W&T Offshore Inc (WTI) 2014 Q3 法說會逐字稿

Greetings and welcome to the W&T Offshore third-quarter earnings conference call. At this time all participants are in a listen only mode. A brief question and answer session will follow the formal presentation.

(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, 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 November 13. To use the replay feature call 201-612-7415 and dial the pass code 13593502. Information recorded 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 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 our 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 from third quarter's 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 increasing 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 a substantial portion of those investments have already been made as reflected by the current DD&A rate.

So we do expect growth in 2015, 2016 while maintaining a more flexible capital plan with good liquidity. We're committed to 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 earlier successes such as Big Bend and Dantzler in 2015. Of course the prices remain lower -- trend lower, the capital plan for new drilling projects will be adjusted accordingly. Also the acquisition environment may become very attractive and we may well 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 and reserves in production.

We've had new discoveries in the third quarter both of which are currently being completed. We successfully drilled the Dantzler number 2 well at Mississippi Canyon block 782 and the SB-03 well at Atwater Valley 574 Neptune field. The Dantzler number 2 well found over 121 net feet of oil pay in target intervals. This well increased the operator's estimate of total gross resources in fields to between 65 million and 100 million barrels 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 four rigs working in the deepwater, including the one completed in advance of number 2 and one rig completing the Neptune SB-03 discoveries. Third rig is drilling a well at Medusa and we have a rig mobilizing to spud the Ewing Bank 910 A5 side track. After the Dantzler number 2 is completed, the rig will complete the Dantzler number1 with first production from those two discoveries 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 where two others. This year we've 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 2014, we commenced batch drilling operations of the ship SS number 6 and SS number 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 number 6 well, with the SS number 7 well to follow immediately thereafter. As we mentioned in the press release, the timing of first oil is a function of infrastructure installation to Medusa Spar, but likely the middle of 2015. We're discussing in the partnership other drilling opportunities at Medusa. These new wells in our Medusa field are another example of a project that can be put online very quickly.

We're currently mobilizing a rig to a platform at Ewing Bank 910 to spud the first well in what we refer to as our phase one redevelopment project. This is comprised of a two-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 analysis, we have identified several additional targets beyond our phase one 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 are 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 side track well is currently being completed and should be online before year-end.

We are continuing 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, that's about 2,000 barrels of oil per day and about 3 million cubic feet of gas per day, about 80% liquids. The A-17 well is planned as the next well at Mahogany. We will begin drilling that well soon as we complete other well field optimization work currently ongoing at Mahogany.

The A-17 well is targeting up at T-Sand location and we'll 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 of 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 and we continue to optimize our drilling and completion processes. Like other operators in the area we're having success with drilling longer intervals, fracing more stages, and using more profit per stage, which is yielding results similar to our nearby offset operators. We normalized for 7,500 foot lateral stacks and our last three wells achieved a pay rate of over 1,000 barrels per day. You can find more details on these wells on our investor presentation on our website.

Drilling and completing the last three horizontal wells, we've 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 profit per stage was increased significantly. These solid results reflect the kind of progress we've made at optimizing drilling and completion techniques to improve production and lower costs.

The Chablis 13H and the Chablis 10H were drilled from the same pad. That includes -- that provides costs savings and efficiency, and one well was completed with slick water hydraulic fracturing. While on the other, we used a hybrid fracture process, so part slick water and part gel. Global performance results in the Wolfcamp B formation were similar between the stimulation methods. We are now moving through specific frac formulations, i.e. slick water 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 of pay will be treated with hybrid fracs, while other formations will be treated with slick water 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, a pretty engineered approach.

During the third quarter, we completed two Wolfcamp B wells and one Lower Spraberry Shale horizontal well using more optimal completion techniques. We are 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 three 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 three out of a total of about seven identified horizontal target formations at this point. I think there may be more but we're honing in on about seven 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 de-risk 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.

Our acreage is about 85% held by production. So we can manage our capital program at the pace that makes the best sense. If oil remains -- if oil prices, rather, remain low, we've got a lot of flexibility, wait for the cost of goods and services to adjust, and incorporate this flexibility into our forward capital plans. So 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 on that 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 here.

So with that operator, we're going to take questions.

( Operator Instructions )

Neal Dingmann, SunTrust Robinson Humphrey.

Good morning, Tracy. Tracy, what do you think about with the capital allocation? Obviously to me, two things, one you certainly have a lot more coming online offshore as demonstrated in all the well results you walked through there, but then you also have the West Permian, 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, two questions around that, 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 net capital between offshore and onshore?

We are doing a lot of thought about that right now is, 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 are assessing all of our capital needs. A lot of the money that was spent for Deepwater has already been spent for further production and development at Dantzler and Big Bend. So that is encouraging.

We do have some more expense going forward in 2015 for both of those deals, but not as much as we had in 2014. So that is encouraging.

And it is 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 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. I don't really have a direct answer for your capital allocation yet, but we're working on it really hard.

Okay. And then just one more thought if I could, separately. It looks to me obviously on that Mahogany, as you mentioned the 816 well was certainly a good well that came on in October. But it also looks like you certainly have a lot of other pitch hands available there.

Two thoughts around that. 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 am going with that is after seeing what came on in October, does it make you more aggressively want to drill some of the other wells there?

The second question around that same play, is there any cost savings around there by -- you know, already had drilled obviously the 816 and obviously stand-on location, (inaudible) you're going after any other Sands or is it simply just growing in other well?

It's a fairly complex problem. It's a quality problem. If you recall, we had that rig on location initially for just a couple of wells and now we've been out there for over three years.

As we drill more wells and we get better data, we find more locations. We are waiting on our next iteration of live 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 come to the point where we needed to drill some development wells, some acceleration wells. So that's one of the things that we are considering for the budget next year as well.

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

You know, 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 shellshocked and they wait for the price to go up and it doesn't, or it doesn't go up as quickly as they think. They pause on pulling the trigger to sell properties.

I don't know really how to fully assess that. 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 -- 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 put most of our acquisition efforts, Neal. So hopefully that will continue.

That makes sense. Look forward to all the activity. Thank you, Tracy.

Thank you, sir.

( Operator Instructions )

Noel Parks, Ladenburg Thalmann.

Good morning.

Good morning, Noel.

I was wondering about the Permian, I've seen the nice result you've had recently. Have you been using the same service providers all along, back from your initial verticals drilling 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.

Right. You said that you have identified which formation you want to test next out there. And then you were talking about the range of options, you said development probably some sort of pad arrangement and drill a couple of formations and move a few hundred feet. Are you pretty much narrowing down an approach like that, or are there different permutations of cost or return considerations that might widen the set of options?

Right now, Noel, it looks like we are 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 of the wells we would 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 alter it as the need comes, but assume it's going to be stacked laterals with moving the rig a few hundred feet.

Right. With the completions you like then, would you be completing simultaneous laterals or (inaudible) staggering 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 the north-south arrangement. We could do it with zipper fracs.

We could do it with different types of (inaudible) and stuff like that. But right now we are still not quite to that point. But we are thinking along the lines of a little bit longer laterals, probably around 7,500 feet, depending upon what the geography is, stacked, moving in kind of a north-south direction, moving the rig in an east-west direction.

Here's the last one for me. What is the current status of takeaway at Yellow Rose right now, having so much activity in the area?

I will let Mr. Murphy answer that question because he is intimately familiar with it.

Actually, Noel, takeaway is good, in fact we have made some changes in this last year where we have actually worked very closely with the group and put a dedicated gas plan on our field because we weren't overly happy with some of the gas and the NGL takeaway and the interruptions associated with a lot of the aged infrastructure. We've actually just brought that online -- that gas plan online in the last 30 days or so. And so we're ramping up into that.

They're taking 100% of our gas now, zero flaring, so we preemptively looked ahead and saw the complications of others in the basin we're seeing from the aged gas plant. It's looking real good. Of course, oil takeaway is not really an issue. So we like where we are at with our new gas plant coming on and we're going to higher net back, higher NGL yields, better cuts, and even some compensate net backs on it, so it looks very good.

Great. Thanks. That's it for me.

( Operator Instructions )

Gail Nicholson, KLR Group.

I am just looking at the 618 SB-03 well over at Neptune, you kind of defined a good amount of net pay, in excess of about 300 feet, is that initial rate target of 5,400 (inaudible) per day growth still a good expectation, based upon the 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.

Okay great. Thank you.

Thank you.

Joe [Mayers], CJ Securities.

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

When we get to the point where we're ready to discuss that with our Board we will do it, we're not quite to that point yet so it will be a little bit later on before we make any decision.

Thank you.

Thank you.

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

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

John Sullivan, Capital Securities.

Good morning gentlemen. There's been a lot of scary talk in the news as far as the (inaudible) prices of oil and Saudi Arabia cutting prices and potentially putting pressure on US producers. And if you believe Goldman Sachs, we're in a $75 price market. I am 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 low 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 right-size 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? It's kind of hard to speculate on that. Clearly when the cost of goods and services is affected by oil prices, 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 six to nine months because rigs come off contract and rigs are the highest-priced portion of the drilling operation.

As a follow-up to that I know you played a derivatives market to hedge against future changes, how far out to do you generally hedge, are you hedging out 90 days or longer? I see the price dropping $20 a barrel, how fast does it take to actually impact your Company revenues? I would assume you have 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 -- quote unquote 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. You can find that information there. Right now, I think we're in pretty good shape.

Okay. Great. Thank you very much, gentlemen.

Thank you, sir.

Richard [Dearly], [Longport Loggers].

Good morning. 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 2015?

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 refer to that, they could 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. That's the current thought it. We detailed what wells we'll be drilling for 2015. In fact, we are mobilizing Ewing 910 now.

We are completing a well at Neptune, and 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. We have to take that into account. It's kind of a quality problem, which I hope we have the problem of having to increase the budget because we are having such success.

And then could -- in terms of gross investment in the Permian, from 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're spending, I think, $160 million this year, $73 million last year. I can't figure out the CapEx for 2011 and 2012 from the releases. So it looks like, at a guess, it's around $600 million. Would that be in the ballpark?

You've got the numbers there. You can figure it out ( multiple speakers ) --

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

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

What was the production this quarter from the Permian?

I don't know the exact production from the quarter. The production currently is around 5,000 barrels per day, gross.

Okay. Thank you very much.

Thank you, sir.

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 got, operator. We appreciate it. We'll 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.