W&T Offshore Inc (WTI) 2013 Q1 法說會逐字稿

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

(Operator Instructions)

Today's conference is being recorded May 8, 2013. I would now like to turn the conference over to Mark Brewer, IR Manager. 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 first quarter of 2013. 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 section of the Company's website, at www.WToffshore.com, or via recorded replay until May 15, 2013. To use the replay feature, call 303-590-3030 and dial pass code 4615599-pound. Information recorded on this call speaks only as of today, May 8, 2013, 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 a disclosure on forward-looking statements. And now, I'd like to turn the call over to Mr. Tracy Krohn, WT's Chairman and CEO.

Thanks, Mark. Good morning, everyone. Thanks for joining us for our first quarter 2013 earnings conference call. This morning, there are several members of management with me, including Jamie Vazquez, our President, Danny Gibbons, our Chief Financial Officer, Tom Murphy, our Chief Operations Officer, and Steve Schroeder, our Chief Technical Officer.

So, continuing with our theme of organic growth with a focus on oil, we had another solid quarter that was largely driven by higher oil production and premium oil pricing. Cash from operations was up 33% in the first quarter compared to the first quarter of last year. This primarily reflects the success of the development projects we had underway in 2012. In particular, we saw growth in oil production from our Yellow Rose project in West Texas and from our Mahogany field offshore. We still have a lot going on in both projects and that should drive further oil reserves and production growth. Our oil production is up 20% year-over-year, as we sold 1.8 million barrels of oil in the first quarter. Our total production was 4.5 million barrels of oil equivalent; and production volumes were split 41% oil, 12% NGLs and 47% natural gas.

Our improved financial results also benefited from the premium pricing we received for our production. Our oil prices averaged $107.15 per barrel for the quarter. We also saw an improvement in our natural gas price realization, which was up 27% to $338.00 per MCF for the quarter. We're continuing to progress our growth initiatives, using a balanced approach. In the first quarter, we spent $136.6 million, of which 63% was dedicated to offshore activities and 37% to onshore activities, while approximately 54% of our first quarter capital went for development activities and 46% for our exploration activities. Our capital expenditures should become increasingly weighted toward exploration as the year progresses.

Okay. So the objective for taking a more balanced approach is to develop longer lived reserves and more predictable production growth, particularly, in our drilling and our development program in the Permian Basin of West Texas. This serves to counterbalance our high cash growth higher IRR, but relatively shorter reserve life offshore projects. We do have some high potential projects, like Big Bend in the deepwater and the Mahogany field on the shelf, that can add substantial future reserves to balance with projects that have steadier and predictable development characteristics, like our 40-acre spacing and horizontal Wolf Camp programs at Yellow Rose.

Near-term, we have an inventory of projects that could add substantial value this year and provide additional upside in 2014 and beyond. Several projects underway are expected to contribute additional production in the later part of 2013. Our second quarter guidance reflects the impact of various planned and unplanned events, including the timing of production of new wells, pipeline outages and platform downtime for maintenance, notably at our Wrigley Field.

Offshore, we are currently drilling the A-14, the subsalt exploratory well at our Ship Shoal 349 Mahogany field. As you know, we've had tremendous success in this field, bringing on line six wells since late 2011, which resulted in a production increase of roughly 600% during that 18-month period. The most recent well, the A-9, had initial production of 2,700 barrels of oil equivalent per day. The A-14 well rates -- or, well results, could prove our theory that the field is even more prolific than originally believed. This well will test the oil productivity of the T-Sand at about 18,000 feet measured depth. This is roughly 3,000 feet below the field’s pay zone, which is the P-Sand, both of which are below salt.

So far, the well has drilled through the P-sand, encountering approximately 123 feet of measured depth pay, which is thicker than we originally projected. The well also encountered over 100 feet of hydrocarbon interval in three additional sands above the P-sand. We expect to reach total depth in the exploratory target P-sand this quarter, and we will update you on those results when we can. Assuming a successful discovery could add as many as five additional P-sand targets in the field.

Following the completion of the A-14 well, we plan to form -- plan to do a recompletion on the A-4 well, and then proceed to the A-15 well. The A-15 is another subsalt exploratory well that could add meaningful reserves in 2013 and production in 2014. That well should spud sometime during the third quarter and is targeted to reach TD near the end of the year. Exploratory opportunity will target five separate pay sands, including the field pay P-sand. Again, a successful A-15 well could create additional development of new reservoirs in the Mahogany field.

These projects have considerable near-term and long-term impacts on the value of the Company. Our initial estimate of the unbooked net resource potential of the A-14 and A-15 exploration wells amounts to roughly 7 million barrels of oil equivalent. These numbers don't account for the additional interval in the hydrocarbon column identified above the P-sand or the value of the pud location P-sand which we've already encountered in the A-14. This is additional value. Once we know more about the productivity of the P-sand, we could again increase the field's total proved reserves. Also, let me remind you that Mahogany production is approximately 75% crude oil that earns premium pricing similar to our other Gulf Coast barrels.

At our Main Pass 108 field, we have two exploratory wells planned for 2013 that together have as much as 3.5 million barrels of oil equivalent of unbooked net resource potential. The Main Pass 108 B-1 well yesterday reached total depth, and we have drilled through approximately 130 feet of gross pay. And that's very encouraging. We expect to begin completion shortly and have the well on production about July. (inaudible) skid over to spud the Main Pass 108 well, which, assuming success, would be on first production by year-end. This natural gas production is expected to be very liquids-rich, thereby substantially boasting our returns.

Looking at development projects offshore -- additional development projects, I should say -- we expect to bring on more oil production from the Mississippi Canyon 243 Matterhorn field. We're currently completing that A-2 side track well. That's a target IP range of 500 to 1,000 barrels of oil equivalent per day. We should also see oil production reserve growth from Matterhorn, assuming success with the A-5 injection well, which is expected to spud immediately following the completion of the A-2 well. The A-5 well is a reservoir pressured maintenance project that is designed to extend the productive life of the field, as well as sweep oil to the A-2 well bore in the eastern portion of the field.

We believe that we've unbooked net resource potential of about 1.5 million barrels of oil equivalent for this project, and that there could be another 3.6 million barrels of oil equivalent of unbooked potential, assuming we conduct a similar pressure maintenance program in the western field area focusing on a slightly larger reserve target. That project will develop based on the results of the A-5, and probably occur in 2014 or early 2015. We are currently drilling the High Island 21 number 1 development well. We're targeting liquids-rich natural gas, and assuming success, this well should be on production sometime in the third quarter. Previous wells in this field have yielded cumulative production of over 50 Bcf equivalent.

Okay. So longer-term, we have other projects in our inventory that we believe add substantial value. Most notably is the Big Bend project, which as I said earlier is expected to be sanctioned this year, and is anticipated to generate first oil production in 2015. We estimate the unbooked net resource potential of this project to be somewhere between 5 million and 11 million barrels of oil equivalent net to our interest. We are in active discussions with other operators about WT's participating in other deepwater projects. This includes looking at opportunities on the deepwater acreage we've obtained from Newfield last year and recent additions from lease sales. In summary, our 2000 offshore drilling program provides huge value to W&T, with unbooked resource potential of 17 million to 23 million barrels of oil equivalent and net value between $425 million and $770 million.

So moving to the onshore, our focus has been on refining our drilling and completion process, gathering data, and performing the necessary field analysis to make sure we're optimizing our exploration and development efforts. At Yellow Rose, we're using 3-D seismic for well and lateral leg displacement -- or placement, rather -- and we have implemented new completion techniques that have generated meaningful results. We've seen a steady improvement in 30-day IP rates for our vertical wells, with our recent wells achieving rates that are nearly double the rates of our mid-2012 vertical wells. We've also seen an upward trend in the vertical EURs over the past few months, and are now projecting an average gross estimated recoverables of 130,000 barrels of oil equivalent for vertical wells. That's including oil and unprocessed gas. We've completed 11 wells in the first quarter, with 9 on 80-acre spacing and 2 on 40-acre spacing.

Our horizontal program is really just beginning and we continue to learn and gather data. To date, we've drilled six horizontal wells, and we're in the process of drilling a seventh. We've shared the results on our first two horizontals. We have two more wells on flow rack, and the last two are awaiting completion. We currently are operating a two-rig drilling program, and will evaluate results to determine the best mix of vertical and horizontal wells across the acreage to optimize our overall returns. We are taking a very systematic approach to both the vertical and horizontal programs, as we want to make the sure we properly filter that information that we gain in this early stage to our long-term operations.

We believe the field could have the potential to be developed down to 20-acre spacing on the vertical program, an idea that we will probably test later this year. We also believe we could ultimately have the potential to drill several hundred horizontal wells targeting the Wolf Camp and other horizontal benches. Our Yellow Rose project has significant upside resource potential, and W&T has identified an additional 120 million to 170 million barrels of oil equivalent, that being about 1,000 locations over and above the prudent and probable reserves booked to date on our acreage.

In regards to our proven undeveloped locations, we have plans to drill those wells within the next five years. We've not booked more locations, because we want to remain flexible with capital dollars in 2013 and in future years. We'll apply a balanced approach, limiting our offshore projects, yielding high rates of returns with high cash flows with our onshore projects, which have relatively predictable unbooked reserves for development future. With 85% of our acreage held by production of the Yellow Rose, we have that flexibility and plan to continue to commit capital to our drilling program. That will have the most impact on our production reserve goals for any given year.

We are planning to take a more measured approach to our East Texas Star project. We have a large acreage position in excess of 140,000 acres and no near-term risk of losing leases. Currently, our plans are to commence drilling again in the third quarter. That could be modified, based on what we learn and observe in the coming months.

On the acquisition front, we are seeing significant activity, both offshore and onshore, including some very attractive opportunities. We've also decided to put a package of our shelf properties on the market. It's a large package, and we think it makes sense to periodically accelerate the terms. Whether or not we sell any properties, we remain interested buyers of Gulf of Mexico properties and have excellent liquidity to complete a deal that fits our criteria. As we announced recently, the borrowing based under our revolving credit facility was increased to $800 million from $725 million.

Well, we have a pretty high level of activity and balanced mix of projects underway, which supports our near-term and long-term organic growth strategy. We're also continuing to return cash to our shareholders, and yesterday we announced that we've increased the quarterly dividend by 12.5%, to $0.09 per share per quarter. When we went public in 2006, we were paying a quarterly dividend of $0.02 per share. This is an overall increase of 350% since 2006 on our regular quarterly dividend. We've also paid special dividends five out of the last six years.

With that, operator, we'll open the phone lines for questions.

Thank you. Ladies and gentlemen, we'll now begin the question-and-answer session.

(Operator Instructions)

Noel Parks, Ladenburg Thalmann.

I wondered if you could talk a little bit more about what the nature of the improvement has been in the Yellow Rose verticals. You said that had been occurring over the last few months.

Yes, actually, the production has gone up nearly 100% on our vertical wells. It just has to do with different completion techniques that we've gotten better at. And also, we've pretty dramatically reduced the number of days it takes to drill those vertical wells.

Great. And when you talk about the techniques, is it more just a frac formula-type improvement?

Yes. It has more to do with the fracs than anything else, and just the method of implementation.

Okay. Great. And looking ahead, you talked about doing some 20-acre spacing. You've already started experimenting with those. If you got to more of a manufacturing mode out at Yellow Rose, do you have a sense of how much more you might be able to shave costs down?

Part of that equation, Noel, is that we're drilling some more horizontal wells out there. And we're trying to determine what is the most efficient method for drilling out there in that field. Do we get better ultimate economics out of the horizontal wells, where we can, or should we drill vertical wells? We are getting pretty efficient with the vertical wells, too. So it's just an economics consideration. And so, the short answer to your question is, yes, subject to better understanding of our horizontal economics.

Okay. That's it for me. I'll get back in the queue. Thanks.

(Operator Instructions)

Michael Glick, Johnson Rice.

Just a question on the shelf package. I was wondering if you could give a little bit more color on the thought process there, and what that means for you strategically, in terms of future direction, in terms of maybe focusing more on the deepwater?

Well, we have focused more on the deepwater in recent years. Occasionally, we sell properties in the Gulf of Mexico and on the shelf and other places. I just believe that right now is a good time to be selling properties. We're also in the buying mode, as well. So, I don't see it as really a different strategy from what we've used in the past. We really haven't sold anything of size in several years, now. And I think sometimes you look at the tree and you need to prune it, that's all.

Got it. Thank you.

Noel Parks, Ladenburg Thalmann.

Just a follow-up. Sorry if you commented on this and I missed it. It looks like the production mix was a little bit oilier than the guidance, adjusted for first quarter. Just wondering if -- what was behind that?

It was a very conscious intent. We had a goal of increasing the oil production in our mix, and so we very judiciously concentrated on developmental projects that yielded oil last year; and we are continuing to drill up prospects that yield oil this year, as well.

So, mostly the Permian then was the main contributor?

The Permian, and also Mahogany.

Okay.

Mahogany is about 75% oil, and those are pretty high rate wells. We've spent a lot of time and effort there to develop.

Okay. That's it for me. Thank you.

Dan McSpirit, BMO Capital Markets.

Good morning. Just want to go back to the shelf property divestiture, what's contemplated there. Any details that you could possibly relay on where, how much and timing?

Well, we've just sent the package out. And without giving too much detail, because it's not like we're sending it out to the entire world, here. But I will tell you that it's a pretty sizable package in the Gulf of Mexico. I don't want to commit myself to what it should be worth or what that production is. But expect it to come in as a pretty large number.

Okay. Great. Thank you. As a follow-up to that, then, regarding CapEx, you say it will be weighted towards exploration over the balance of the year, if I heard that correctly. Can you share with us, at all, how that may be weighted by quarter over the balance of the year, and whether or not there's any plan to sell down interests in any exploration projects slated for the back half of this year that could reduce that expenditure? I ask this in light of the $450 million CapEx budget for 2013.

If you look through it, and if you look in the earnings release, I think we detailed that pretty well, what we have coming up. I'm not sure if I can, right off the top of my head, give it to you by quarter. We're moving, after the B-1 well at Main Pass 108, which we just TD'ed and we expect to have online in July, we'll be drilling that well and expect to have that on by the end of the year. So you'll see that across the third and fourth quarters.

And then Main Pass 243 A-5, we'll be on that shortly. We're buttoning up one of our -- the A-2 well over there now. So you will see that, starting in the second and third quarters. And then the Ship Shoal 349 A-15, you will see as either an early third quarter, late second quarter, and on into the fourth quarter.

Got it.

I don't have any interest in selling down any of these wells.

Got you. Okay. Okay. I appreciate that. Thank you.

The rest of the CapEx will be out in West Texas.

Right. Right. Thank you.

(Operator Instructions)

Biju Perincheril, Jefferies.

A couple of questions. As a follow-up to that previous question, in the deepwater, on some of the Newfield properties, can you give us where you stand in terms of assessing some of those prospects, and when do you plan to test some of that?

I don't really have a whole lot I can share with you right now, other than that we are very active in gathering up seismic and data and working up prospects, in and amongst all that acreage. We've been approached by several other operators to participate in different areas, so we're evaluating that, as well. You build it and they will come, and that's kind of what's happening. So we're encouraged. We've since several things that we like. We've seen a few things that we didn't particularly care for. But mostly, it's been pretty positive.

So this is something we can look forward to, say, in 2014? As far as (multiple speakers).

I'd tell you 2014 and beyond.

Okay. And then in the Permian, the horizontal wells that you tested, I think they were all the A-zone, or the upper member. Can you talk about what your plans are for testing some of the other zones there? And I think the industry had probably more success to the South, in the more deeper zones. How is that different further up north, where you are?

Well, that's a fairly comprehensive question, but let me break it down. Yes, we do have the intent to test different benches. I always get a little bit confused by the nomenclature, because it varies across the basin with different operators. Some of them call it upper and lower Wolf Camp. Some of them call it A, B. Some call it A, B, C, D, E. And I never know what the correct nomenclature is. But clearly, we're having success in the Wolf Camp. I don't know which zone it is for all the other operators. We'll call it either the upper or lower. And yes, we will be testing additional benches, probably even up the whole, before the end of the year.

Okay. So that's included in the seven wells that you plan for this year? Or is that on top of that?

Perhaps even more than that, Biju.

Okay. Got it. Thank you.

Thank you, sir.

Thank you. And I'm showing no further questions in the queue at this time. I'd like to turn the call back to you, Mr. Krohn, for final remarks.

Okay. Well, that's all I have. Thank you very much for joining us this quarter and we'll talk to you again soon. Thanks so much.

Ladies and gentlemen, this concludes our conference for today. If you'd like to listen to a replay of today's call, please dial 303-590-3030 and enter the access code of 4615599, followed by the pound sign. Thank you for your participation. You may now disconnect.