W&T Offshore, Inc. (WTI) Q2 2015 Earnings Report, Transcript and Summary

Greetings and welcome to the W&T Offshore Second Quarter 2015 Earnings Conference Call. At this time, all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation. [Operator Instructions] As a reminder, this teleconference is being recorded. I would now like to turn the conference over to your host, Ms. Lisa Elliott. Thank you. Please go ahead.

Thank you, operator, and good morning, everyone. We appreciate you joining us for W&T Offshore’s conference call to review the second quarter 2015 financial results and for an operational update. Before I turn the call over to the company, I have a few items that I’d like to point out. If you wish to listen to a replay of today’s call, it will be available in 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 13. To use the replay feature, call 201-612-7415 and dial the passcode 13613143. Information reported on this call speaks only as of today, August 6, 2015 and therefore time sensitive information may no longer be accurate as of the date of any replay. Please refer to the second quarter 2015 financial results announcement we released yesterday for disclosure on forward-looking statements. At this time, I’d like to turn the call over to Mr. Tracy Krohn, W&T’s Chairman and CEO.

Thanks, Lisa. Good morning, everyone. Thanks again for joining us for our second quarter 2015 conference call. Joining me this morning is Jamie Vazquez, our President; Danny Gibbons, our Chief Financial Officer; Tom Murphy, our Chief Operations Officer; and Steve Schroeder, our Chief Technical Officer. As is our practice, we’ll focus our prepared remarks on providing an update on our key operations. After my remarks, we’ll take questions. Hopefully you’ve had a chance to review the detailed financials and operations data in the news release we put out yesterday evening. And as a side note, we do expect to file our second quarter Form 10-Q sometimes this afternoon. Operationally, we had a strong quarter with several substantial deepwater drilling successes. Now, we can just get commodity prices cooperate a little bit. Our second quarter production came in towards the top end of our guidance range for production but well below guidance on expenses. Production for the quarter averaged approximately 46,500 barrels of oil equivalent per day on lower downtime and better well performance than planned. Lease operating expenses were well below guidance as we saw operating cost decline faster than what we were seeing earlier in the year. We’ve completed two new wells in our Medusa field and a new well on our Ewing Banks 910 field. These wells should helps us maintain production in third quarter and then ramp up as our major deepwater projects at Big Bend and Dantzler come on line in the fourth quarter. So our third quarter guidance includes allowances for potential storing downtime. So, third quarter production could be better than guidance if we have a quiet storm season like the last couple of years. We expect to end the year with a higher exit rate, as we bring on Big Bend sometime early fourth quarter and Dantzler by year-end 2015. We expect our fourth quarter 2015 production volumes to exceed third quarter volumes and our 2015 exit rate to be well above any volumes levels we have seen in the few years. This is possible despite the sharp reduction in our 2015 CapEx plan as we complete projects that have been in the works but had not contributed to production. Thus, the forward spend is now gaining some real visibility for the fourth quarter, kind of like a football game where you win in the fourth quarter. So, we continue to focus on oil projects. Our second quarter oil production increased almost 3% compared to last year while natural gas and natural gas liquids production decreased. Revenues in the second quarter were better than expected $149 million with about 78% of that coming from oil and natural gas liquids production. Oil and liquids made up about 55% of our total production in the second quarter and that percentage will continue to grow with our new projects that will be coming on line. Our average realized sales price for the second quarter was $34.83 per barrel of oil equivalent or $5.81 per Mcfe. Adjusted EBITDA for the second quarter was $79.7 million and our adjusted EBITDA margin was 53%. Although this is much better than the adjusted EBITDA margin of 38% we saw in the first quarter, it is still low compared to our historical levels for the industry. Cost of goods and services have come down but will need to continue to decline in this current commodity price environment before we or others in the industry resume normal operations. Controlling costs to manage margins is critical at this commodity price level. Our employees are very focused on cost control measures and continue to work with our service providers to reduce costs. Our lease operating expenses or LOE declined 27% in the second quarter compared to last year. The decline was primarily in base LOEs. We saw decline in almost every category including fuel transportation contract services and labor. Our LOE guidance for the third quarter is based on increased workover activity at a number of offshore projects. Those also could come in lower than we currently anticipate. In regard to our 2015 capital budget, 75% of which has already been spent, our capital expenditures are directed towards high value projects that are expected to contribute significantly to future production, proved reserves. That’s that forward trend I was talking about. These are projects targeting substantial oil reserves and in the case Medusa and Ewing Banks 910 projects for which a new or existing infrastructure can be brought on line quickly. So far this year, our project results have exceeded our expectations and we are bringing on line some outstanding wells in 2015. During our last quarter call, we discussed several projects that were still being completed or just ramping up. So, I would like to give you an update on those projects. At Mississippi Canyon 538, the Medusa field, we now have both the subsea number 6 and number 7 wells on production. The subsea number 6 well found approximately 180 feet of net pay and established a peak IP rate of over 9,200 barrels of oil equivalent per day in May. The subsea number 7 well which encountered over 140 feet of net pay was completed and put on production at a peak IP rate of over 8,300 barrels of oil equivalent per day in June. Both the SS number 6 and the SS number 7 are excellent wells which we increased the total field production to almost 21,000 barrels oil equivalent per day gross and more than 3,000 barrels oil equivalent per day net to our 15% interest. This production is 85% crude. Both wells have more than one productive zone and are currently producing from their respective upper sand completions. The two wells have completed using a smart completion technology -- technique which allows us to remotely change producer [ph] zones in the future. That way we can bring our second completions in each of these wells into production at relatively no additional cost. These two exploratory wells are part of an expansion program going on in the Medusa field which is targeting multiple stacked oil sands. Along with our partners, we are continuing to evaluate further drilling opportunities within the field. These latest discoveries expand the scope of the field and are excited about possible next steps. So during July, we brought on line our South Timbalier 320 A-5 Sidetrack discovery well which is part of the Ewing Banks 910 field. Well logged 160 feet of net pay in the two zones and was completed in June. The A-5 well reached an early IP rate of approximately 2,700 barrels oil equivalent per day gross with 1,350 barrels oil equivalent per day net to our working interest. In early July, drilling commenced on the Ewing Banks 954 A-8 which is the second well to Ewing Banks 910 program. We intend to have a well on production by the end of year. The A-8 well is targeting a deeper exploratory sand in the producing interval from the A-5 sidetrack well. Based on seismic data, this well has a potential for a larger impact on reserves than what was encountered by the A-5 sidetrack well. Depending upon the outcome of the A-8 well, a third well could follow in the future. So, the Ship Shoal 359 A-14 T-sand well simulation work performed in May has increased oil production for the well approximately 37%. That increases the production rate from 2,850 barrels oil equivalent per day to 3,908 barrels oil equivalent per day current. Continued strong performance from reservoir should result in new reserve additions for this year. Every year we are seeing, gaining more reserves from this particular sand. In the high new [ph] fields in which we have a 100% working interest, continues to be a great field for us producing well over 9,000 barrel oil equivalent per day. In addition to that the water-flood project initiated at Matterhorn last year came in to exceed our expectations. Production from the tech point [ph] well continues at around 1,400 barrels of oil equivalent per day up from around 200 barrels of oil equivalent per day before the water-flood. That project success has helped us to validate our expectations for field wide expansion which we expect to undertake on the western side of the field in a much larger reservoir. This project hopefully will be undertaken next year. The development of our Big Bend and Dantzler discoveries are progressing well. And as we mentioned in an updated news release, we now expect to bring the Big Bend field on production during the fourth quarter and the Dantzler by the end of the year. We are expecting combined production from Big Bend and Dantzler to reach in excess of 8,000 barrels of oil equivalent per day net to our interest. Production is expected to be about 81% oil. So, as a quick update on our Yellow Rose field in the Permian Basin, we didn’t drill or complete any new wells in the field in the second quarter. However, nearby offset activity, well performance continues to be very strong with Wolfcamp B and Lower Spraberry formations. Our key Lower Spraberry Shale horizontal well continues to perform at levels indicating a 1 million barrel estimated ultimate recovery or EUR. This continues to be a great well and a great reservoir horizon. In fact some analysts are saying with lower spread rate, play is quickly becoming one of the most economic oil plays in the U.S. With over 90% of approximately 26,000 highly contiguous net acres in the basin held by production, we have the opportunity and the luxury to continue to let offset operators spend their capital to de-risk more of our acreage, demonstrate productivity of our target formations. Thus with decades of operating experience in the Gulf of Mexico we have demonstrated, we know how to identify projects that will be successful and profitable. Certainly the projects that we have pursued over the last several years have proven that. Deepwater wells that are bringing on line later in 2015 at Bid Bend and Dantzler are expected to be world-class and could bring our overall deepwater production to over 28,000 barrels oil equivalent per day. We also have some other great producing assets in our portfolio that have added really great value over the last few years to development, exploration and field optimization such as Mahogany and Matterhorn. Thus in these so called bed times, we tend to excel. With our 2015 capital expenditure dropping in the back half of the year, we expect to generate more positive cash flow. We can’t control commodity prices but with great assets and strong operations and decades of experience, we can control what opportunities to pursue and how to successfully manage those opportunities. I guess that concludes my prepared remarks. Operator, with that, we can open the phone lines for questions.

Thank you. [Operator Instructions] Our first question comes from the line of Neal Dingmann with SunTrust. Please go ahead with your question.

Tracy, a quick question. Obviously we have seen -- continue to see despite the environment, big prices in the Perm. Does that change your thinking at all about what you might do with that property or maybe if you could just discuss thoughts on that when you look at returns there versus your offshore returns?

Well I think one of the things that it indicates is that the market doesn’t really look at as the parts versus the whole. The parts clearly work more than the whole. I mean we are seeing acres prices in the area that we are at $34,000 an acre. So, if you multiply that times 26,000, I gets to be a pretty large number. Having said that, yes, we are spending most of our money in the deepwater right now. So, we’ve got a pool of money that’s dedicated to that as we get those wells on line and then we will start looking at doing more activity in West Texas.

And then Tracy, how do you think -- you certainly have the spill wells coming on late this year, let’s assume for a second, everybody talks about the lower, longer months [ph] out there. That does in fact is the case, how you think about in the 16 deepwater activity; I mean is it sort of compares to this year?

Yes, we are trying to grow a couple wells every year, explore exploration wells on the deepwater, that’s kind of our expectation in the near-term. So, I think that those are lined up even with our own projects as opposed to outside projects as well. So, I am pretty encouraged here. When prices go down, we tend to get a look at a lot of different projects that we wouldn’t normally get a look at. That doesn’t even begin to account for additional acquisitions.

Thank you. Our next question comes from the line of Noel Parks with Ladenburg Thalmann. Please proceed with your question.

I had a few things. At Matterhorn with water-flood, how long did it take to reach the current rate, 3,800 a day? What was the ramp up time on that?

The production is about 1,400 barrels oil equipment per day. Ramp up time on that was only two to three months.

And I was just wondering when you look at...

Let me interrupt you. I mean the reason it is so short is because the rock properties are so good.

And just as far as when you are looking at oil say -- your 45.50 versus more 55.60, how does that change the water-flood economics, if you look at doing similar projects starting new injection?

It changes the economics with time. The reason that we’re deferring on the western part of the field getting to work is because the tech point [ph] well is still making several 100 barrels of oil a day. So, we’ve got a location down depth to do the water-flood but the tech point [ph] well, the existing well in the reservoir is still doing quite well and it’s a big reservoir. So, that’s one of the things that has us excited is we’ve done the pilot project now. We would expect to see proved reserves in that reservoir to the west.

And one thing I was wondering is looking at the deepwater going forward and as your plan for the next year and the future beyond that, does the services cost environment make you feel any more comfortable as far as just the share of wells interested you might hang on to? I guess, I’m just thinking with this environment there might be some of your partners who might be staying on the sidelines instead of going forward?

We agree with you. The share that we are going to take, we’re still thinking about around 20% max. We could stretch that to maybe 25%, 30% in some cases but that’s kind of the thought process that we have right now. The good news of course is that it’s costing a lot less to drill these wells. The same rig that was going for $500,000 to $600,000 a day is now going for half of that. So drilling cost is starting to drop pretty rapidly. And as we’ve mentioned earlier in the year, normally takes about six to nine months to see some of the substantial cuts in operating costs and expenses for particularly the more tangible items. So, now we’re entering month eight, nine now. So, we’re really starting to see acceleration in the production of cost of getting to services.

And just one last one on the gas side. Could you just sort of refresh my memory? Where do you have your say lowest cost gas developed opportunities in the company at this point?

Well, gas development opportunities, again, most of that is still on the shelf is what we’ve been looking at. So, in anticipating your question of well, what we be the dollar amount you should have to have for gas to be able to go back and do those. Again, it’s a function of the reduction of the cost of goods and services. We’ve had very good success with our Fairway field as result of doing some pretty minor works. So drilling activity isn’t very good but we’ve extended the reserves over there just as a function of improving the compression and the plant over there, the plant that takes for gas. So that’s one of the places. The other places are around some of our larger domes deeper and on the shelf. We see potential for a lot of additional exploration now. We’ve bought a bunch more seismic. Some of that deeper stuff is going be gas. Obviously we prefer to focus on oil right now but now it’s starting to get the forward rig cost and cost of goods and services are dropping and now that we can start looking at larger gas price.

Our next question comes from the line of Patrick Rigamer with Seaport Global. Please proceed with your question.

I guess a question on the operating expenses, you saw a big drop quarter-over-quarter as you’re approaching the midway point of the third quarter here, commodity prices are lower than they were in the second quarter. Is there room for those operating expenses to continue to fall or what’s the market look like today?

I think, overall, you’ll see that assuming price of goods and cost of goods and services continue to drop like we’ve seen the last couple of months. A little bit of thought needs to go into the third quarter. Third quarter is when we do a lot of our work because the weather is actually pretty good. So, we’ll do a lot of platform maintenance and pipeline maintenance and painting and all the things that we need to do, work and stuff that we have to do to maintain these platforms well. So third quarter is usually little bit lumpy and again that’s a function of the weather too. Normally weather is pretty good but if we get a storm or two in there that could affect that as well. So expenditures are a little bit lumpy. We normally target expenditures a little bit more toward the third quarter. So, don’t be surprised if you see a little bit of increase or whatnot, depending upon what all we have to do. And we still haven’t changed guidance. I expect overall for the year to see guidance towards the low end, as a function of the lease operating costs and expenditures out to go.

And then I guess with Big Bend and Dantzler start to come on here around year-end, do you have an estimate on what kind of like the first year decline is on those assets?

My personal opinion is I don’t think you’ll see much of any decline on those on the first year. These are world-class oil reserves. We’re only getting a very small portion of the reserves booked as proved. So, these are very high octane wells, if you will. So, I don’t expect to see whole lot of decline.

Our next question comes from the line of Jeff Davies with TPH Asset Management. Please proceed with your question.

I can appreciate the lack of urgency on the Permian assets on the heels of the second lien deal but just trying to think philosophically how you think about leverage, liquidity your bonds are in the 50s at this point, what your thoughts on creating more liquidity for the company?

That’s funny that you said that bonds are in eh 50s at this point, because they’re not very liquid. So, anytime there is sale the value of the bonds go up very rapidly. But the way we think about West Texas is that those reserves have been there for millions of years, they’re not going anywhere. Technology continues to improve. We’re going to spend our money where we can get the highest cash flow rate of return. At this point in time, the West Texas is a much longer live play obviously and that’s one of things that gives us a good feeling about it. But the other good thing about it is that we continue to see our offset operators making improvements in their designs and proving up some of the zones for us. So for instance at Lower Spraberry we drilled a couple of wells and had very good success, but our offset operators are drilling a whole lot more wells. And now we’re starting to see other operators move into the area and paying premium prices for the acreage. So, we feel like the value of that asset continues to go up while we don’t have to spend any money on. And we can put our asset invest -- or our investments toward our deepwater field which is going to produce even higher rates of return. So that’s kind of how we look at it.

I guess to be more specific, the bonds yield 30% now, so is drilling -- there is Permian well and developing that play better choice and selling that asset and buying your debt back at 30% yield?

Short answer to that is yes.

Thank you. Our next question comes from the line of Richard Tullis with Capital One Securities. Please proceed with your question.

I just popped on a little bit ago, so I apologize if you’ve already covered this Tracy. Continuing with the liquidity themes of the last caller, Tracy, what is the preliminary outlook for the borrowing base redetermination, the 500 million base that you currently have?

That’s great question. I don’t have any answer to that at this point in time. We’re not scheduled to do our redetermination until October. So, we’re little bit premature. If I could give you an answer to that, I would. But I don’t have any answer for that.

Do you think there is, given the current commodity environment, is there a descent risk of substantial cut or you think enough reserve bookings could be to offset the commodity decline?

I think the things that the banks look at is primary the proved producing reserves. We’ve got a lot of proved producing reserves coming on at the end of the year. And in fact, we expect we’ll have some of them on, but for this next bank meeting. So that will weigh heavily on what their thoughts are with regard to the borrowing base and then rest of it will just be price.

And then going back to reserves, Tracy, what do you expect you can book for Big Bend and Dantzler, say end of this year? And even looking out further into ‘16, do you think by year end ‘16 you will have been able to book proved reserves for the majority of the -- at least the estimated potential for those projects?

Normally the way it works because of the wage profiles in these wells, we only get credit for the portion of the reserves that has been contacted in the sand. Anything below that is usually booked as probable and possibles initially until you get continued production. So year one, I would expect to see a pretty dramatic increase. We won’t get all of it, year one. But year two, we will probably get most if not all but on proved producing side along with additional bookings on probables and possibles. I expect these wells to perform as world-class producers. We are -- that’s one of the reasons. We certainly didn’t drill it based on what the amount of proved reserves. I think the proved reserves are already illustrated in our -- some of our other press releases that the operators put out.

Okay. And you may have touched on this a little bit already but given the I guess the growing popularity and improved results in the Lower Spraberry and it’s certainly moved toward your part of the midland basin and you were in one of the -- you had working interest in one of the better Lower Spraberry wells drilled to-date. Any inclination to maybe monetize, at least part of your Permian properties? I know recent deals we have seen are still north of 30,000 per acre in the midland basin adjusting for production?

Yes. The short answer to that is yes. Any of our assets are for sale any day at the right price, Richard. So yes, we have had a lot of -- we have had a great deal of interest in those properties.

Thank you. [Operator Instructions]. Our next question comes from the line of Jon Evans with JWest. Please proceed with your question.

Thanks for taking my call, I appreciate it. Can you just talk a little about -- I don’t know if you have any initial thoughts but for CapEx next year, I mean the back half obviously is very light and you have been very prudent on waiting for cost to come down. But what’s your kind of initial thought for potentially CapEx next year?

We are looking at that right now Jon. We are in the midst of our budgeting process as we speak. I don’t really have a great feel for that at the moment. And we may not have a great feel for that until later on in the year when we get these wells on production and typically we announce the budget towards the end of January, early February. So it’s a little premature for us yet. But I am feeling pretty good about it. I mean we have got a lot of production coming on line. And we are not going to have to forward spend. So, I feel pretty good about it.

Thank you. Our next question comes from the line of Al Shams with American Capital Partners. Please proceed with your question.

I am a retail broker here in the Atlanta area and I follow the company off and on for four or five years and recently have been buying some of the stock. Can you share with me why we don’t see more insider buying in the company? I know that you have a large position. So, I wouldn’t necessarily expect you to add a lot more to your position but some of the other officers?

Yes. Al, first of all, thank you for being a shareholder, I do appreciate it. Second, understand that most of the insiders are normally in possession of material non-public information.

Okay.

I certainly, I am very restricted on when I can buy or sell shares most of the time. So, we are in and out of data rooms, we do a lot of acquisition work. We do a lot of drilling. So, if for instance we drill the well and I got a bunch of pay in it and I am not ready to make that announcement, I can’t go out and buy shares.

Right.

So, this is a normal occurrence. So when you talk about insiders, you are talking about Section 16 officers and Board of Directors. So that’s normally the case. So that’s why you don’t see a lot of it.

Okay. Following up on the other question where the individual asked about repurchase of bonds. I mean that would seem to be a very compelling purchase, maybe monetize some of your properties and repurchase some of that debt at a discount.

I agree.

Okay. So…

The issue is the question was how does that compare to our other rates of return?

Right.

And right now I would tell you that yes, I mean certainly if we were to sell something, first thing we do is pay our bank debt and then we would look at where we would reinvest the rest of the funds. So, we pay off the bank debt and get a lot of dry powder. And then my expectation is we get a better rate of return on doing acquisitions and drilling some of these other wells. That’s why we have the debt in the first place.

Okay. You feel comfortable with your liquidity situation as it is right now?

Yes.

Okay. Incidentally I was also with the old Humble Oil Company as a corporate auditor in the late 60s so.

Oh my gosh, one of our founders was with old Humble Oil Company, many, many years ago. He’s a geophysicist with them.

Okay, great, great. Well I am happy to be a part of the company and a shareholder and I have confidence in your abilities and your acumen.

Thank you very much, sir. I appreciate you called.

Thank you. Mr. Krohn at this time there are no further questions. I would like to turn the floor back to you for any final or concluding remarks.

I think that will do it today, operator. Stay tuned everyone. We think it’s getting better. Thanks so much. We will talk to you next time.

Thank you. Thank you for your participation. This concludes today’s call. You may disconnect your lines at this time.