W&T Offshore Inc (WTI) 2017 Q2 法說會逐字稿

Greetings, and welcome to W&T Offshore, Inc. Second Quarter Earnings Conference Call. (Operator Instructions) As a reminder, this conference is being recorded.

It is now my pleasure to introduce your host for today's call, Lisa Elliott. Thank you. You may begin.

Thank you, operator, and good morning, everyone. We're glad to have you join us on W&T Offshore's conference call to review financial and operational results for the second quarter 2017. Before I turn the call over to the company, I'd like to remind you that information reported on this call speaks only as of today, August 4, 2017, and therefore, time-sensitive information may no longer be accurate as of the date of any replay. Also, please refer to the company's second quarter 2017 financial and operational results announcement W&T released yesterday for disclosure on forward-looking statements and a reconciliation of non-GAAP measures.

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

Thanks, Lisa. So good morning, everyone, and thanks for joining us today. With me this morning is Tom Murphy, our Chief Operations Officer; Danny Gibbons, our Chief Financial Officer; and Steve Schroeder, our Chief Technical Officer. They will be available to answer your questions later on during the call.

So before we review our second quarter results, I'd first like to update you on the Bureau of Ocean Energy Management issue, which we expect to have completely resolved in a few weeks. On June 28, BOEM filed a motion with the Department of Interior to rescind its 4 orders issued in 2016 that instructed us to provide additional supplemental bonding of $260.8 million. And on June 31 -- actually, in July 31, the IBLA demanded the orders back -- or excuse me, remanded the orders back to BOEM, which is the first important step to the BOEM reversing or rescinding the bonding requirements. So we anticipate that sometime this month, necessary steps will have been taken to allow the BOEM to rescind the orders. When this does occur, we will make an announcement accordingly and put -- hopefully put this behind us.

So we're very pleased with both our financial and operational results in the second quarter. Production was in line with our expectations and was up modestly from last year's second quarter and from the first quarter of this year. We produced approximately 3.9 million barrels of oil equivalent or 43,848 BOE per day. Oil and liquids represented about 58% of production, which was also up slightly.

Notably, we've continued to drive down our lease operating expense, or LOE rather, which declined $5.1 million or 14% compared to last year and down $8.6 million or 22% compared to the first quarter this year. We've been very successful at reducing our base LOE over the last 2 years. So our base LOE, which does not include variable operating costs such as insurance premiums, workover costs and facilities maintenance costs, was $26.7 million in Q2 2017 compared to $30.7 million in Q2 of last year and $34.5 million in Q2 2015. By driving down base LOE, we've greatly improved our operating margins. So in addition to managing our base LOE downwards, we've also been able to significantly reduce our insurance premiums.

The most variable element of our operating costs is our workover and facilities maintenance expenses, which were much lower in the second quarter. As a result, our LOE was far below our guidance for Q2. We may see an increase in this cost during third quarter, but this will be somewhat weather and storm dependent because, absent tropical storm downtime, weather is normal -- normally pretty good in the third quarter. So the better the weather offshore, the more work we can get done. Regardless, we are projecting a very good operating expense outcome for the full year with the midpoint of our guidance at $157 million for 2017, which is down a full $12 million from our expectations and guidance at the beginning of the year.

Our estimated production volumes for the third quarter included an allowance for unexpected storm and weather-related downtime of about 3,000 BOE per day. Additionally, we had anticipated a 12,000 -- 12 million cubic feet per day recompletion of High Island 22, and wells only generated a rate of about 2,600 Mcf per day. Third quarter production is projected to be somewhat lower than our second quarter volumes before ramping back up in the fourth quarter when the A-17 well, Mahogany and several other wells will have an impact on our production. We believe this to be a conservative estimate of our production for the rest of the year. The combination of slightly higher production volumes in Q2, along with a much reduced LOE, resulted in EBITDA margins that we haven't seen since oil prices are more than twice what they are now. In the second quarter, we generated adjusted EBITDA of $72.6 million, up $31.8 million over the same period in 2016; and an adjusted EBITDA margin of 59%, up from 41% in the same period last year.

So excluding special items, our adjusted net income was $31.1 million, and our earnings per share were $0.22 per share. We've clearly turned the corner this year and are generating solid bottom line results.

So our midyear 2017 SEC proved reserves, or 1P, were 74.4 million barrels of oil equivalent, of which 56% was liquids, up slightly from year-end 2016. The increase in proved reserves is more than sufficient to replace production. Proved developed producing reserves increased almost 6 million barrels of oil equivalent or 13% compared to year-end 2016. They present a -- value of our reported SEC proved reserves discounted at 10% was $955 million. That's a 27% increase from $754.9 million at year-end 2016, and that's due to upward revisions of previous estimates and higher average prices.

We continue to offset most of the natural production decline of our asset base. A substantial portion of this comes from our Mahogany Field. In April, at Mahogany, we placed the A-16 well on production, which reached a peak production rate of 1,625 barrels of oil equivalent per day. That's about 83% oil. At the end of the second quarter, we completed the A-8 well, which is still on completion flowback, and we expect to be in a position next quarter to talk about the A-8 well results.

Both of these -- most of -- excuse me, both of these bypass wells were lower-cost and low-risk wells drilled to more fully exploit the P-Sand. That continues to be an amazing oil source and the main producer at Mahogany. To date, the P-Sand has contributed approximately 75% of the Mahogany Field cube production of over 45 million barrels of oil equivalent.

So our next Mahogany well, the A-17, is targeting the deeper T-Sand for testing and hopefully extending the further limits of that sand in the field. Operations have recently commenced on the well, and we're looking forward to seeing this well's results, which we expect in the fourth quarter. [Third] addition to the primary T-Sand target, the A-17 holds additional opportunities. That's another interesting potential for stacked pay above the deeper T-Sand. The A-17 could be a high-impact well for the company with the potential to materially expand the Mahogany Field volumes and value. It is possible that the T-Sand could prove to be an even larger and more prolific producer than the P-Sand. So assuming success, the A-17 well could be on our production during November, and we expect it to make a meaningful contribution to our year-end production exit rate.

So as a reminder, our A-18 well at Mahogany was completed in the T-Sand and placed on production in mid-January 2017. So that well reached the peak initial production of around 5,100 barrels of oil equivalent per day, and cumulative production so far has already exceeded 0.75 million barrels of oil equivalent of production since it came online.

The Mahogany Field T-reservoir was the primary contributor to a meaningful increase in our midyear 3P reserves, with a 48% increase in volumes or 80 million barrels of oil equivalent and a 73% increase in value or $1.3 billion from year-end 2016. This significant appreciation of 3P reserves is an indication of upside potential and phenomenal value that exist for this field.

So on the Ship Shoal area, we've mobilized a platform rig to our Ship Shoal 300 field to commence drilling the B-5 well. New seismic allowed us to map some strong amplitude features and multiple stacked pay intervals and an undrilled fault block very close to some excellent offset production wells in the field. Assuming the B-5 well is successful, we'd expect to have it on production in the October-November time frame. W&T operates this well with 79% working interest, and we expect the well to cost about $8.4 million to drill and complete. So in line with our project selection and high grading criteria, we expect this well to provide fast payback of under 1.5 years. Well holds potential for significant stacked pay. If the upside case is realized, it could trigger a follow-up well to further increase reserves and value. And we'd assume that we would -- in that case, we'd drill the next well.

So we recently added 2 low -- relatively low-risk exploration wells to our 2017 drilling program, with one at South Tim 224 and another at Main Pass 286. The well at South Tim 224 is a shelf exploratory opportunity located in 170 feet of water near existing infrastructure, which is expected to spud in the fourth quarter. W&T operates and holds a 39% working interest. If successful, the South Tim 224 well could be tied back to any number of nearby existing production platforms and placed on production quickly and, hopefully, cost effectively and may also spur additional follow-up drilling opportunities on our acreage.

Well at Main Pass 286 is also an excellent exploratory shelf well. There's an open water location. It won't be drilled off of the platform. So it's in 300 feet of water, and it is near existing infrastructure owned and operated by W&T. Again, the prospect exhibits strong seismic amplitude features helping to derisk the opportunity. Drilling will likely begin in the fourth quarter of 2017, and W&T holds a 100% working interest in the prospect.

So as we previously mentioned, we plan to commence our Phase 2 drilling program in our Ewing Banks 910 field area, which follows our very successful Phase 1 drilling program where we drilled and completed 2 successful wells about a year ago from our Ewing Banks 910 platform. Phase 1 wells have contributed to the increase in production in the field. Phase 2 is scheduled to begin in the fourth quarter. We'll include 2 new low-risk exploration wells, which are planned to be drilled and produced from the South Tim 311 platform. These are both low-risk, stacked pay prospects that can be put on production quickly, reducing cycle time and enhancing project economics.

Viosca Knoll 823 Virgo field, we have a 2- to 3-well program planned to commence later this year, with production contributions expected in 2018. These low-risk exploitation wells have strong risk-reducing seismic attributes, coupled with nearby well control and logs, especially -- well, essentially a bit out of place. These wells will be drilled from the existing platform and can be brought online, again, relatively quickly.

We've made great progress in our plug and abandonment program over the last 2 years. And assuming we complete all the projects planned for 2017, our ARO expenditures next year could drop to around the $10 million mark from around $80 million this year. So our total liquidity was $255 million on July 26, 2017. That included a cash balance of $105 million.

So as we indicated last quarter, considering the quality of solid growth opportunities in the Gulf of Mexico right now, we're reviewing a number of strategies to find opportunities to enhance our growth prospects. We mentioned previously that we had engaged Eaton-Stifel to help us create a drilling and acquisition fund. We're gaining traction in this process and expect to have positive news in the not-too-distant future.

So with that, operator, we can open up the lines for questions.

(Operator Instructions) Our first question comes from Richard Tullis with Capital One.

Tracy, sounds like good news potentially on the way for the BOEM. Once that order would be rescinded regarding the supplemental bonding, what do you expect total bonding cost, say, in 2018 to be versus what it is currently? Any change there?

No. No change. We might actually see a reduction in it.

Okay, good. Good. From a follow-up, W&T has done a good job over the years of drilling the sub-salt wells at Ship Shoal. Do you see the opportunity to kind of transfer that success and knowledge to other fields where you have sub-salt prospects?

Absolutely.

Could you elaborate a little bit? Do you expect to start drilling some of those, say, in 2018? And where might those be?

We're a little bit variable on the timing right now. As we get a little bit closer to that, I'll be able to reveal that to you. We're keeping that a little close to the vest right now.

Our next question comes from Aloke Agarwal with Phoenix.

Now that the DOL levels are back up, how are you guys thinking about the capital structure? You have these 2019 bonds coming due, and in the past, you talked about an exchange. We're just curious what you think here.

I don't know exactly -- I don't recall exactly what I talked about in regard to an exchange on the 2019 bonds. I don't believe that's exactly correct. I expect to generate enough cash to pay them off.

Excellent. That's good news. And just as a quick follow-up. On the last call, I believe, you talked about 2017 plugging and abandonment coming in a little bit lower. Is that still the case?

Yes, I think so. Hopefully, we don't have too many storms out here, and we should be pretty close to our estimate. If we have some more storm activity, then naturally, that will get -- that we'll be a little bit lower, but it will be deferred until the following year.

And my last question is just on the tax refund, the $69 million, is that expected to come in next year?

Yes.

We do have another question. It's from Richard Tullis with Capital One.

Yes, Tracy, thought I'd jump back in. As oil prices getting close to the $50 and you're generating more margin here, what do you see on the horizon for drilling more high-potential deepwater exploration wells? What sort of oil price do you look for to maybe start taking on that higher risk?

Well, again, it's not so much the price. It's the margins, Richard. Nominal dollars are important, but clearly, what we want to have is margins. So drilling costs are going down, but fortunately with the price or they have been in the last couple of years. So we think about it more as a margin investment and total capital pool that we have. Of course, we're working on this drilling and acquisition fund as well, so that will assist us in our efforts.

All right. And just lastly, Tracy. Looking out to 2018, I know your plan is -- planning process is still a little ways off, but what sort of drilling budget do you think it would take to keep production flattish in 2018?

I'm not sure yet, Richard. I don't have that answer. That's a really good question. We are in the middle of that budget. And of course, it will depend upon the success that we have for the remaining years. So I think it's a little premature to give you an answer. I don't want to give you a wrong one, so I'll just pan on that a little bit. But keep asking because I keep wondering what that's going to be myself.

There are no further questions.

We appreciate it, and we'll be in touch with the markets here in the next quarter or if not sooner. Thank you very much.

Ladies and gentlemen, thank you for your participation. This does conclude today's teleconference. You may disconnect your lines, and have a wonderful day.