W&T Offshore, Inc. (WTI) Q2 2014 Earnings Report, Transcript and Summary

Good morning, ladies and gentlemen. Thank you for standing by. Welcome to the W&T Offshore's Second Quarter Earnings Conference Call. [Operator Instructions] This conference is being recorded today, Thursday, August 7, 2014. I'd now like to turn the conference over to Ms. Lisa Elliott. Please go ahead, ma'am.

Thank you, operator, and good morning, everyone. We appreciate you joining us for W&T Offshore's conference call to review the results of the second quarter of 2014. And before I turn the call over to management, I have a few items I'd like to point out. If you wish to listen to a replay of today's call, it will be available in a few hours via webcast by going to the Investor Relations section of the company's website at www.wtoffshore.com, or via recorded replay until August 14. You can use the replay feature by calling (719) 457-0820, and dial the passcode 3356171. Information recorded on this call speaks only as of today, August 7, 2014, and therefore, time-sensitive information may no longer be accurate as of the date of any replay. Please refer to our second quarter 2014 earnings release for a disclosure on forward-looking statements. At this time, I'd like to turn the call over to Mr. Tracy Krohn, W&T's Chairman and CEO.

Thanks, Lisa. Good morning, all. Thanks for attending our second quarter 2014 earnings conference call. Joining me this morning are Jamie Vazquez, our President; Danny Gibbons, our Chief Financial Officer; Tom Murphy, our Chief Operations Officer; and Steve Schroeder, our Chief Technical Officer. Yesterday afternoon, we announced our second quarter results in a detailed news release, so this morning we'll focus on some of the key items in that announcement and take your questions. We had a strong quarter, and I'd like to point out a few highlights. Production was 48,300 barrels of oil equivalent per day, and 3% above our midpoint of guidance and 6.6% over the second quarter last year. Despite the deferred production that we encountered in the second quarter -- that's about 3.39 Bcf equivalent, or 564,000 barrels of oil equivalent, that we had in downtime, that we'll talk about later on. Revenues were $263 million, up $27.6 million over the second quarter of 2013. Operating expenses declined 9.5% compared to last year, and were 8.5% below the midpoint of our guidance. Earnings per share of $0.24 and adjusted EBITDA of $175.7 million were both well above second quarter 2013 results. So to that point, higher production and higher oil realized prices, coupled with lower operating expenses, led to our increase in adjusted EBITDA. EBITDA margins improved from 66% -- excuse me, from 60% to 67% in the second quarter of 2014, compared to the second quarter of 2013. So far, this year, adjusted EBITDA has increased to $343.7 million, which has allowed us to fund our capital program within cash flow. End of May, we announced that the U.S. Department of the Interior Bureau of Ocean Energy Management, or BOEM, informed us that W&T continues to qualify for a waiver of certain supplemental bonding requirements for potential offshore decommissioning liabilities, including plugging and abandonment. Also in May, our wholly-owned subsidiary, W&T Energy VI, completed the acquisition of the E&P properties in the deepwater from Woodside Energy USA for about $51 million. The more obvious value proposition of this acquisition to us was we obtained a 20% non-operated working interest in the oil-producing Neptune Field, which is a great addition to our growing portfolio of what we think are quality deepwater assets. Less obvious to some in this value equation is the upside associated with the acquisition. As part of the package, we also acquired 24 deepwater lease blocks on which we have several identified prospects, in addition to the currently planned projects. Neptune is a substantial field. It began producing in 2007. It's comprised of Atwater Valley blocks 574, 575 and 618. There are 6 subsea wells tied back to tension leg platform. This TLP, which we also have an ownership interest, is in 5,489 feet of water. Neptune Field has cumulatively produced over 30.6 million barrels of oil equivalent, of which 88% is oil. Total net proved reserves we acquired were 1.9 million barrels of oil equivalent, which are classified as 100% proved developed. PV-10 of those reserves is $53 million. We also acquired probable net reserves of 1.1 million barrels of oil equivalent. Average daily net production from the Neptune Field for the month of June averaged 1,700 Boe per day, net to our interest, of which 88% was oil. Our new term focus for Neptune is exploration. In addition to its considerable oil reserves and productions from multiple sands, it offers substantial exploration upside. Our expanded 2014 capital budget includes participation in a well to test the northern half of the field, which is never been tested due to a salt overhang. A rig is on location and currently drilling. Subsequently, in the quarter, we recently announced that the U.S. Environmental Protection Agency lifted the suspension and proposed debarment, and removed the statutory disqualification previously imposed on W&T. It's good to get this resolved. We take our responsibility to protect the environment to the safety of our employers -- excuse me, employees and contractors, very seriously. It's important to have dedication to compliance and prudent operations in the Gulf of Mexico recognized. We announced an increase of $185 million in our budgeted 2014 capital expenditure program, from $450 million to $635 million. That also includes acquisitions we have completed so far this year. In addition, the company was notified that we prevailed in the U.S. Court of Appeals with the Fifth Circuit ruling in our favor, as we sought insurance recovery for our removal of wreck costs associated with damage from Hurricane Ike. The underwriters subsequently requested rehearing on 3 different points and all were denied. The company spent approximately $46 million in connection with the removal of wreck claims from Hurricane Ike, and we ultimately expect to recover this, plus accrued interest, from this group of insurance underwriters. Again, we had a solid quarter, our strong cash flow and good prospectivity supports the increased budget, and the expansion of our exploration drilling program, which now includes additional wells in the Deepwater Gulf of Mexico and at our Yellow Rose field in the Permian Basin. Before turning it over to Jamie to review the increased budget and operational highlights, I'd like to provide you with an update on our West Texas Yellow Rose field. Onshore at Yellow Rose field, we currently are running 3 rigs in this field, with 2 dedicated to our vertical program and 1 to our horizontal program. Through the second quarter, we completed 11 vertical wells and 1 horizontal well. Of the 11 vertical wells completed during the quarter at Yellow Rose, 8 wells were drilled on 80-acre spacing and 3 wells on 40-acre spacing. Most of these are in early stages of flowback. We expect the drilling to complete approximately with the same number of vertical wells at Yellow Rose in the third quarter. Some of this is to hold acreage, not a whole lot it, but some of it is still -- we're still holding acreage. We've recently completed 2 horizontal Wolfcamp B wells in Martin County. The Chablis 10H was drilled to a total debt of 16,000 feet and a 6,025 foot lateral length. The Chablis 13H was drilled to a total depth of 15,830 feet and a 5,855 foot lateral length. Keep in mind that lateral lengths are somewhat determined by lease lines. Both wells recently began flowback and have already cut oil. We expect to equip them with artificial lift this month, and then we will see them build to their peak rates. Additionally, we just drilled a third horizontal bench, Lower Spraberry, in our Yellow Rose field to total depth. The well is currently being prepared for completion and frac operations in the Lower Spraberry horizon, and we anticipate results during the fourth quarter of 2014. We're excited about this new bench, and we continue to aggressively exploit and derisk our upside reserve potential in the field. We continue to see offset, and nearby operators in the Midland Basin announced substantial well results across these multiple stack targets. Our goal is to continue our exploration program, then complete the necessary analysis to determine an optimal development plan. For instance, we're currently drilling -- we're currently testing completion techniques with our second and third operated Wolfcamp B horizontal wells, the Chablis 13H and the Chablis 10H. They've both been drilled from the same pad, which provides cost savings and efficiency. Obviously, the pad drilling brings down the cost per well, and that's why you see so many operators choosing this option. You'll see more of that from us in the future. We continue to analyze our processes and make adjustments as we move toward our development phase. We believe we will have hundreds of drilling locations providing years of inventory, so it's important that we learn everything we can from every well. Second quarter production from the field averaged approximately 4,400 barrels of oil equivalent per day, gross. With that, I turn it over to Jamie to review the increased budget, operational highlights. Jamie?

Yes, thank you. As Tracy mentioned, the company has increased its 2014 capital budget to $635 million. The additional $185 million is dedicated to additional exploration wells, which accounts for about $127 million; and acquisitions that have been completed so far in 2014, estimated about $58 million. All the additional projects support our reserve and production growth, as we maintain our criteria, drilling within cash flow. These additional projects strengthen our production outlook for 2015, as they start to fill a production gap that was created from our successful deepwater exploration program. All of these exploration wells, assuming success, will commence production within relatively short periods of time, ranging from about 2 months from now up to about 18 months. The revised budget is allocated 66% to the offshore, 25% to the onshore and about 9% of that for acquisitions that were made so far this year. This budget does not include any additional acquisitions that the company may compete in the remainder of the year. Now we'd like to provide you with some of the details of these high-impact exploration projects. We've added about 3, maybe even 4, deepwater wells to the budget and 1 well on the shelf, being East Cam 321, A-2 side track. First, we're currently drilling the Neptune SB 03 well, which is targeting 2 main field pays at a target debt of approximately 18,200 feet of total vertical depth. Estimated total well costs to drill is about $160 million gross or $32 million net, to our 20% working interest. The operator, BHP, estimates the reserves associated with this well could range between 4.1 and 8.1 million barrels of oil equivalent gross. With success, we expect to see first production from this well later this year. Also, additional projects include a second well in our Dantzler prospect, being Mississippi Canyon 782. This well is designed to expand on our oil discovery at Dantzler No. 1 late last year, which was an excellent well that logged approximately 120 feet of net pay and 2 high-quality Miocene reservoirs. The Dantzler No. 2 exploration well is expected to prove up additional field reserves and give us more information about the field. We hold a 20% non-operating working interest in Dantzler. The estimated cost of the Dantzler No. 2 well is $87 million to drill and evaluate, and $94 million to compete, for a total of $181 million, $36.2 million associated with our interest. As you recall, the Dantzler project is in close proximity to our Big Bend development project. We are enthusiastic about the synergies that exists with the Big Bend and Dantzler projects, and expect to utilize some of the production infrastructure that we will install for Big Bend to produce Dantzler. All the necessary long lead items for Big Bend are now on order and contracts for subsea installations are being finalized. We set -- expect to see first oil production from Big Bend in late 2015, and first oil production from Dantzler as soon as early 2016. Next, we have included another additional well, or wells, to be drilled in our deepwater Medusa field in Mississippi Canyon 538 and 584, which was acquired in the fourth quarter of 2013. We have a 15% working interest in this field. Productions from the month of June averaged approximately 700 -- excuse me, 970 barrels of oil per day, net to our interest, which is 86% oil. In addition to this first well at Medusa, we now believe that we may have a second well to follow. That second well is likely to commence late 2014, maybe early 2015. Other wells are under evaluation. We expect the rig will mobilize the location late third quarter or early fourth quarter. Drilling and completion costs in the first well is estimated at $121.6 million gross per well and $18 million net to W&T. This exploration well is expected to move what we consider probable reserves into the proved reservoir reserves category in 2014. We expect the quick hookup with first oil production from this wells to be in April 2015. Located in approximately 560 feet of water, we expect to spud an exploration well from our Ewing Bank 910 platform in the fourth quarter. The details of this will be forthcoming, but it's important to note that since we are drilling from existing infrastructure, we expect immediate production in 2015 upon success. At the end of the quarter, we were drilling 2 offshore operated shelf wells, which were the A-16 and Ship Shoal 349, our Mahogany field, and the A-2 at East Cameron 321. In addition, to well count in 2014 is the East Cameron 321 A-2 side track. We have reached total depth in about 8,500 feet at our East Cameron -- at the location, and we have commenced completion operations. We logged over 140 feet of potential pay in 4 upper zones in this exploration well. We currently anticipate that the well will be brought online in the third quarter, with a target initial production rate of about 850 barrels of oil equivalent per day, and about 60% oil. At Ship Shoal 349 Mahogany, you may recall that our 2014 program includes 3 new wells. The A-15, 16 and 17, and 1 recompletion, which is the A6. In May, we commenced production of the A-15 exploration well, which achieved a peak production rate of approximately 1,075 barrels of oil equivalent per day, of which 83% was liquid. The well has logged over 65 feet of measured depth pay in the P sand. Also in May, the A-6 well was recompleted in the N sand at Mahogany and sanded up, so we are preparing for suite change to an upper sand. In early June, the A-16 development well commenced drilling. This well is designed to produce the M, the N and O sands that were logged in the A-14 well, which was completed last year, and a deeper, newly discovered T sand reservoir. We expect to have A-16 online in the fourth quarter, with the likely initial production rate of approximately 1,800 barrels of oil equivalent per day. The rig will then likely spud the A-17, an exploration well targeting the main field pay P sand, and likely the T sand as well. Production from the Mahogany field averaged 8,200 barrels per day,up from 6,988 barrels a day in the second quarter last year, and continues to be a significant contributor to the increasing revenues and production this year over last year. At Yellow Rose field in the Permian Basin in West Texas, we're increasing our 2014 horizontal drilling program with 3 additional wells, bringing the total number of horizontal wells planned for 2014 to 10. This will allow us to make efficient use of the horizontal rigs we have running in the field and move our exploration and development plan a bit further, as we approach 2015. Now I'd like to turn the call back over to Tracy.

Thanks, Jamie. We've just outlined numerous projects with substantial opportunity to add reserves and significant production volumes in the near term and in the future. Our deepwater program, in particular, continues to expand. We've just -- for several decades, most of our growth has come from acquiring quality-producing properties that offer upside potential, and then further exploring and developing them to realize that potential. This is not a new concept for us. We've been doing it this way for several decades. In our earlier days, this was primarily done on the shelf, but now we're doing that in a big way in the deepwater. We have a good reputation as an accomplished shelf player, but through acquisitions and the lease sales, we now have almost half of our lease acreage in the deepwater. We think that the strong economics of our successful deepwater program far outweigh large upfront costs, because we believe there are ultimately larger reserves. In summary, our successful exploration programs and acquisitions, both onshore and offshore, should provide the company with a solid growth pattern for years to come. And with that, operator, I'll take on questions.

[Operator Instructions] Our first question comes from Neal Dingmann with SunTrust.

Tracy, a question on -- it sounds like you're going to increase the program a little bit on the Permian. And just want to -- based on that, would that take any capital away from the offshore?

Not at this time, Neal. Right now we're still working on the premise that we've got a certain number of wells to drill horizontally there, before we advance into a full-fledged development program that would include pad drilling, line drive-type pad drilling. So, no, at this point in time, no change in budget percentages.

Okay. And then looking offshore, it seems like you've got a number of wells coming. How many -- Tracy, is it fair to say, how many additional deepwater projects are you adding late this year or beginning next year? It looked like quite a number to me.

Well, we've -- it looks like 4 total, so far.

Okay. And then remind me how many will be coming online? Are you starting to shift [ph] Big Bend or am I missing [indiscernible]? Is there another one coming online in the second half?

We're working on Big Bend and Dantzler. That timing may change just a little bit in our favor. We're not quite sure yet. We've spent some dollars on long lead items ahead of time even before sanctioning, we haven't sanctioned Dantzler at this time.

Okay. And then lastly given, obviously, a great capital that you have and your liquidity, are you looking for additional acquisitions like the Woodside at this time?

We're always looking for additional acquisitions, Neal. That's part and parcel of core activity for us.

We'll go next to Noel Parks with Ladenburgn Thalmann. Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division: Just a couple of things. At Neptune, it was mentioned that you had -- I think it was a 1.1 million barrels of probable. I was wondering are those reserved in the probable category just because of 5-year SEC rule of capital allocation? And also, is the well that's being drilled, was that considered something that comes from a pud inventory or a probable?

To answer your first question, yes, we think we've taken a fairly conservative approach on the classification of those reserves. Those are the reserves we're targeting at this point in time. Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division: Great. And the current drilling, an example of sort of project that you will be doing going forward under the operator?

Well, actually, the way we've looked at it, Gail [ph], is we think that in exploration, pure exploration plays, it behooves us not to take more than about 20%, we might go a little above or below that. But in general, around 20%. For instance, at Dantzler, we took 20% of Big Bend, we took 20% -- those were pure exploration plays. On anything that we do, of course, with regards to an acquisition, that would be a function of what our acquisition percentage is. It's already on production, so we're -- the normal process is we -- if we make an acquisition, we do it with an eye toward exploitation and exploration in the future. That's one of the things that motivates us, as opposed to just pure discounted cash flow. But I think that, in general, you'll see us on exploration plays at about 20%, plus or minus a little bit, and then on acquisitions, it will be a function of whatever we can acquire. Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division: Okay. And just thinking about the balance sheet, it sounds like several deepwater projects are getting teed up beginning of this year and next. And so plenty to do in the Permian. Thinking of your leverage potentially heading off a bit from here?

Yes, that's a possibility. I mean, the point is we don't lever up to do exploration. We will lever -- we're still going to drill within cash flow. We will lever up to do acquisitions and development. And we think that's a good reason to lever up.

[Operator Instructions] We'll go next to Gail Nicholson with KLR Group.

I was curious, looking at Mahogany, that feels as though it's a field that keeps on giving. What's the plan proposed to A-17 well?

We'll take a look at that once we drill the A-17 well. It seems, Gail, that -- and I'm sorry, I must have gotten the name wrong there, I guess that was Noel before. Sorry, Noel. Anyway, I think, Gail, what we will do is we'll take a look at it at that point in time and we'll decide where we're going to go after that. We've gotten new loss data coming, latter part of this year, early part of 2015. So we will have a chance to examine and review that as well. We have still not gotten to the bottom of the hydrocarbon column at Mahogany. So every time we get new data, we find new wells to drill, and it's been like that ever since we've owned it.

Great. And then on -- do you guys plan to draw any additional horizons outside of the -- you're doing the Lower Spraberry, but you're going to do a Wolfcamp B or can anything else? Or are you just thinking about one additional horizon in B?

The short answer to that would be, yes, we do. We're just going to see where we'd come with each different horizon and keep a close watch on our neighbors and what they're doing. I think we probably won't lead on that, we'll be more likely to follow because there's a lot of activity around this. No reason to spend extra money wildcatting on some of these different ventures, there's so many of them. It's probably better for us to sit back and wait and see what everybody else is doing before coming up with a more comprehensive plan. But in the interim, I mean, we are looking at better ways to complete what we already have, and we are getting better at it. But also, we mentioned that we are targeting the Spraberry, which several of our offset operators have done very successfully. So we have high hopes for that as well.

And also in the release, you mentioned that you're doing 2 different frac designs on the Chablis 13H and 10H. Could you expound upon what different designs you're testing on those 2 wells?

Sure. I could, but then I'd have to shoot you. No, I'm -- seriously I can't. I mean, that is fairly proprietary.

With no further questions in the queue, I'd like to turn the call back over to management.

All right, operator, I think we're done. We appreciate it. We'll talk to you next quarter, if not before.