W&T Offshore Inc (WTI) 2014 Q2 法說會逐字稿

Good morning, ladies and gentlemen. Thank you for standing by. Welcome to the W&T offshore second quarter earnings conference call.

(Operator Instructions)

This conference is being recorded today, Thursday August 7th, 2014.

I'd like to now turn the conference over to Ms. Lisa Elliot. 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.

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 their recorded replay until August 14th. You can use the replay feature by calling (719)457-0820 and dial the pass code 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. I'd like to point out a few highlights.

Production was 48,300 barrels 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 oils barrel equivalent that we had in down time that we'll talk about later on.

Revenues were $263 million, up $27.6 million over the second quarter 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.

To that point, higher production and higher all-in realized prices coupled with lower operating expenses led to our increase in adjusted EBITDA. EBITDA margins improved 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 with in-cash flow.

In May, we announced that the US Department of Interior Bureau of Ocean Energy Management, or the BOEM, informed us that W&T continues to qualify for a waiver of certain supplemental binding 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 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 that we obtained a 20% nonoperated 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, began producing in 2007. It's comprised of Atwater valley blocks 574, 575, and 618. There are six subsea wells tied back to a tension leg platform. This TLP, in which we also have an ownership interest, is in 5489 feet of water. Neptune field has cumulatively produced over 36 million barrels of oil equivalent, of which 88% is oil.

Total net reserves we acquired were 1.9 billion barrels of oil equivalent, which are classified as 100% proved developed. PV-10 of those reserves was $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 1700 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 production 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 has never been tested due to a salt overhang. A rig is on location and currently drilling.

Subsequent to the end of the quarter, we recently announced that the US 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 and the safety of our employers -- or 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 US Court of Appeals with the 5th 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 three different points and all were denied. The Company spent approximately $46 million in connection with 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 three rigs in this field, with two dedicated to our vertical program and one 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 three wells on 40-acre spacing. Most of these are early stages of flow back. We expect to drilling complete approximately the same number of vertical wells at Yellow Rose in the third quarter. Some of this is to hold acreage, not a whole lot of it, but some of it we're still holding acreage.

We've recently completed two horizontal Wolfcamp B wells in Martin County. The Chablis 10-H was drilled to a total depth of 16,000 feet and a 6025-foot lateral length. The Chablis 13-H was drilled to a total depth of 15,830 feet and a 5855-foot lateral length. Keep in mind that lateral lengths are somewhat determined by lease lines.

Both wells recently began flow back and they've 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 Sprayberry, in our Yellow Rose field to total depth. The well is currently being prepared for completion and frac operations in Lower Sprayberry Horizon, and we anticipate results during the fourth quarter of 2014. We're excited about this new venture. We continue to aggressively exploit and de-risk our upside reserve potential in the field.

We continue to see offset nearby operators in the Midland Basin announce 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 testing completion techniques with our second and third operated Wolfcamp B horizontal wells, the Chablis 13-H and Chablis 10-H. 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 4400 barrels of oil equivalent per day gross.

With that, I turn it over to Jamie to review the increased budget, operational highlights. Jamie?

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, estimate about $58 million. All of 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 serve to fill a production gap that was created from our successful deepwater exploration program. All these exploration wells, assuming success, will commence production within relatively short periods of time, ranging from about two 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 complete in the remainder of the year.

Now, we'd like to provide you some of the details of these high impact exploration projects. We have added about three, maybe even four, deepwater wells to the budget, and one well on the shelf being the East Cam 321 A-2 side track. First, we are currently drilling the Neptune SB03 well, which is targeting two main field pays at a target depth 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 reserve associated with this well could range between 4.1 million 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 number 1 late last year, which was an excellent well that logged approximately 120 feet of net pay in two high quality Miocene reservoirs.

The Dantzler number 2 exploration well is expected to prove up additional field reserves and give us more information about the field. We hold a 20% nonoperated working interest in Dantzler. The estimated cost of the Dantzler number 2 well is $87 million to drill and evaluate and $94 million to complete, 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 exist 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 the contracts for subsea installations are being finalized. We expect to see first oil production from Big Bend in late 2015, and first oil production from Dantzler soon as early as 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 first quarter of 2013. We have a 15% working interest in this field. Production from the month of June averaged approximately 970 barrels of oil per day net to our interest, which was 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 on 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 a quick hookup, with first oil production from these wells to be in April of 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 well will be forthcoming, but it is 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 two offshore operated shelf wells, which were the A-16 at Ship Shoal 349, our Mahogany field, and the A-2 at East Cameron 321. An addition to well count in 2014 is the East Cam 321 A-2 side track. We have reached total depth at about 8500 feet at our East Cam 321 location, and we have commenced completion operations.

We logged over 140 feet of potential pay in four 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 included three new wells: the A-15, -16, and -17, and one recompletion, which is the A-6. In May, we commenced production of the A-15 exploration well, which achieved a peak production rate of approximately 1075 barrels of oil equivalent per day, of which 83% was liquids. 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 a sleeve 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 in a deeper, newly discovered T-sand reservoir. We expect to have the A-16 online in the fourth quarter, with a likely initial production rate of approximately 1800 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 8220 barrels per day, up from 6988 barrels per day in the second quarter last year, and continues to be a significant contributor to the increase in revenues and production this year over last year.

At Yellow Rose field in the Permian Basin in West Texas, we are increasing our 2014 horizontal drilling program with three 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 rig 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. For several decades, most of our growth has come from acquiring quality producing properties that offer upside potential, and then further exploring or 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 acquisition and lease sales, we now have almost half our lease acreage in the deepwater. We think that the strong economics of our successful deepwater program for outweigh large up-front costs, because we believe there are ultimately larger reserves.

In summary, our successful programs and acquisitions, both on shore and offshore, should provide the company with a solid growth pattern for years to come.

And with that, operator, I'll take on questions.

Thank you.

(Operator Instructions)

Our first question comes from Neal Dingmann with SunTrust.

Good morning, gentlemen.

Good morning, Neal.

A question on, it sounds like you're going to increase the [focus] a little on the Permian? And just 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 -- 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, beginning next year? It looked like quite a number to me.

It looks like four total so far.

Okay. And then remind me, how many will be coming online? Is it just Big Bend or am I missing -- is there another one coming online, 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 the great capital that you have and your liquidity, are you looking for additional acquisitions like the Woodside?

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

All right. Thanks. Great quarter.

Thank you.

We'll go next to (technical difficulties) [Noel Parks, with Ladenburg Thalmann].

Good morning.

Good morning.

Just a couple of things. At Neptune, it was mentioned that you had -- I think it was 1.1 million [sales of probable]. I was wondering, are those in the probable category just because of five year SEC rule on capital allocation? And also, is the well that's being drilled, would that consider it something come from the [pud inventory] or 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.

Great. And the current drilling, an example of sort of project that you will be doing going forward under the operator?

Actually, the way that we've looked at it, Gail, 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%; at Big Bend, we took 20%. Those were pure exploration plays.

On anything we would do with regard to an acquisition, that will be a function of what our acquisition percentage is.

Okay.

It's already on production so, you know, 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 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.

Okay. And just thinking about the balance sheet, would these several deepwater projects getting teed up coming into this year and next, and still with plenty to do in the Permian, are you thinking of your leverage potentially heading up 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.

Right. That's it for me. Thanks.

Thank you, sir.

(Operator Instructions)

We'll go next to Gail Nicholson with KLR Group.

Good morning. I was curious, looking at Mahogany, that field that keeps on giving, what's the plan post the A-17 well?

We'll take a look at that once we drill the A-17 well. It seems, Gail, that -- I'm sorry. I must have gotten a name wrong earlier. I guess that was Noel before. Sorry, Noel. (laughter)

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 do you guys plan to drill any additional horizons outside of the -- doing the Lower Sprayberry, but are you going to do a Wolfcamp B or anything else, or are you just sticking with that one additional horizon in B?

The short answer to that would be yes, we do. We're just going to see where with we 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 us, 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, we are looking at better ways to complete what we already have, and we are getting better at it. But also, you know, we mentioned that we are targeting the Sprayberry, 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 two different frac designs on the Chablis 13-H and the 10-H. Could you expound upon what different designs you're testing on those two wells?

Sure, I could, but then I'd have to shoot you.

Okay. (laughter) Fair enough.

Being as serious as I can, that is fairly proprietary.

Okay. Great. Thank you.

Thank you.

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, and we'll talk to you next quarter if not before.

And ladies and gentlemen, this concludes the W&T Offshore second-quarter earnings call. If you'd like to listen to a replay of today's conference, please dial 719-457-0820 or 888-203-1112 and enter the pass code 3356171.

The conference center would like to thank you for your participation. You may now disconnect.