W&T Offshore Inc (WTI) 2013 Q3 法說會逐字稿

Good morning, ladies gentlemen. Thank you for standing by. Welcome to the W&T Offshore's third quarter earnings conference call. During today's presentation, all parties will be in a listen-only mode. Following the presentation, the conference will be open for questions.

(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 from the third quarter of 2013. Before I turn the call over to management, I have a few items that I'd like to point out. I

f 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 enter the passcode 4645500, pound.

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 would like to turn the call over to Jamie Vazquez, W&T's President.

Thank you, Mark and good morning, everyone. 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 last year. As a result, 82% of our third-quarter revenue were derived from our liquid production.

Revenues grew to $244.6 million and two-thirds 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 is a 34% increase and has 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 did not continue to have substantial production volumes 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 at 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 averaged 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 and reserves through accretive acquisitions.

On November 5, we closed on a majority of the properties associated with the acquisition of Callon Petroleum 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 a 75% interest in the Medusa fields production facilities. This acquisition continues our focus on the deepwater and further expands our footprint there.

During September, average daily production from the Medusa field was approximately 7,000 barrels of oil equivalent growth or 1,050 barrels of oil equivalent net of which that, 88% is oil. Additionally, the first closing includes various interest and other non- operated Gulf of Mexico shelf fields that were not subject to a preferential right.

We plan to close on the remaining properties toward the end of November for those properties in which the preferential rights are waived. 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 crude 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 barrels of oil equivalent and possible reserves of 2 million barrels of oil equivalent. From a commodity standpoint, the reserves including proved, probable and possible are approximately two-thirds oil and one-third 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 in Medusa, Murphy Oil, has stated that they expect to drill two wells in 2014 and are considering three additional wells in 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 gross 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, as a result of a preferential right to purchase, we executed another purchase and 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 a 35% interest in this deepwater field and at 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 would 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 activities at our Mahogany field, Matterhorn field, Highland 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.

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 operation shortly on our 812 well and place this well back on production, at which time we will resume our drilling operations on our A-15 well. This well is a deep shelf subsalt exploration well targeting multiple stacked oil zones and horizons and is an offset to our highly successful A-14 well. We expect A-15 well to be at total depth sometime during the first quarter of 2014.

At our deepwater Matterhorn field, we've begun a completion operations on the recently drilled A-5 side track well which logged roughly 220 feet of net pay earlier this y ear. 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 a 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.

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 operators 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 are drilling is based on reprocessed 3-D seismic data that indicates production potential in the Lentic 1 sand at target. Mahogany, Matterhorn and East Cameron 321 are all examples of large, substantial fields that we have 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.

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 teams continue to find large impact projects to tract 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 fields 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 will subsea tie-back with first production expected in 2015.

We are now participating with the 20% working interest in an additional well, the Mississippi Canyon 782 number 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. This is another high impact exploration well for us ongoing.

Moving onto the onshore, as part of our expanded capital budget, we are adding approximately seven 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 program and plan to continue our current drilling pace. In the third quarter we completed nine new vertical wells, one of which was an exploration well. During the fourth quarter we plan to continue to operate two rigs at our Yellow Rose field. We continue to see strong 30 day and average initial production rates from our wells and are well ahead of the average 30 day IP rates seen last year.

We've reduced drilling costs and continued to improve efficiency. Our 40-acre well spacing tests 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 tests.

Recently, we spud the first horizontal Wolfcamp B well on our acreage in Martin County. The well's lateral length exceeds 6000 feet and we reached TD last night. We like how the well drilled and we like our encouraging results to date which are limited to shows and mud logs. Over the next few days, we will be running our full formation evaluation suite and then we will move into completion. I hope to have this well fracked 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 four to six possible horizontal benches in our field. With this well being our very first Wolfcamp B test. 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 are still in 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 are 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 and 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 oil in the James lime at about 8,500 feet to vertical depth with a planned lateral length of just over 6,000 feet. We expect to complete this well during the fourth quarter also. Results of this well will determine and shape our future plans for this area.

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 costs 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 [WASS] data over numerous blocks.

Alongside these efforts, our technical staff is focused in multiple field studies which are expected to create additional exploration and development wells to our portfolio both onshore and offshore for future years. This would include the evaluation of deeper targets below our existing field pays.

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 or 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)

Neal Dingmann, SunTrust.

Jamie, just wondering on -- looking at the Yellow Rose, I know you have laid out as far as what 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 any color you could talk about? How instead of just total rigs or something just how you see that development plan playing out next year?

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

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

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

That's great. Thank you.

Noel Parks, Ladenburg Thalmann.

A couple of things, at the Star project, you, these days, 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 two or three quarters ago, I remember you shifting to thinking it was going to be more oil. Where does that stand now, and is that oil/ gas mix uniform across the acreage, as far as you know at this point?

I know for a fact that the Star project -- we have been working on this for 1.5 years, almost close to two years. We have always advertised it as what we were chasing was the oil window in the James Lime. It is a new play for the oil, as we've seen it in the past from other operators, it is more of a gas play, but we've always chased it 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. With success, we expect it to be a nice development play for us.

Great, thanks. I heard about -- earlier you were talking about the really great results from the Matterhorn production optimization. I wondered 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 of -- a pressure maintenance project that we kicked off this year. Tom, would you like to add anymore 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. While your question really isn't asked in this matter, but there's a lot -- what we're doing and which we've illuminated before, but the interesting thing about Matterhorn, and that's where we are going with this initial project with the A-5, it's going to set up, to me, some longer-term opportunities and surely some reserve growth with our pressure maintenance project.

We haven't booked those things yet, but we are going to get that into production and then probably through the course of 6 to 12 months we will probably see reserve appreciation there through the pressure support project. As we've illuminated before, if we like the looks of that, that is going to completely de-risk, which is actually a larger target for us into the western sector of the field. So, that holds some good reserve growth going forward for us over the next year to two.

Okay, thanks a lot.

Curtis Trimble, Global Hunter Securities, LLC.

I was hoping to delve a little bit into maybe the economics out at Yellow Rose on the vertical vis a vis the horizontal program and what you hope to, in terms of hurdles, maybe a risk factor, et cetera for the vertical wells vis-a-vis expectations for the horizontals.

The horizontal program on the Yellow Rose project as we say, we've done some horizontals on the Wolfcamp A, and we're continuing to watch results of that, but we are more excited about the Wolfcamp B with this new well. And as far as expectations, we have huge expectations based on a lot of the activity around us.

We have wells directly offsetting us that have done very well in the Wolfcamp B. We will wait to see the results of our well and we will give you more color around the economics and what we plan to do in development forward.

Okay, can you give us an AFB on that initial B well and how it comped up with your prior A experiences?

Curtis, can you speak up a little bit? What was your question again?

Just looking for a cost on that B well vis-a-vis what your experience has been.

We think the wells will probably come in -- of course it depends on the lateral length, it depends on exactly what we do on the completion, but nominally we are probably talking initially in the $7 million to $7.5 million range. Through time, for instance, we are 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 are probably looking at $6 million to $6.5 million, I would hope as a target point for drilling complete on these, depending on the lateral lengths, again.

And we are doing 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-fours and we've taken them over 7,000 feet. So we are looking for -- and it depends exactly on what your acreage position is and what the lease offer is relative to that. So those all drive the cost, too. But I think we will 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?

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

Looking additionally at a 12-stage frac program, are you going to be a little more aggressive?

Again, I want to wait until I see the log, but we will probably be well in excess of 12. I think we will be knocking in the 18 to 20 stages per well, probably, at a well like that. We are 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 packages you see now, are they generally of the smaller type or do you see some large patchy type packages out there with folks looking to exit the area in total?

We are seeing both. Those from large operators and small operators and we're hearing about some things that may be coming down the pike.

Got you. 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. A little bit of a combination of everything. Everyone has their own reasons for selling.

Very good. I appreciate it.

Richard Tullis, Capital One. Richard, please go ahead. We will move to the next question. Brian Foote, Clarkson's.

A quick question. On the Medusa project, you indicated that the operator's talking about drilling potentially two wells next year and three 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 production and/or reserves?

I would expect that we would do that more once we get the proposals from the operator and also we incorporate that in our budget. We have been really good about in the last few years to make sure that, 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 well.

So you will see that once we get it on a schedule. And as far as the additional wells after 2014, not necessarily, we're not sure if it's going to be 2015 or something beyond, that because we don't have exactly when that would be, but 2014 looks like it's going to happen and we are going to provide for that in our budgeting process.

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

As you know, this segment of Wolfberry is a 4,000 feet segment that we've been targeting on our vertical well, and as we get our results on the vertical wells, we are seeing what 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. It is in stages. We started with the A, now we're moving to the B. Other operators are out now looking at things like the Cline.

I think it is an evolving project. We're in the exploration phase still as you look at the other benches. As they develop with positive results, you will see full development of those subsequent to that happening. So, one of the things in 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. These things take a lot longer than the conventional play does to evaluate. Time will tell, really.

Great, thanks.

(Operator Instructions).

Michael Glick, Johnson Rice.

Jamie, I think you mentioned acquiring wide azimuth seismic in the Gulf of Mexico. I was curious if you could provide more color on what that will cover and specifically if you will be acquiring wide azimuth over Mahogany?

Yes, we will give more color to that. Part of it is purchase of existing WAZ data and part of it is going to be participating in some new sheet that would help some existing fields. I think we are going to give more color to that in the next month or so.

Okay, great. Given the success you've had at Mahogany, is it reasonable to expect that that rig is going to stay on location for the foreseeable future?

Yes, we are expecting that and we are planning for that as part of the 2014 plan.

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 are excited about as we go into the fourth quarter and into the year and as we plan for 2014. It is looking really good and our results have been very positive. Thank you for listening and 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.