W&T Offshore, Inc. (WTI) Q2 2013 Earnings Report, Transcript and Summary

Good day, 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, 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 a few items I'd like to point out. If you wish to listen to a replay of today's call, it will be available in a few hours via webcast by going to the Investor Relations section of the company's website at www.wtoffshore.com or via recorded replay until August 15, 2013. To use the replay feature, call area code (303) 590-3030 and dial the pass code 4628422#. The 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'd like to turn the call over to Mr. 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 on 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 proved reserves into significant cash flow. So we're turning reserves into money. The success of our organic growth program has been driven by the strategic initiatives we have implemented over the last few years. We've been adding staff, realigning teams, refining our incentive programs. We're focused on seismic data analysis, and we've acquired new leasehold. We're also evaluating joint venture opportunities, and we continue to identify additional opportunities along those lines. We have increased the oil content of our total production to 40% in the second quarter, up from 33% in the second quarter of 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 haven'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've 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 million cubic feet equivalent 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 online 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 will reflect nicely in our expected revenues as well. Remember, the guidance includes 2.5 BCF equivalent of downtime 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 2 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 FERC-regulated rate cases. So let's move on to operations. On the shelf in the Gulf of Mexico, we've continued to be very active at our Mahogany Field at Ship Shoal 349. As we recently announced, during July, we made a subsalt discovery in a deep shelf exploratory target that exceeded our expectations. The A-14 well had an initial production rate from the targeted P-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's 3,310 BOE per day net. And subsequently, that well has a reached 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 6 -- 4,644 BOE per day gross or 3,870 BOE per day net. That well is 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. The well has a high quality of oil sands, which haven't previously been discovered, as it logged pay in the M, N and O sands, all of which represent 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 sand -- excuse me, 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. So currently, the platform rig in 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 September -- early September at an estimated net rate of 1,000 barrels of oil equivalent per day. Following that A-4 recomplete, we expect to spud the A-15, another deep shelf subsalt exploratory well, which targets oil sands in 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. 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 will derisk a number of additional locations in the field and provide us with significant unrisked reserve potential. Mahogany has low-risk upside drilling opportunities with 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 oilfield just continues to grow in both its aerial footprint, as well as in vertical column and number of productive sand intervals. Every time we get new data, we find additional reserves in the field. We haven't defined the limits of this field, and that's really cool. At our Main Pass 108 field, we have 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. So 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 initial production rate 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 a Lentic 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 oilfield, and this project has targeted resource potential of 1.1 million barrels of oil equivalent. In regards to our development projects on this shelf, our High Island 21 A-1 development well was a success. First production is expected in late third quarter or early fourth quarter. Well encountered LH-20 main pay sands largely as expected, and as upside had also penetrated additional pay zones, 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 at 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, 2 wells will likely be codeveloped. We have a 20% interest in both wells. Big Bend discovered oil sands with high-quality reservoir properties that include characteristics which we were looking forward to getting the results on Troubadour. We continue to achieve excellent results on 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 log revealed 220 feet of net pay in the wellbore. The log pay was well in excess of our predrill expectations and is one of the biggest A sand intervals in the field. So we're going to produce the A-5 for a period of time, then expect to resume the original plan and utilize the well to assist with our field pressure maintenance program. Completion operations are underway, and we expect first production in early fourth quarter. So a nice surprise there as well. Moving to onshore drilling activity. In West Texas, we continue with our current 2-rig drilling program at Yellow Rose. We completed 9 wells in the second quarter, of which 2 are horizontal and 7 are vertical. We have 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 was 4,387 net BOE per day. We have continued to drill some of our vertical wells on 40-acre spacing and have found their performance is consistent with the type curves seen in the offset 80-acre wells on our Yellow Rose acreage. We booked reserves for approximately 50 PUD locations on 40-acre spacing, which represents only a small portion of our total potential 40-acre downspacing well locations. Further upside for 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 6 completed horizontal wells have targeted the Wolfcamp A formation. As we stated previously, we've been testing this formation with varied results, and we'll continue to refine target depth, optimize our specific completion techniques and lateral lengths 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 in the area. 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%, and 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 4 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 is very active. We are reviewing a lot of interesting asset packages, but we're going to remain selective. As we've mentioned during the last call, we do have some of our offshore shelf assets on the market. 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. So 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. So with that operator, we'll open up the phone lines for questions.

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

Say, Tracy, I want to make sure I understand. After the big fun you had on that Ship Shoal 349, Mahogany Field, I know you mentioned in the press release a number of other potential zones. I guess what I'm also trying to get a handle of, just in that P-Sand around in that field, is there numerous other well opportunities? Or 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 is yes. There are other opportunities in the P-Sand. We -- I mean, we could actually just drill an acceleration well for the P-Sand because this existing P-Sand is going to be there for a while. But fortunately, we also have some other sands in between the target sand, in the P-Sand and the T-Sand.

Okay. And then just one follow-up. Moving over onshore. You obviously had a lot of opportunity either through the downspace -- vertical downspacing or the horizontal. Will you continue -- I'm not sure if you know at this point. Would you continue with the 2 rigs going after all of that? Or if you see an opportunity that the horizontals continue to work or that the 40 acres downspacing works, would you add a rig sooner rather than -- another rigs sooner rather than later?

You're right. We are evaluating that right now. And of course, oil prices have a lot to do with that, Neal. We see multiple benches in the field, and 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. And you're right, we haven't made any decisions along those lines yet, but we're certainly in that period of time in the year which we start formulating those plans.

Our your next question is from the line of Michael Glick with Johnson Rice. Michael A. Glick - Johnson Rice & Company, L.L.C., Research Division: Just a question again on Mahogany. I mean, given kind of the seemingly large amount of opportunities out there, is there any possibility to add a second rig? I mean, I know you have a platform rig. But could you add another rig out there?

Yes. It's in fairly Deepwater. It's in about 500 feet of water. So we originally started out with a 3-well program. We're on -- gosh, we've held the rig now for about another year. So -- and 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 jackup, and I think we're better off, on an IRR basis, of maintaining just one rig in this particular field, yes. Michael A. Glick - Johnson Rice & Company, L.L.C., Research Division: Okay. And then just in terms of your undeveloped deepwater blocks, is there any 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? Michael A. Glick - Johnson Rice & Company, L.L.C., Research Division: No, just your undeveloped W&T operating leasehold that you kind of acquired 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. One thing I should point out is that the Troubadour was our other budgeted well. So that's the block adjacent to it, the Troubadour.

[Operator Instructions] Our next question is from the line of Richard Tullis with Capital One Southcoast.

Getting back to the subsalt discovery, what was the drilling, 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 predrill was around 3 million or so if I remember correctly, but it sounds like it's above that.

Yes, 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 the 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. And do you see additional subsalt potential on your acreage, particularly on the shelf where it hasn't been really drilled that much over the years?

Yes.

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

Yes.

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

Tracy, I was wondering if you could give us the forecasted production rates on those 2 large workovers that bumped up the LOE expense in the quarter.

Yes, that would be about 30 million a day. That's over -- I'm sorry, yes, 25 million, excuse me, net. That's over in Fairview -- Fairway, excuse me, Fairway.

And then coming onshore, at Yellow Rose, and I don't know, maybe a little 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?

Man, I really -- I haven't thought of it through to that point. We need to get some beta 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. But we're also looking at other benches in that same area. So we're -- 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.

And would you be able to tell me where the county is that this initial one is going to go down in?

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

Our next question is from the line of Noel Parks with Ladenburg Thalmann. Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division: Pardon me. You may have touched on this already. I got on a little bit late. But for the shelf properties you're looking at divesting, could 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 have appeal to you from an acquisition standpoint? Just tell us anything about other type of assets that you might effectively trade for something.

That's a little bit of a nebulous question. Let me see if I can break it down for you. We've got 3 individual regions in the Gulf, East, West and Central, and we're offering properties from all 3 of those areas. We are -- we have not included Mahogany in any of that equation, if that helps clarify that for you. Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division: Sure. Let me see. I guess I had tended to think of W&T as being a little bit more, as I said, the consolidator of Gulf assets and as opposed to as interested in selling.

Okay. Well, let me address that for you a little bit. I mean, we've sold properties in the Gulf many times. In fact, we sold some last year into -- I think it was EPL. And so the idea of selling properties -- I mean, any of those properties are for sale every day, Noel, for the right price. But as a private company, we sold assets all the time, and that was part of our regular business strategy. We'd get the debt up a little bit and then we get the production up and then we sell properties and we would put the money back in the ground. Nothing different here. We'll dense up a little bit. We'll sell some properties. We'll put it back, we'll pay down debt. We'll put the money back in the ground. It's more of a pruning exercise and acceleration of cash flow.

[Operator Instructions] Our your next question is a follow-up from the line of 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 in a well issue with Wrigley. This is a host platform issue at Cognac. They're telling us it will be first quarter of next year when 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 this structure.

So half online by year-end expected in...

I think that's a reasonable expectation.

And then the other half, say, first quarter, 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. And then just lastly, on Troubadour, what's the predrill 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're not operating on that, I would leave that more to the operator who is Noble.

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. We will talk to you soon.

Ladies and gentlemen, that does conclude the W&T Offshore second quarter Earnings Conference Call. We'd like to thank you for your participation. You may now disconnect.