W&T Offshore, Inc. (WTI) Q1 2015 Earnings Report, Transcript and Summary

Greetings and welcome to the W&T Offshore First Quarter Earnings Conference Call. At this time, all participants are in a listen-only mode. A brief 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. Ms. Elliott, you may being.

Thank you, operator, and good morning, everyone. We appreciate you joining us for W&T Offshore’s conference call to review results for the first quarter of 2015. Before I turn the call over to the company, 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 May 14. To use the replay feature, call 201-612-7415 and dial the passcode 13608155. Information reported on this call speaks only as of today, May 7, 2015 and therefore time sensitive information may no longer be accurate as of the date of any replay. Please refer to our first quarter 2015 earnings 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 for joining us for our first quarter 2015 conference call. We will review of financial results and provide you with an operational update. 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. Hopefully you got a chance to review the detailed news release we put out yesterday evening. This morning we'll primarily focus on key operations, and take questions. As you can see from the release, our operating results for the quarter came in as expected, with production just at the midpoint of our guidance, and operating expenses falling a bit below the midpoint. We produced an average of 48,800 barrels of oil equivalent per day in the first quarter, and that's up 0.8% from production in the first quarter last year. And that was on a 9.4% increase in crude oil production, offset by lower natural gas and NGL production. As you know, our focus has been on increasing crude oil production, and we are clearly succeeding in that phase of the business. We expect that crude oil production will increase further this year and into next year. We'll have deepwater production coming online later this year and into next year. Production during the year is expected to be a little lumpy, with planned pipeline outages and platform maintenance. Back-half of the year will benefit from new projects coming online that will drive oil production higher. Those projects are in various stages of drilling, completing, are being hooked up to existing production facilities. Similarly, LOE, lease operating expenses, will be lumpy as usual. And in the second quarter, we will have increased work-over activity and greater facilities work. Based LOE will actually be down, with the continued downward pressure on cost. Nonetheless, full-year guidance remains unchanged. So during the first quarter, we completed the first of two new subsea wells at Medusa in Mississippi Canyon Block 538. The first well, Subsea No. 6, was recently put online and is still ramping up. The Subsea No. 7 is being completed as we speak today, and should be online within the second quarter. These exploratory wells are part of an expansion program going on in that field. This deepwater field currently produces about 4,500 barrels of oil per day gross to Medusa's spar, which is the host production facility. We have a 15% working interest in Medusa. Production is about 85% crude oil, and these two wells, which were drilled in the first half of 2015, targeted multiple stacked oil sands. The first, the Subsea No. 6, found approximately 180 feet of net pay. And the second well, the Subsea No. 7, encountered approximately 140 feet of pay. Both wells are expected to be completed as dual-zone smart completions. At our Ewing Bank 910 field, we're currently drilling the A-5 sidetrack exploratory well, which should come online late in the second quarter. The estimated initial rate for the A-5 sidetrack is expected to be approximately 3,075 barrels oil equivalent per day net to WT, which is currently anticipated to be about 80% oil. The other operator Ewing Bank 910, we have a 50% working interest. Following the A-5 sidetrack, we likely will commence drilling the A-8, and be at the objective of the well in the fourth quarter this year. Based on high-quality seismic, the A-8 looks like it's very promising, and bigger targets than the A-5 sidetrack. Depending upon the outcome, the A-8 third well could follow. So of course, later in the year, we expect to bring Mississippi Canyon 698 Big Bend online. And Mississippi Canyon 782 Dantzler should be brought online within a couple of months of that. The second well at Dantzler was completed here in the second quarter. All three wells related to this development are now complete and ready for subsea installation hookup. The development work to connect Big Bend and the two Dantzler wells to the nearby Thunder Hawk platform is ongoing and on schedule, with three installation vessels currently in the field. The anticipated combined production rate for both Big Bend and Dantzler is expected to reach in excess of 8,000 barrels per day net to our interest. We estimate that production will be between 80% and 85% oil. So let me move on to another successful ongoing project that we began at Mississippi Canyon 243 Matterhorn. If you'll recall, we drilled the A-# well there last year as a water injection well. Screwed up [ph], found excellent pay in the well, purposely produced a flux [ph] well for about eight months, an early initial rate in excess of 1,000 barrels of oil per day. We then converted the well into a water injection well in September 2014, with the sole purpose of increasing the production from the A-2 well through pressure maintenance and a single-pump water flood into the A sand reservoir. So by mid-December, the A-2 well started showing a strong response. Production from the A-2 well has steadily increased from about a 300 barrels of oil per day to its current rate of over 1,400 barrels of oil equivalent per day and it's still climbing. Needless to say, the water flood and field pressure maintenance program is working very well. In the future, we expect to expand this type of program to the western flank of the field. And we think the results will be much better, as the original oil-in-place estimates are considerably larger in this other reservoir. By the way, we have 100% working interest in Matterhorn. As always, we will advance key re-completion projects that can expand our production rate at relatively low costs. And there's several wells that we have the ability to do that with. So let me discuss our onshore operations for moment. In the first quarter, at our Yellow Rose field in the Permian Basin, we completed two previously drilled horizontal wells and two vertical wells. Rates for the vertical well, the UL 7-19 4, was 164 barrels of oil equivalent per day. And the UL 7-19 5 was 213 barrels of oil equivalent per day. The horizontal wells are still cleaning up. As of the end of March 2015, we had two vertical wells and four horizontal wells awaiting completion at Yellow Rose. And at this time, we've temporarily suspended new drilling activity in our Yellow Rose field. Fortunately, over 90% of our Yellow Rose acreage is held by production. So we're not at risk of losing the acreage, and we have a lot of flexibility as to when to resume drilling operations. We have the ability to wait until the cost of goods and services move better in line with a lower commodity price environment. So while our operating results came in as expected, our financial results were heavily impacted by the sharp price decline. We significantly drove down our EBITDA and EBITDA margin that caused us even to have a write-down. That said, we're actively working with our service providers to bring down costs. We've seen a good response, but still not enough. We believe they need to move down further to get the margins back to historical levels. We've been operating for over 30 years in the Gulf of Mexico, and we're typically able to maintain annual EBITDA margins around 60% in many different commodity pricing climates. So in April, we announced that our amended – excuse me, we amended our existing back-revolving credit facility, and modified certain covenants to enhance our financial flexibility. We outlined that in a cover report on Form 8-K that we filed with the SEC. As a result of the April 15 semi-annual re-determination, the borrowing basing the bank credit facility was re-set as $600 million. On May 2015, we announced the pricing and marketing of the $300 million five-year second-lien term loan, baring interest at an annual rate of 9%, with an original issue discount to par at 99. Net proceeds will be used to repay a portion of the outstanding borrowings under the revolver. And upon issuance of the term loan, the borrowing base of the revolver facility will be reduced from $600 million to $500 million. The lender commitments in completion of the term loan are subject to negotiation approval and execution of definitive loan documentation. That's near-term, by the way. Details of the term loan agreement will be available in a few days, post closing of the transaction via a current report on Form 8-K that we will file with the SEC. Pro forma for this new issue, as of March 31, 2015, our liquidity under the borrowing base, plus cash, would've been about $285 million. We believe these recent actions provide us with enhanced liquidity and financial flexibility to execute our capital plan, as we work to return our EBITDA margins to more normal levels. Projects in progress will enhance future production and more cash flow. As we mentioned in our press release, the capital expenditure program is front-end loaded this year, with 80% of our planned capital expenditures for the year occurring in the first half of 2015. And all of our capital for the last three quarters of 2015 is focused on the deepwater. And so with that, operator, we're ready to take questions.

Thank you. We will now be conducting a question-and-answer session. [Operator Instructions] Our first question is from Neal Dingmann with SunTrust. You may proceed.

Good morning, Tracy.

Good morning, Neal.

Tracy, obviously, you made the comment about some of your new exploration, just kind of putting that on hold. I guess what's your thoughts between going out offshore and looking for M&A versus your inventory that you have now? You have, to me, appears to a pretty deep inventory. But are you always looking for more M&A for the right price? Or how should you think about adding to offshore inventory?

I've always looked to M&A for the right price, for three decades. So the answer to that is clearly, yes. Neal, realistically, we get back to work when the margins get to be around 60%. So that can be accomplished in three different ways. One, it's a reduction in cost, or of course, two, an increase in revenues, or both. So, as soon as we get to those margins, we'll know. Not only dollars will be less if pricing is less, of course, but the margins we expect to be the same when we're ready to get back to work. So that's the challenge, and that's what happens in these environments where you have steep price declines for any length of time. We're prepared for that. And that was one of the reasons, of course, why we went out and shored up the borrowing base with the second lien.

Makes sense. And just my one other one. I know you've all said anything, for the right price, is for sale. But again, you're certainly – not just your own, but seeing a lot of peer additional activity and success around your onshore, now, wells and just wondering how actively, I mean, are you looking to shop that? Is that something that just depends on the returns that you are seeing versus offshore? I'm just wondering, again, potential of selling that anytime soon?

We have a lot of activity around people that have come to us wanting to buy, but we're not actively out soliciting. But they're beating on the doors to talk to us about it. Talk is pretty cheap, so we'll talk to just about anyone. But the reason for that is that late in the year, and early this year, we proved up the horizontal case. And that was the intent. And we knew it was going to take 15 wells to 20 wells horizontal to get to that point, with the last well being about 1,700 barrels a day equivalent. So that's spurred a lot of interest in the area. We think we're sitting on a pretty good, fat, juicy piece of it. So we are getting a lot of interest in it.

Perfect. Thanks, Tracy.

Thank you.

[Operator Instructions]

All right, still waiting on somebody here. Mr. Parks? Are you there?

Oh, yes, sorry. I didn’t hear my name called. Just a couple questions. With the Ewing bank 910 field, the role of the improved seismic, had you guys really talked about that before? You mentioned it in the release today.

I don’t know – I know we’ve mentioned it in the past with regard to the Gulf of Mexico. I mean one of the things that we always benefit from is better seismic. So whenever we get a better piece of seismic in any area, it enhances our ability to find hydrocarbons. And Ewing 910 is certainly one of those areas.

And just to give me a sense, what era – or how long ago did you get the updated seismic?

It's been within the last two years. I don't know exactly, but say within the last two years. And of course, when you get this data, you have to process it in a different way so we do processing in-house. So it just enhances our ability to image these formations.

Right. And with the – of course, your CapEx is pretty modest for second half of the year. But looking further out, with the softness we've seen in prices in your deepwater portfolios, is there anything on the non-operated side that at this point has been delayed substantially, looking out into the next couple of years?

Negative. Nothing's been delayed. And of course, the reason we're a little soft on the CapEx side in the second half of the year is because we spent a lot in the first half of the year.

Right.

Yes.

And just a thought on hedging? I know it's something you've talked about in the past. With oil strengthening a bit, but really most of the strength being the spot in the near-months, so we just have a futures curve that's gotten fairly flat. Does that make you think any more about locking in some of the future pricing? Or would you only want to do that if you saw a nice deep contango you didn't think would be sustained?

Actually, we are looking at hedging some of this stuff going forward. I think we can do that without much risk to the upside. We're clearly biased toward the thought that prices do recover over time. So we would want to be more focused on making sure we covered our borrowing base on the downside. And I think we can do that just about any time.

Great. And do you have a sense of what percentage you might be looking at – percentage of your total oil production?

We never hedge more than about 50% or so.

Okay, great. That's all for me.

Thanks.

Our next question is with Michael Glick with Johnson Rice.

Good morning. Just on Big Bend and Dantzler, what sort of ramp-up period should we expect from those fields, from when they come on, to peak production?

I’m sorry. There was some external noise here in the room. I didn't hear your question. Would you repeat it, please?

What sort of ramp-up period should we expect for the Big Bend and Dantzler fields, from first production to peak production?

I think probably not more than about 2 months.

Got you. And as far as your guidance is concerned, is there much contribution in there for Dantzler?

No, there isn't.

Okay, all right. That's all for me. Thank you.

Okay.

[Operator Instructions] Our next question is from Tom Nowak at Avant Capital.

Hi, good morning.

Good morning.

Just back on the Permian, you mentioned there's a lot of interest. At what point do you formalize that, and make those parties compete against each other and put their best offer forward? Is that going to be based on the oil curve? Is there some threshold at which you make that more formal?

A threshold? I'm not sure I understand your question, sir.

Is there a price level – is there a point on the futures curve, when the futures strip and some level…

If we are going to sell it, we're going to try to get the best price we can. I don't know that it's dependent upon the futures curve.

Right. Well, I'm just saying, since there's a number of interested parties already, why not go forward and formalize that, and make them compete against each other now and put their best offers forward?

I really appreciate the idea that we would need to have a formal process. It doesn't need to be formal or informal. It could be either one. Like I said, we're not out soliciting; it’s coming to us. And I think that's probably a very good sign, and a better way to do it.

Okay. Thanks.

Sure.

I would like to turn the conference back over to Mr. Krohn for closing remarks.

I think that’s it for me, operator. We'll be updating the market as we go along for the rest of the year. And if anything additional comes up for this quarter, we'll do the same. Thank you very much.

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