leave a little bit of flexibility in our budget for that. So that's the current thought on -- we've kind of detailed what wells we'll be drilling for 2015. In fact, we're mobilizing Ewing 910 now. We're completing the well at Neptune. Obviously, there's some hookup charges that will go along with that, that may be billed in 2015, even though the prices occurred in 2014. So we have to take that into account. It's kind of a quality problem, Richard. I hope we have the problem of having to increase the budget because we're having success.

All right. And then could -- in terms of gross investments in the Permian, some acquisition plus the CapEx to date, do you have a round number for what that is?

No.

It appears to me that it would be something like you paid -- I think it was $390 million you spent. You're spending, I think, $160 million this year, $73 million last year. I don't -- I can't figure out the CapEx for '11 and '12 from the releases. So it looks like, at a guess, it's around $600 million. Would that be in the ballpark?

Well, you got the numbers there. You can figure it out.

No, I don't have the numbers. That's why I m asking.

I can't tell you off the top of my head, Richard, what the all-in CapEx is out there. What I'm focused on is not only that, but also what is the recovery that we can receive out of the over 9.4 billion barrels of oil in place. That's the ultimate goal and promise of West Texas.

Right. And what was the production this quarter from the Permian?

I don't know the exact production in the quarter, but production currently is around 5,000 barrels a day gross.

Mr. Krohn, we have no further questions at this time. I would now like to turn the floor back over to you for closing comments.

That's all I've got, operator. We appreciate and we look forward to talking to our investors in the future.

Ladies and gentlemen, this does conclude today's teleconference. You may disconnect your lines at this time. Thank you for your participation, and have a wonderful day.