W&T Offshore Inc (WTI) 2013 Q2 法說會逐字稿

Ladies and gentlemen, thank you for standing by. Welcome to the W&T Offshore second quarter conference call. During today's presentation, all parties will be in a listen-only mode. Following the presentation, the conference will be opened for questions.

(Operator Instructions)

This conference is being recorded today, August 8, 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 second quarter of 2013. Before I turn the call over to management, I have 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 15, 2013. To use the replay feature, call area code 303-590-3030 and dial the pass code 462-8422, pound. Information recorded on this call speaks only as of today, August 8, 2013, and therefore time-sensitive information may no longer be accurate as of the date of any replay. Please refer to our second quarter 2013 earnings release for a disclosure on forward-looking statements.

At this time, I would like to turn the call over to Tracy Krohn, W&T's Chairman and CEO.

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

Our strategy to drive growth organically is yielding solid results. Successful exploration wells in the Gulf of Mexico and in West Texas are generating reserves and production in 2013, as well as helping to build an inventory of longer term exploration and development projects for further growth. Our development program is building on past successes and converting our high quality crude reserves into significant cash flow. We're turning reserves into money. The success of our organic growth program has been driven by the strategic initiatives we've implemented over the last few years. We've been adding staff, realigning teams, refining our incentive programs. We've focused on seismic data and analysis, and we've acquired a new leasehold. We're also evaluating joint venture opportunities, and we continue to identify additional opportunities along those lines.

We have increased oil content of our total production to 40% in the second quarter up, from 33% in the second quarter last year, or 20%. Growth in oil production from our Mahogany Field and Yellow Rose projects are major contributors to this increase. In the first half of 2013, we generated almost $300 million of net cash from our operations, up from a little over $240 million in the first half of 2012. On August 1, we received a $54 million tax refund, which further strengthens our liquidity position. We actually didn't expect that until later on in September, so that was a nice little surprise. Also, yesterday our Board of Directors approved a $0.09 per share cash dividend on our common stock, continuing our practice of returning cash to our shareholders.

In the second quarter, we had a 9% increase in revenue, primarily due to higher oil volumes and higher gas prices. Revenue and cash flow would have been much higher if we hadn't been impacted by substantial production deferrals, resulting from various third-party pipeline outages, platform maintenance, and some well performance issues that needed to be resolved by workovers. Overall, we had approximately 3.2 Bcf equivalent of production deferral in the second quarter of which about 70% was natural gas. Adding back those deferred volumes, production for the quarter would have averaged roughly 308 Mcfe per day, up 2.6% from first quarter production levels.

We do expect some of these operational production deferrals to continue which is reflected in our revised annual guidance and our new third quarter guidance. On the other side of the equation, we've made a significant increase in our full year guidance for oil and NGLs, as a result of our successful exploration and development projects so far this year. Our Ship Shoal 349 A-14 well at Mahogany was brought on production in July, and with more projects coming on line in the next few months, we expect to see production of oil and liquids strengthen in the second half of the year.

Given the outlook for commodity prices raising our oil and NGL guidance beyond the high end of previous full year range should reflect nicely in our expected revenues as well. Remember, guidance includes 2.5 Bcf equivalent of down time for storms. We opted to keep this in our guidance, however, if not used, we anticipate that we would revise guidance to add back those volumes. Also, acquisitions and divestitures are not in our guidance. Regarding the increase in our lease operating expense guidance for the full year, we've added two major workovers at our Fairway Field and a couple of other workover projects to enhance production. Conversely, we've reduced our guidance for gathering and transport expenses and production taxes, primarily because of better-than-expected outcomes regarding the FERC-regulated rate cases.

Let's move on to operations. On the shelf in the Gulf of Mexico, we've continued to be very active in our Mahogany Field at Ship Shoal 349. As we recently announced during July, we made a subsoil discovery in a deep shelf exploratory target that exceeded our expectations. The A-14 well had an initial production rate from the targeted T-sand of 3,030 barrels of oil and 5.6 million cubic feet of gas per day for a total of approximately 4,000 barrels of oil equivalent per day gross. That is 3,310 BOE per day net. Subsequently, that well has reached a peak production rate so far of 3,588 barrels of oil and 6.3 million cubic feet of gas per day, for a total of 4,644 BOE per day gross or 3,870 BOE per day net. That well's producing at that rate today. Because our Mahogany Field has infrastructure in place, the well is already on production and generating cash flow.

This field is expanding with each exploratory well and the A-14 is the deepest productive sand to date. So, we still haven't run out of oil hydrocarbon column in this field. [Well ahead] of high quality oil sands which haven't previously been discovered, as it (inaudible) the M, N, and O-sands, all of which represents reserve additions to the Company. The A-14 also penetrated a thicker-than-expected P-sand interval which is the primary field pay sand. In total, the well logged over 370 feet of net oil pay, with the T-sand accounting for 108 feet of total new pay. This discovery provides immediate incremental production and stimulates additional drilling opportunities to exploit the other newly discovered oil sands that were encountered in the A-14 well. Our team is already looking at the possibility of drilling another exploratory well at Ship Shoal 349 in the early part of 2014.

Currently, the platform rig at Mahogany is working on a major recomplete in the A-4 well to bring a behind pipe P-sand interval into production. We anticipate putting it on production in late August or early September, at an estimated net rate of 1,000 barrels oil equivalent per day. Following the A-4 recomplete, we expect to spud the A-15, another deep shelf subsalt exploratory well, which targets oil stands and multiple horizons. The well is scheduled to reach TD near the end of 2013 or early 2014, with a target IP rate of 1,390 BOE per day net to us after royalties. The target reserve potential associated with this well is anticipated to be in the range of 1.8 million to 6.2 million barrels of oil equivalent.

Assuming success, this well would derisk a number of additional locations in the field and provide us with significant unrisked reserve potential. Mahogany has low-risk upside drilling opportunities in the known producing sands, and we've established now that further upside opportunities from continuing to test this deep shelf subsalt opportunities certainly behoove us. As we mentioned in the release, this oil field just continues to grow in both its aerial footprint, as well as in vertical column, and number of production sand intervals. Every time we get new data, we find additional reserves in the field. We hadn't defined the limits of this field and that's really cool.

At our Main Pass 108 field, we've completed the B-1 side track, a new discovery well, and expect first production possibly as soon as this weekend. The well encountered 73 feet of measured depth pay in the target Tex W-6 sand, as well as additional 30 feet of measured depth pay in the Tex W-3 sand. We'll see new reserve bookings from both the primary Tex W-6 sand, as well as the secondary Tex W-3 sand. This well is expected to produce very liquids-rich natural gas, and we anticipate having an initial production rate of around 950 BOE per day net. We continue to evaluate other opportunities in the field, and we may drill another well there as part of our 2014 drilling program.

Another upcoming exploration well is our East Cameron 321 A-2 side track. As a result of a field study, we've identified this opportunity which is Lintec test at about 8,500 TVD. We'll mobilize a rig in September and reach TD in mid-October. Our expected initial production rate for this well is approximately 850 BOE per day net. Historically, East Cameron 321 has been a significant producing oil field, and this project has a targeted resource potential of 1.1 million barrels of oil equivalent. In regards to our development projects on the shelf, our High Island 21 A-1 development well was a success. First production is expected in late third quarter or early fourth quarter. The well encountered LH20 main pay sands largely as expected. In its upside, it also penetrated additional pay zones in the LH16, which represents additional reserve bookings and a future recomplete.

In the deepwater Gulf of Mexico, we're participating in the drilling of a well, the Troubadour prospect at Mississippi Canyon 699. That's in the adjacent block to our recent oil discovery at Mississippi Canyon 698, which we call Big Bend. We should reach total depth at Troubadour in a few days. With success at Troubadour the two wells will likely be co-developed. We have a 20% interest in both wells. Big Bend discovered oil sands with high-quality reservoir properties and fluid characteristics, so we're looking forward to getting results on Troubadour.

We continue to achieve excellent results in our Matterhorn Field at Mississippi Canyon 243. In fact, we recently reached TD in the A-5 side track well, which was planned as a pressure maintenance project, water injection, for the eastern portion of the field. Upon reaching TD, the well logs revealed 220 feet of net pay in the well bore. The log pay was well in excess of our pre-drill expectation. It is one of the thickest A-sand intervals in the field. So, we're going to produce the A-5 for a period of time and then expect to resume the original plan to utilize the well to assist in our field pressure maintenance program. Completion operations are underway, and we expect first production in early fourth quarter, so nice surprise there as well.

Moving to onshore drilling activity, in West Texas, we continue with our current two-rig drilling program at Yellow Rose. We completed nine wells in the second quarter, of which two are horizontal and seven are vertical. We've completed another horizontal well and another vertical well during July. The June exit rate at Yellow Rose was approximately 3,989 net BOE per day, and the July new peak production for the field reached 4,387 net BOE per day. We've continued to drill some of our vertical wells on 40-acre spacing, and have found their performances consistent with the type curve seen in the offset 80-acre wells on our Yellow Rose acreage. We booked reserves for approximately 50 PUD locations on 40-acre spacings which represents only a small portion for our total potential 40-acre down-spacing well locations. Further upside from the Company exists when we move towards 20-acre vertical spacing tests which will be a consideration for our 2014 drilling program.

So far, our six completed horizontal wells have targeted the Wolfcamp A formation. As we've stated previously, we've been testing this formation with varied results and will continue to refine target depths, optimize our specific completion techniques and lateral length, and evaluate early time production trends in all our wells. Currently, we're planning to begin testing the Wolfcamp B formation with our first horizontal well scheduled for the third quarter. Our early indications in petrophysical analysis have suggested that equivalent production potential exists from this interval as compared to other known Wolfcamp B production elsewhere in the basin. We expect to have some results from this Wolfcamp B horizontal well before year end 2013. We continue to expand our acreage position therein. We recently acquired an additional 2,160 net acres which offsets and is surrounded by our current Yellow Rose Field. This increases our net acreage position by approximately 10%. It brings our total net acreage position at Yellow Rose to 25,730 acres. That is again net acreage.

In East Texas, at our Star Project, we continue to monitor our four initial wells and have begun planning our fifth horizontal well. We expect to spud the fifth well during the fourth quarter. In the second half of 2013, our high level of activity and balanced mix of projects that are underway should yield both near term and longer term organic growth. Regarding acquisitions, the market's very active. We are reviewing a lot of interesting asset packages, but we're going to remain selective. As we mentioned during the last call, we do have some of our offshore shelf assets on the market. The bidding round is closed and we're currently evaluating a variety of options proposed. Activity such as this helps support our balanced approach to growth.

Wrapping up, the last half of 2013 has a lot of high potential impact for growth via exploration and production. We continue to see good potential opportunities for acquisitions, and we expect to obtain our fair share of that market as well. With that, operator, we'll open up the phone lines for questions.

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

(Operator Instructions)

Please ask one question and one followup, then re-queue for additional question. Neal Dingmann with SunTrust.

Morning, Tracy. Tracy, I want to make sure I understand. After the big find that you had in that Ship Shoal 349 Mahogany field, I know you mentioned in the press release a number of other potential zones. I'm trying to get a handle just in that T-sand around in that field, is there numerous other well opportunities? I'm just trying to get a sense of how many -- the potential of the T-sand, as well as other zones there.

Specifically, the answer to that is, yes. There are other opportunities in the P-sand. We could actually just drill an acceleration well for the P-sand, because this existing T-sand is going to be there for awhile. Fortunately, we also have some other sands in between the target sand and the P-sand and the T-sand.

Okay. Then, just one follow-up, moving over onshore. You obviously have a lot of opportunity to either through the down space, vertical down-spacing, or the horizontal. I'm not sure if you know at this point, but would you continue with the two rigs going after all of that? Or if you see an opportunity that the horizontals continue to work, or the 40-acre down-spacing works, would you add another rig sooner rather than later?

You're right, we are evaluating that right now. Of course, oil prices have a lot to do with that, Neal. We see multiple benches in the field. We have operators in the area that are testing multiple benches. We're pretty damn excited about that whole area. So, more to come on that. You're right, we haven't made any decisions along those lines yet. But we're certainly in that period of time of the year in which we start formulating those plans.

Thanks, Tracy. Look forward to all the activity.

Michael Glick with Johnson Rice.

Good morning. Just a question again on Mahogany. Given the seemingly large amount of opportunities out there, is there any possibility to add a second rig? I know you have a platform rig, but could you add another rig out there?

Yes, it's in fairly deep water, it's in about 500 feet of water. We originally started out with a three-well program. We're on -- we've held the rig now for about another year. We're on about the sixth well here. So, we're not interested in putting another rig out there. It would probably require a very large jack up, and I think we're better off, on an IRR basis, of maintaining just one rig in this particular field, yes.

Okay. Then, just in terms of your undeveloped deepwater blocks, is there update there, in terms of where you stand in terms of partnership discussions, or the possibility of drilling a well this year?

Yes. With regard to Big Bend, you're talking about?

No, just your undeveloped W&T-operated leasehold that you acquire via Newfield.

Yes, that possibility exists. We're looking at some other opportunities as well. So, the last part of the year is going to be pretty interesting.

Got it. Thank you.

One thing I should point out is that Troubadour was our other budgeted well. That's the block adjacent to it, the Troubadour.

Thank you.

(Operator Instructions)

Richard Tullis with Capital One Southcoast.

Good morning, Tracy.

Good morning, Richard.

Getting back to the subsalt discovery, what was the drill and complete cost on that well?

D&C was around $45 million to $50 million.

Okay. And, what do you estimate the reserves are on that well? I guess your pre-drill was around $3 million or so, if I remember correctly. But it sounds like it's above that.

It could be. We'll know more after we get a little more production history. And that's the point. So far, well pressures are standing up very good. We're very pleased with [gross-] producing characteristics of this well. Production has leveled off at the rates that I've told you, that were actually up from the initial rates.

Okay. Do you see additional subsalt potential on your acreage, in particular, on the shelf where it hasn't been really drilled that much over the years?

Yes.

Looking out into 2014, do you think you'll be drilling some more subsalts?

Yes.

Okay. That's all for me right now. I'll jump back in the queue.

Curtis Trimble with Global Hunter Securities.

Thank you. Good morning, everyone. Tracy, I was wondering if you could give us the forecasted production rate on those two large workovers that bumped up the LOE extent in the quarter.

That would be about $30 million a day.

Okay. Good deal. And then --

That's over in Fair -- I'm sorry, yes, $25 million a day, excuse me. Net. That's over in Fairview -- Fairway, excuse me, Fairway.

Then, coming onshore out at Yellow Rose, and it may be a little bit too preliminary to talk about it, but in terms of mapping out the B versus the A, any idea of how many locations that might open up, if it proves out to be as successful as the A is?

I really haven't thought it through to that point. We need to get some data on the Wolfcamp B. But, it would be very similar to whatever we would have generated in the Wolfcamp A, Curtis. There are other operators having success with the B, and it's varied success across the basin. We're also looking at other benches in that same area, so they're all different, and they all have different formulas. I think to range it for you, maybe 50 to 100 locations per zone, on horizontal.

Would you be willing to tell me where the county is that this initial one's going to go down in?

I think that's going to be in Martin County.

Very good, I appreciate it.

Noel Parks of Ladenburg Thalmann.

Good morning. You might have touched on this already. I got on a little bit late. For the shelf properties you're looking at divesting, can you just talk a little bit about, as far as what you're interested in maybe letting go of and letting somebody else consolidate, versus what might appeal to you from an acquisition standpoint? [You're selling] (inaudible), are there any particular types of asset that you might effectively trade for, or something?

That's a little bit of a nebulous question. Let me see if I can break it down for you. We've got three individual regions in the Gulf -- East, West and Central. And we're offering properties from all three of those areas. We have not included Mahogany in any of that equation, if that helps clarify anything for you.

Sure. Let me see. I had tended to think of W&T as being a little bit more of a consolidator of Gulf assets, as opposed to interested in selling.

Let me address that for you a little bit. We've sold properties in the Gulf many times. In fact, we sold some last year to -- I think it was EPL. The idea of selling properties, any of those properties are for sale every day, Noel, for the right price. As a private Company, we sold assets all the time. That was part of our regular business strategy. We get the debt up a little bit, and then we get the production up, and then we'd sell properties. Then, we would put the money back in the ground. Nothing different here. Debt's up a little bit, we'll sell some properties. We'll put it back, and we'll pay down debt. We'll put the money back in the ground.

Great. And --

It's more of a pruning exercise and acceleration of cash flow.

Got you. Okay. I think that's all for me. Thanks.

(Operator Instructions)

Richard Tullis.

Tracy, could you give us an outline of the timing for the resumption of the curtailed production?

Yes, we expect to have at least half of it back on before the end of the year. The biggest outlier is Wrigley, which goes to the Cognac platform that Shell operates. They've got the entire structure shut down. This isn't a well issue with Wrigley; this is a host platform issue at Cognac. They're telling us it'll be first quarter of next year before they'll have the platform up. They've got some remediation work to do on the platform. That was one of the largest platforms ever put out in the Gulf of Mexico. It's got about 60 wells on it. They've got some remediation work they need to do on the structure.

So half online by year end expected?

I think that's a reasonable expectation.

And then the other half, say, first quarter or first half of next year?

That's what we hope. We don't get to drive that. That's in our guidance now. The way I presented it to you is in our guidance now.

Okay. Then lastly, on Troubadour, what's the pre-drill cost and reserves estimate on that one?

I don't think we've ever given that out, Richard, so I'm just not going to do that at this point. Since we are not operating on that, I would leave that more to the operator, who is Noble.

Okay. All right, that's all I have. Thank you.

I'm showing no further questions at this time. I'd now like to turn the call back over to Mr. Krohn for closing remarks.

Great, we're done. We appreciate your attendance. Thank you very much, and we'll talk to you soon.

Ladies and gentlemen, that does conclude the W&T Offshore second-quarter earnings conference call. If you would like to listen to a replay of today's conference, please dial 1-303-590-3030 with the access code of 4628422. We'd like to thank you for your participation. You may now disconnect.