W&T Offshore, Inc. (WTI) Q3 2013 Earnings Report, Transcript and Summary

Good morning, ladies and gentlemen. Thank you for standing by. Welcome to the W&T Offshore's Third Quarter Earnings Conference Call. [Operator Instructions] This conference is being recorded today, November 7, 2013. I would now like to turn the conference over to Mr. Mark Brewer, Manager of Investor Relations. Please go ahead, sir.

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 third quarter of 2013. 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 November 14. To use the replay feature, call area code (303) 590-3030 and dial the passcode 4645500#. Information recorded on this call speaks only as of today, November 7, 2013, and therefore, time-sensitive information may no longer be accurate as of the date of any replay. Please refer to our third quarter 2013 earnings release for a disclosure on forward-looking statements. At this time, I'd like to turn the call over to Jamie Vazquez, W&T's President.

Thank you, Mark, and good morning, everyone, and thank you for joining us. I'm pleased to provide a review of our results for third quarter of 2013 and an update on some of our operating activities and future plans. Our Chairman and CEO, Tracy Krohn, is currently traveling in Asia. He is unable to join us this morning, but with me today in our Houston office is Danny Gibbons, our Chief Financial Officer; Tom Murphy, our Chief Operations Officer; and Steve Schroeder, our Chief Technical Officer. We had a solid quarter, outperforming our guidance on production and expenses. Our third quarter production volumes increased 13% over third quarter volumes last year to 45,700 barrels of oil equivalent per day. While revenue grew 32% over the same period due to our growth in higher volume liquids. Through our strategic efforts, we have increased our oil production by 25% and our NGL production by 10% since the third quarter of last year. As a result, 82% of our third quarter revenue were derived from our liquid production. Revenues grew to $244.6 million, and 2/3 of that growth was derived from increased production. Our cash generation was also strong, with adjusted EBITDA of $37.5 million from the prior year period to $147.2 million. That's a 34% increase, and it's positioned us to be able to reward our shareholders and raise the quarterly dividend from $0.09 per share to $0.10 per share. Keep in mind that our revenues and EBITDA would have been higher if we didn't continue to have substantial production volume deferred due to third-party pipeline outages, platform and facility maintenance and various operational issues. We estimate that about 4.7 billion cubic feet equivalent was deferred in the third quarter. Current production rates are approximately 310 million cubic feet equivalent per day and roughly 51,600 barrels of oil equivalent per day. Current production capacity including that, which is currently offline and deferred, is estimated at 330 million cubic feet equivalent per day or around 55,000 barrels of oil equivalent per day net to W&T. Our earnings release provides detailed guidance for the fourth quarter and revised guidance for the full year that reflects a more narrow range and an increase in the midpoint of production volume estimates. To drive our success, we continue to use a strategic portfolio approach that balances our growth opportunities. In the third quarter, the year-over-year increase in production growth came from both offshore and onshore wells, development and exploration projects and from producing properties we acquired late last year from Newfield Exploration. Our achievements in Mahogany field have played a major role in our growth. Net production from the field increased to average over 7,500 barrels of oil equivalent per day net during the third quarter. This is up 97% from last year's third quarter. Onshore, the primary growth contributor is our Yellow Rose field in the Permian Basin, where production has grown over 60% from last year's third quarter and average 3,944 barrels of oil equivalent per day. In the fourth quarter, it will be a very similar story. We are very active with the drill bit onshore and offshore, and we are adding production reserves through accretive acquisitions. On November 5, we closed on a majority of the properties associated with the acquisition of Callon Petroleum's Gulf of Mexico assets. The transaction includes a 15% working interest in the Medusa field, located in the deepwater, Mississippi Canyon blocks 538 and 582. We also acquired a 10% membership interest in Medusa Spar, which owns the 75% interest in the Medusa field production facility. This acquisition continues our focus on the deepwater and further expands our footprint in there. During September, average daily production from the Medusa field was approximately 7,000 barrels of oil equivalent gross or 1,050 barrels of oil equivalent net, of which that is 88% is oil. Additionally, the first closing include various interests in other nonoperated Gulf of Mexico shelf fields that were not subject to a preferential right. We plan to close on the remaining properties towards the end of November for those properties, which the preferential rights our way. The average net daily production from all the shelf properties was approximately 5.1 million cubic feet of natural gas equivalent in September, of which 98% is natural gas. Total net proved reserves associated with the Callon acquisition are 2.4 million barrels of oil equivalent. All of which are classified as proved, developed reserves, and probable reserves of 2.3 million equivalent and possible reserves of 2 million barrels of oil equivalent. From a commodity standpoint, the reserves, including proved, probable and possible, are approximately 2/3 oil and 1/3 gas. This acquisition has all the elements we like. It generates good cash flow from proved producing properties, as well as offers good upside potential. The operator of Medusa, Murphy Oil, has stated that they expect to drill 2 wells in 2014 and are considering 3 additional wells in the future within the historical productive deepwater oil field. Our position in deepwater has become substantial, and deepwater production accounting for approximately 35% to 40% of our total production volume. We now have roughly 0.5 million growth acres in the deepwater, including a 23,000-acre growth we added from the Callon acquisition. Now in addition to the Callon acquisition, just yesterday late, we -- as a result of our preferential right to purchase, we executed another purchase of sale agreement to acquire 8.75% working interest in the currently producing Power Play field, which covers Garden Banks 258 and 302. W&T already owns the 35% interest in this deepwater field. And in close of this acquisition, our working interest will increase our position in the field to 43.75% working interest. The acquisition will be effective August 1, 2013, and it should close this month. We continue to symbol a good balance of producing deepwater properties and infrastructure to support future activity and exploration prospects to drive future reserve and production growth. Now I'd like to turn the call over to Tom Murphy, our Chief Operations Officer, to update you on our operations.

Thank you, Jamie. I'd like to update everyone on our recent operations and recent investments impacting our short-term rates and performance, and I'll begin with the offshore units. As we outlined in our earnings release, our investment activity is at our Mahogany field, Matterhorn field, the High Island 22 field, East Cameron 321 field and Main Pass 108 fields are all making incremental production contributions in the near term as our company-wide production has recently climbed and is currently up over 51,000 barrels of oil equivalent per day, as Jamie said. And we have other projects scheduled to come online in the short term, which are expected to further strengthen our production. At our Ship Shoal 349 field or Mahogany field, we expect to finish operations shortly on our A-12 well and place this well back on production, at which time we'll resume our drilling operations on our A-15 well. This well is a deep shelf sub-salt exploration well, targeting multiple stacked oil zones and horizons and is an offset to our highly successful A-14 well. We expect the A-15 well to be at total depth some time during the first quarter of 2014. At our deepwater Matterhorn field, we've begun the completion operations on the recently drilled A-5 side track well, which logged roughly 220 feet in net pay earlier this year. We expect first production from the A-5 in early December. In September, we conducted some recent production optimization projects at the Matterhorn field and performed the recompletion on the A-9 well, and I'm pleased to report that these activities together have significantly enhanced production from the Matterhorn field, allowing it to more than double to approximately 5,300 barrels of oil equivalent per day. And we expect oil output to be further boosted in the short term at this field when we bring the A-5 project online and ramp up our pressure maintenance project. We also just recently commenced operations on our exploratory well at our East Cameron 321 field in the Gulf of Mexico shelf. This well is targeting new oil reserves at 8,500 feet with initial production expected in the fourth quarter. We anticipate the initial production rate from this well to be approximately 850 barrels of oil equivalent per day net to W&T and have estimated the reserve potential for the project to be about 1.1 million barrels of oil equivalent. We have 100% working interest in the East Cameron 321 field and have been the operator since 2005. This field has been a great asset for the company over the years with cumulative production since discovery, totaling almost 95 million barrels of oil equivalent and crude oil making up roughly 80% of those volumes. The well we're drilling is based on reprocessed 3D seismic data that increase [ph] production potential in the Lentic 1 sand target. Mahogany, Matterhorn and East Cameron 321 are all examples of large substantial fields that we've acquired via acquisitions over time and have increased production and reserves using new technology, leading to new ideas, allowing W&T to expand and exploit these assets over time. And ultimately, we've added significant new reserves and meaningful value at these fields through the drill bit. At Mahogany, our drilling efforts have led to a sevenfold increase in oil production from this field since our acquisition, and our team has continued to find large impact project to track our investment. We believe that advances in technology, including new data gathering and evaluation processes, will continue to provide us with more opportunity to add value to the field across our asset base. Looking a little bit longer term on the offshore. In addition, we've got a number of deepwater projects driving that long-term growth. During the third quarter, we had a natural gas discovery at Mississippi Canyon 699 Troubadour, where we have a 20% working interest. Nearby, at our 2012 deepwater oil discovery called Big Bend, the operator Noble Energy recently sanctioned the project as a single well subsea tieback with first production expected in 2015. We are now participating with a 20% working interest. In an additional well, the Mississippi Canyon 782 #1, we call the Dantzler prospect, also operated by Noble in the same general vicinity, drilling operations are underway currently, and we expect results by year end. And this is another high-impact exploration well for us ongoing. Moving on to the onshore. As part of our expanded capital budget, we are adding approximately 7 additional vertical wells at the Yellow Rose field during the fourth quarter of 2013. We've been very pleased with our progress lately on our vertical well programs and plan to continue our current drilling pace. In the third quarter, we completed 9 new vertical wells, one of which was an exploration well. During the fourth quarter, we plan to continue to operate 2 rigs at our Yellow Rose field. We continue to see strong 30-day in average initial production rates from our wells and are well ahead of the average 30-day IP rate seen last year. We've reduced drilling cost and continue to improve efficiency. Our 40-acre well spacing test also continue to yield positive results, and we expect to continue our 40-acre expansion efforts into 2014 and are beginning to plan opportunities for 20-acre down spacing test. Recently, we spud the first horizontal Wolfcamp B well on our acreage in Martin County. The well's lateral length exceeds 6,000 feet, and we reached TD last night. We like how the well was drilled, and we like our encouraging results to-date, which are limited to shoals and mud logs. Over the next few days, we'll be running our full formation evaluation suite, and then we'll move in to completion. I hope to have this well frac-ed and stimulated before the month end with flowback results coming before the end of the year. We currently see approximately 150 potential horizontal drilling locations per bench, and we see prospectivity in as many as 4 to 6 possible horizontal benches in our field, with this well being our very first Wolfcamp B test. So we are still very early in our reserve de-risking process in the field relative to the horizontal potential, but see significant potential value and significant drilling inventory and are excited about this Wolfcamp test over the next several weeks. We will continue to evaluate our other potential benches, which we'll likely test in the coming months. We're still on the exploration mode. And once we identify all the upside, we can shift to the cost engineering mode in the field to maximize value further. We're about 85% held by production, or HBP, which allows us to be a little bit more flexible on our drilling program. The northward expansion and growth in industry activity surrounding our acreage reflects both the potential of our acreage and the significant value tied to our current position. Shifting to East Texas, we recently spud and are currently drilling our fifth horizontal well at our Star Project. The well is targeting the oil in the James Lime at about 8,500 feet true vertical depth with a planned lateral length of just over 6,000 feet. We expect to complete this well during the fourth quarter also. The result of this well would determine and shape our future plans for this area. So with that operations update, let me turn it back to Jamie to update you on our budgets and planning.

Thank you, Tom. We previously increased our capital budget for 2013 to $550 million. The additional dollars will accommodate the addition of our Dantzler deepwater exploration well, additional drilling in our Yellow Rose field, completion cost from our successful exploration drilling and new seismic and leasehold costs. These projects are underway and, with success, will add future reserves, production and other development opportunities. Although we aren't complete with our 2014 capital budget planning, I can say that next year we will have another active year. Our inventory of organic opportunities continues to grow. We are reprocessing seismic data in a number of areas offshore and are currently in the process of obtaining new data, including the WOS data over numerous blocks. Alongside these efforts, our technical staff is focused in multiple field settings, which are expected to create additional exploration development wells to our portfolio, both onshore and offshore, for future years. This would include the evaluation of deeper targets below our existing field pay. Finally, as you can see, we are very active in the acquisition market. The Gulf of Mexico acquisition opportunities continue to be plentiful. We believe that our reputation as a ready buyer of quality Gulf of Mexico properties is to our advantage. There are a large number of valuable assets, including many deepwater properties for sale, that are expected to come to the market from both large and small operators that provide future opportunities for W&T. As always, we are always looking for transactions that create value for our shareholders. And now, operator, we are ready to take questions.

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

Jamie, just wondering on the -- I look into Yellow Rose. I know you all have laid out as far as what sort of the capital plans are there. I'm just wondering if you continue to see success for you all on the horizontals, as well as some of the peers, are you still pretty agile as far as how the operational plans may change or just any color you could talk about, sort of how maybe instead of just the total rigs or something just kind of how you see that development plan playing out next year?

Yes. We actually are watching very closely the activity in and around our field area. But as far as giving you some color for next year and the budget, we would like to defer to that later when we approve the budget. But we are encouraged by that activity. We're encouraged by our own results and our vertical wells, and we're anxious to see the results of this horizontal B -- Wolfcamp B test that we're actually doing as we speak.

Okay. And then just one follow-up on, obviously, it seems like on the Main Pass 108 and High Island 21, I think you mentioned that they're producing. And you can add any color as far as -- I know on the comments on the press release, it kind of mentions what you're seeing on each of those that they're currently producing. And I think, further on, you mentioned a little bit on the size. Maybe comment as far as what are -- I guess just so I'm clear on those, those are currently producing today, and those are already tied into sales. And then what sort of magnitude are you looking on those?

Well, we -- they are producing, and they are currently within the guidance that we put for fourth quarter and year end -- for the year guidance. So as far as future projections, let's kind of wait and see. As you know, offshore, the way this works is we'll see how it performs over time. And if we're able to increase production or add reserves as a result of that, it's just a matter of time on that.

Our next question comes from the line of Noel Parks with Ladenburg Thalmann. Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division: Just a couple of things. At the Star Project, you guys are describing it as mainly an oil project. I remember originally when you were looking at it, the thought was that it would have a lot of gas. But I thought it was better maybe 2 or 3 quarters ago, I remember you shifting to the thinking it was -- they're going to be more oil. Where does that stand now? And is that sort of oil, gas mix uniform across the acreage as far as you know at this point?

Well, I believe -- I know for a fact that the Star Project, we've been working on this for about 1.5 year, maybe almost close to 2 years. We've always advertise it as what we were chasing with the oil window and the James Lime, and it is a new play for the oil as you could -- as you've seen it in the past from other operators as more of a gas play. But we've always chased on the oil window. And we have continued to explore this opportunity. And to-date, we have not booked any reserves out here. We continue to do exploration tests to see if this play will go forward. And with success, we expect it to be a nice development play for us. Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division: Great. And then I heard about the -- earlier, you were talking about the really great results from the Matterhorn production optimization. So I was just wondering if you could talk a little bit more about what was involved and whether you see a lot more opportunities like this particular one at Matterhorn.

I didn't hear the first part of your question. But as far as Matterhorn goes, Matterhorn was acquired property. We brought it in-house. We did a lot of extra work. We bought data. We've exploited that property and continued to grow the production out there with not only additional wells, but also through a development program -- a water pressure maintenance project that we kicked off this year. And Tom, would you like to add any more to that?

Yes, the question really was what drove it. It was fundamentally -- the biggest impact was that A-9 recompletion where we took it to a new interval, a new behind pipe, which performed very well, a little bit better than our expectations actually. And while your question really isn't asked in this manner, but there's a lot -- what we're doing in -- which we've eliminated before. But the interesting thing about Matterhorn and that's where we're going with this initial project with the A-5, it's going to set up to make some longer-term opportunities and surely some reserve growth with our pressure maintenance project. We haven't booked those things yet. So we're going to get that into production. And then probably through the course of 6 to 12 months, we'll probably see reserve appreciation there through the pressure support project. And then as we've eliminated before, we'll -- if we like the looks of that, that's going to completely de-risk, which is actually a larger target for us into the Western sector of the field. So that hold some good reserve growth going forward for us over the next year to 2.

Our next question comes from the line of Curtis Trimble from Global Hunter Securities.

I was hoping to delve a little bit into maybe the economics out at Yellow Rose on the vertical vis-à-vis the horizontal program and kind of which you've looked to in terms of hurdles, maybe at risk factor, et cetera for the vertical wells vis-à-vis expectation for the horizontals.

Well, the horizontal program on the Yellow Rose project. We're -- as we say, we've done some horizontals on the Wolfcamp Bay, and we'll continue to watch results of that. But we're more excited about the Wolfcamp B as we're -- and with this new well. And as far as expectations, we have huge expectations based on a lot of activity around us, where we have wells directly offsetting us that have done very well in the Wolfcamp B. So we'll wait to -- really wait to see the results of our well, and we'll give you more color around the economics and what we plan to do in development forward.

Okay. Can you give us an A or B on that initial B well and how we comped up with your prior A experiences?

Curtis, what was -- can you speak up a little bit? What was the question again?

Just looking for a cost on that B well vis-à-vis what's your [indiscernible] A experiences?

Oh, the B well? Yes. Well, we think the wells would probably come in -- of course, it depends on the lateral length. It depends on exactly what we do on the completion. But normally, we're probably talking initially in the $7 million to $7.5 million range. And through time, like for instance, we're going to do a pretty sophisticated formation and logging package on this as one example in the future with our optimization. We'd start to cut back and remove things like that as we get more into the optimization phase. I think long term, we're probably looking at $6 million to $6.5 million, I would hope, as a target point for our drilling complete on this, depending on the lateral lengths, again. And we're doing kind of a mid-length lateral here. This is about, like I said, a little over 6,000 feet. We and others are drilling as short as in the mid-4s and we've taken them over 7,000 feet. So we're looking forward -- and it depends exactly on what your acreage position is and what the lease offer's relative to that. So those all drive the cost, too. But I think we'll be in the, again, $7 million range initially with a reduction later into the future.

Sure. And looking at, say, a 12-stage frac program, are you going to be a little bit more aggressive than that?

Can you take the question?

Curtis, go ahead. I couldn't hear that again.

So looking initially at a 12-stage frac program, are you going to be a little more aggressive than that?

No. Well, again, I want to wait until I see the log, but we'll probably be well in excess of 12. I think we'll be knocking in the 18 to 20 stages per well probably at a well like that. We're pretty aggressive on the sand placement and the volume of sand and our stage -- our length between stages.

I appreciate it. Looking at the Gulf of Mexico acquisition environment. In the package you just see now, are they generally at the smaller type? Or do you see some large Apache-type packages out there with folks looking to exit the area in total?

We're seeing both, both from large operators and small operators, and we're hearing about some things that maybe coming down the pike.

Got in and in general, what do you think is motivating that decision-making process?

I'm not sure, everyone has different reasons and different objectives and different capital needs because it's a little bit of combination of everything. But everybody has their own reasons for selling.

Our next question comes from the line of Richard Tullis with Capital One. We will move to the next question. Our next question comes from the line of Brian Foote with Clarksons.

Just a quick question. On the Medusa project, you indicated that the operator is talking about drilling potentially 2 wells next year and 3 in 2015. Can you give us any idea of what the CapEx would be related to those wells? What you're targeting? How that could impact the production and/or reserves?

Well, I would expect that we will do that more once we get the proposals from the operator, and also we incorporate that in our budget. We've been really good about it in the last few years to make sure that on -- particularly on these deepwater wells, we give you as much color as possible as to what the costs are, the depth and what the expectations are going into the wells. So you'll see that once we get it on a schedule. And as far as the additional wells after '14, not necessarily, we're not sure if it's going to be '15 or something beyond that, but -- because we don't have exactly when that would be. But '14 looks like it's going to happen, and we provided -- we're going to provide for that in our budgeting process.

Okay, perfect. And then on the Permian side, just for clarification, you talked about the potential in 4 to 6 benches. Is there a way to think about what is the increment? I mean, what makes it 4 or what makes it 6? What should we be looking for or listening for as you test out those different benches?

Well, as you know, this segment of Wolf area is 4,000 feet segment that we've been targeting on a vertical well. And in our -- as our -- we get our results from the vertical wells, we're seeing that these -- what we're calling benches are these different areas that we can see as potential to have the horizontal development in addition to the vertical development. So it's in the infancy stages. As you know, we've started with the A. And now we're moving to the B. Other operators are just out now looking at things like decline. I think it's just -- it's an evolving project. We're kind of in this exploration phase still as you look at the other benches. And as they develop and put positive results, you'll see a full development of those subsequent to that happening. So one of the things on these resource plays, you drill these wells, and you don't get immediate results. You drill them, and you frac them, and you have to wait a while. So these things take longer than the conventional play does to evaluate, so time will tell, really.

[Operator Instructions] Our next question comes from the line of Michael Glick with Johnson Rice. Michael A. Glick - Johnson Rice & Company, L.L.C., Research Division: Jamie, I think you mentioned acquiring wide-azimuth seismic in the Gulf of Mexico. I was just curious if you could provide kind of more color on what that will cover and, I guess, specifically, if you'll be acquiring wide-azimuth over at Mahogany.

Yes, we will give more color to that. Part of this is the purchase of existing WOS data and part of it's going to be participating in some new shape that would help some existing fields. And I think we're going to give more color to that in the next month or so. Michael A. Glick - Johnson Rice & Company, L.L.C., Research Division: Okay, great. And then I guess given the success you've had at Mahogany, I mean, is it reasonable to expect that, that rig is going to stay on location for, I guess, the foreseeable future?

Yes, we're expecting that, and we're planning for that as part of the '14 plan.

And at this time, we have no further questions. I would like to turn the conference back to Ms. Vasquez for any closing remarks.

Thank you, again, for listening, and we're excited about as we go into the fourth quarter and end of the year as we plan for '14. It's looking -- it's really good, and our results have been very positive. So thank you for listening and then have a great day.

Ladies and gentlemen, this does conclude the W&T Offshore's Third Quarter Earnings Conference Call. Thank you for your participation. You may now disconnect.