W&T Offshore Inc (WTI) 2015 Q2 法說會逐字稿

Greetings and welcome to the W&T Offshore second quarter, 2015, earnings conference call.

(Operator Instructions)

As a reminder, this conference 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 a few hours via webcast by going to visit 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 pass code 13613143.

Information recorded 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 2000 (sic) financial results announcement we released yesterday for a disclosure on forward-looking statements.

At this time, I'd like to turn the call over to Mr. Tracy Krohn, W&T 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 financial 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 sometime this afternoon.

Operationally, we had a strong quarter with several substantial deep quarter drilling successes. Now, if we could just get commodity prices to cooperate a little bit. Our second quarter production came in towards the top end of our guidance range for production and well below guidance on expenses.

Production for the quarter averaged approximately 46,500 barrels of oil equivalent per day. A lower downtime and better well performance than planned. Lease operating expenses were well below guidance as we saw operating costs decline faster than what we were seeing earlier in the year.

We completed two new wells in our Medusa field and a new well at our Ewing Banks 910 field. These wells should help us maintain production in the third quarter, and then ramp up as our major deep quarter projects at Big Bend and Dantzler come online in the fourth quarter.

So our third quarter guidance includes allowances for potential storm 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 some time during the 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 volume levels we've seen in a 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 have 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 for 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 online. 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's still low compared to the historical levels for the industry. The costs of goods and service's have come down, but we'll need to continue to decline in this current commodity price environment before we or others in the industry resume normal operations.

Controlling cost 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 a 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 through our reserves. That's that forward spend I was talking about. These are projects targeting substantial oil reserves, and in the case of the Medusa and Ewing Banks 910 projects, which are near existing infrastructure that could be brought online quickly. So far this year, our project results have exceeded our expectations and we're bringing online 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'd like to give you an update on those projects.

At Mississippi Canyon 538, the Medusa field, we now have both the sub-sea number 6 and number 7 wells on production. The sub-sea number 6 well found approximately 180 feet of net pay and established a peak IP rate of 9,200 barrel oil equivalent per day in May. Sub-sea number 7 well, which encounter 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 have increased the total field production to almost 21,000 barrels of oil equivalent per day growth, for more than 3,000 barrels of 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 were completed using a smart completion technology technique, which allows us to remotely change producing 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're continuing to evaluate further drilling opportunities within the field. These latest discoveries expand the scope in the field and our excitement about possible next steps.

So, during July we brought online our South Timbalier 320 A-5 sidetrack discovery well, which is part of the Ewing Banks 910 field. The 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 of oil equivalent per day gross or 1,350 barrels of 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 in the Ewing Banks 910 program. We intend to have a well on production by the end of the year. The A-8 well is targeting a deeper exploratory sand than the producing interval from the A-5 sidetrack well.

Based on seismic data, this well has the 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 stimulation work performed in May has increased oil production for the well by approximately 37%. That increases the production rate from 2,850 barrels of oil equivalent per day to 3,908 barrels of oil equivalent per day currently. Continued strong performance from the reservoirs should result in new reserve additions for this year.

Every year, we seem to be gaining more reserves from this particular sand. The Mahogany fields in which we have 100% working interest, continues to be a great field for us producing well over 9,000 barrels of oil equivalent per day.

In addition to that, the waterfront project initiated at Matterhorn last year has continued to exceed our expectations. Production from the [take point] 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's 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 Dantzler field by the end of the year. We're 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 and well performance continues to be very strong for 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 the Lower Spraberry play is quickly becoming one of the most economic oil plays in the US. With over 90% of our approximately 26,000 highly contiguous net acres in the basin held by production, we have the opportunity and the luxury to continue to let offsite operators spend their capital to derisk more of our acreage, and demonstrate the productivity of our target formations. Thus with decades of operating experience in the Gulf of Mexico, we've 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 we were bringing online later in 2015 at Big Bend and Dantzler are expected to be world class, and could bring our overall deepwater production to over 28,000 barrels of 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 through development, exploration and field optimization such as Mahogany and Matterhorn.

Thus, in these so called 'bad times' we tend to excel. With our 2015 capital expenditures 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 continue to see, despite the environment, some 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 discuss thoughts on that when you look at returns there versus your offshore returns?

I think one of the things that it indicates is that the market doesn't really look at us as the parts versus the whole. The parts are clearly worth more than the whole. I mean, we're seeing acreage prices in the area that we're at $34,000 an acre. If you multiply that times 26,000, it gets to be a pretty large number.

Having said that, yes, we're 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 online, then we'll start looking at doing more activity in West Texas.

Then, Tracy, how do you think -- you certainly have a slew of wells coming on late this year. Let's assume for a second, everybody talks about the lower longer [montrap] there. If that does in fact is the case, how do you think about into 2016, deepwater activity as it compares to last year?

We're trying to drill a couple of wells every year, exploration wells out in the deepwater. That's 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'm pretty encouraged. 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.

Thanks, Tracy.

Thank you, sir.

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

Good morning.

Good morning, Noel.

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

Well, the production is about 1,400 barrels oil equivalent per day. Ramp-up time on that was only two to three months.

Okay, great. And I was just wondering, when you look --

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

Okay, great. And as far as when you're looking at oil, say, $45, $50, versus more like $55, $60.

Yes.

How does that change the water flood economics if you look at doing similar projects starting new injection?

Well, 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 take-point well is still making several hundred barrels of oil a day.

So we've got a location down dipped to do the water flood, but the take-point well, the existing well in the reservoir is still doing quite well. And it's a big reservoir. 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.

Great, great. One thing I was wondering is looking at the deepwater going forward, as you had planned for next year and the future beyond that, does the service cost environment make you feel any more comfortable as far as the share of a well of interest you might hang on to? I was just thinking, with this environment that there might be some of your partners who might be staying on the sidelines instead of going forward.

No, we agree with you. The share that we're 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 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, $600,000 a day is now going for half of that. Drilling costs are starting to drop pretty rapidly.

We'd mentioned earlier in the year, it 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 8, 9 now. So we're really starting to see an acceleration in the reduction of cost of goods and services.

Great. One last one. On the gas side, can you refresh my memory? Where do you have your lowest costs of gas development opportunities in the Company at this point?

Well, gas development opportunities, again, most of that is still on the shelf, is what we'd be looking at. So in anticipating your question of well, what would be the dollar amount that you'd 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 over at our Fairway Field as a result of doing some pretty minor work. 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 the gas. So that's one of the places.

The other places are around some of our larger domes, deeper. 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 to be gas. Obviously, we'd prefer to focus on oil right now. Now it's starting to get to the point where rig costs and costs of goods and services are dropping enough that we can start looking at larger gas plays.

Great, that's all for me. Thanks.

Thank you, sir.

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

Hi, good morning. Question on the operating expense. Saw a big drop quarter over quarter as we'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 in a year you'll see that, assuming price of goods and cost of goods and services continue to drop like we've seen in 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's 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, abandonment work and stuff that we have to do to maintain these platforms and wells.

So third quarter is usually a little bit lumpy. Again, that's a function of the weather, too. Normally, the 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 a increase or whatnot depending upon what all we have to do. We still haven't changed guidance. I expect overall for the year to see guidance toward the low end as a function of the lease operating costs and expenditures out in the Gulf.

Okay. Then with Big Bend and Dantzler set to come on here around year end, do you have an estimate on what the first-year decline is on those assets?

My personal opinion is I don't think you'll see much of any decline 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 a whole lot of decline.

Okay, great. Thank you very much.

Great.

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

Hello?

Mr. Davies, perhaps your line is muted on your end. You're live on the call.

Yes, thank you, I apologize. I can appreciate the lack of urgency on the Permian assets on the heels of the second lien deal. But trying to think philosophically how you think about leverage, liquidity. Your bonds are in the 50s at this point. What's your thoughts on creating more liquidity for the Company?

That's funny that you say the bonds are in the 50s at this point because they're not very liquid, so any time there's a sale, the value of the bonds go up very rapidly. 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 the things that gives us a good feeling about it.

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 these zones for us. For instance, the Lower Spraberry, we've 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 it. We can put our investments toward our deepwater field which is going to produce even higher rates of return. That's kind of how we look at it.

I guess to be more specific, the bonds yield 30% now. So is drilling those Permian wells and developing that play a better choice than selling that asset and buying your debt back at 30% yield?

The short answer to that is, yes.

Okay, thank you.

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

Thanks, good morning. I just hopped on a little bit ago, so I apologize if you already covered this, Tracy. Continuing with the liquidity theme of the last caller, Tracy, what's the preliminary outlook for the borrowing base redetermination, the $500 million base that you currently have?

That's a great question. I don't have an answer for that in this point in time. We're not scheduled to do our redetermination until October.

Okay.

So we're a little bit premature. If I could give you an answer to that I would, but I don't have an answer for that.

Do you think there's, given the current commodity environment, is there a decent risk of a substantial cut? Or do you think enough reserve bookings could be had to offset the commodity decline?

Well, I think the things that the bank look at is primarily prove-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 before this next bank meeting. So that'll weigh heavily on what their thoughts are with regard to the borrowing base and the rest of it will just be price.

Okay. Then going back to reserves, Tracy, what do you expect you could book for Big Bend, Dantzler, say, end of this year and even looking out further into 2016? Do you think by year-end 2016 you will have been able to book proved reserves for the majority of -- at least the estimated potential for those projects?

Normally, the way it works because of the wedge 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'll probably get most, if not all of it on the proved-producing side, along with additional bookings on probables and possibles. I expect these wells to perform as world-class producers.

That's one of the reasons -- we certainly didn't drill it based on what the amount of proved reserves are. I think the proved reserves are already illustrated in some of our other press releases that the operators put out.

Okay. You may have touched on this a little bit already. Given 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 a working interest in one of the better Lower Spraberry wells drilled to date. Any inclination to monetize at least part of your Permian properties? I know recent deals we've 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. Yes, we've had a great deal of interest in those properties.

Okay, that's all for me. Thank you, Tracy.

Sure, thank you.

Thank you.

(Operator Instructions)

Our next question comes from the line of John Evans with J West. Please proceed with your question.

Thanks for taking my call, I appreciate it.

Sure.

Can you talk a little bit about -- I don't know if you have any initial thoughts, but for CapEx next year. The back half obviously is very light and you've been very prudent on waiting for costs to come down. What's your initial thought for potentially CapEx next year?

We're looking at that right now, John, we're in the midst of our budgeting process as we speak. I don't really have a great feel for that at the moment. We may not have a great feel for that until later on in the year when we get these wells on production.

Typically, we announce the budget toward the end of January, early February. So it's a little premature for us yet, but I'm feeling pretty good about it. We've got a lot of production coming online. We're not going to have to forward spend so I feel pretty good about it.

Okay, great. Thank you for your time.

Thank you, sir.

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

Tracy, Good morning.

Good morning, sir.

I'm a retail broker here in the Atlanta area and I've followed 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 to you add a lot more to your position, but some of the other officers.

Well, 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 am. I'm very restricted on when I can buy or sell shares most of the time. So we're in and out of data rooms. We do a lot of acquisition work. We do a lot of drilling.

So if, for instance, we've drilled a well and I've got a bunch of pay in it and I'm not ready to make that announcement, I can't go out and buy shares.

Right.

This is a normal occurrence. When you talk about insiders, you are talking Section 16 officers and Board of Directors. So that's normally the case. 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, 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 that you yes, yes, certainly if we were to sell something, the first thing we'd do is pay off bank debt. Then we would look at where we would reinvest the rest of the funds.

So we'd pay off the bank debt, 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 1960s.

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

Great. Okay, I'm happy to be a part of the Company and a shareholder. I have great confidence in your abilities and your acumen.

Thank you very much, sir, appreciate your call.

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 concluding remarks.

That'll do it today, operator. Stay tuned, everyone. We think it's getting better. Thanks so much. We'll 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.