W&T Offshore Inc (WTI) 2015 Q4 法說會逐字稿

Welcome to W&T Offshore fourth-quarter earnings conference call.

(Operator Instructions)

As reminder, this conference is being recorded. It is now my pleasure to introduce your host, Lisa Elliott. Please go ahead, Ms. Elliott.

Thank you, operator. Good morning, everyone. We appreciate you joining us for W&T Offshore's conference call to review the fourth-quarter 2015 financial results and for an operational update.

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 a recorded replay until March 16. To use the replay feature, call 201-612-7415 and dial the passcode 1362-9410.

Information recorded on this call speaks only as of today March 9, 2016 and therefore time sensitive information may no longer be accurate as of the date of any replay. Please refer to the fourth-quarter 2015 financial results announcement we released yesterday for a disclosure on forward-looking statements and reconciliations 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. Tracy?

Thanks, Lisa. Good morning, all. Joining me this morning are: Jamie Vazquez, our President; Danny Gibbons, our Chief Financial Officer; Tom Murphy, our Chief Operations Officer; and Steve Schroeder, our Chief Technical Officer.

Yesterday evening, we put out a detailed financial and operations release on the fourth quarter and full year 2015. We also provided guidance for the first quarter and full year of 2016. We won't repeat all of that again this morning, but we are happy to address your questions. We will be filing our Form 10-K with more details in a day or so.

So throughout last year, in 2015, we focused on completing the projects that were already in progress at the beginning of the year or that were committed to with partners; projects like Big Bend and Dantzler, the two Medusa wells and the Ewing Bank 910 project. Once we had those projects completed, we could reevaluate our position and plan our moves going forward.

Our goal was to maintain our production volumes and protect both our balance sheet and liquidity so that we could successfully navigate through the challenges of this low commodity price environment. We believe we did a good job on those fronts in 2015 and I took the right steps to manage those challenges.

Full-year production was down only 3.3% in 2015 compared to 2014, despite a 63% drop in capital spending during that same period, from $630 million to $231.4 million. Actually, crude oil production was up 7.9% year-over-year but both natural gas and NGL production was down 8% and 24% respectively.

Our 2016 drilling budget is dramatically lower instead about $15 million, not including plug and abandonment activities. It includes the completion of the A-8 well at Ewing Bank 954, which came online this month, but no other new wells are currently planned in 2016.

Based on the high volume of production additions from our recently developed projects, we had expected only a very modest decline in production in 2016 over 2015, with crude oil production basically flat. However, due to unplanned pipeline outages and maintenance and some unexpected well performance issues, we now expect production to be approximately 4 BCFE lower than our initial expectation. Thus an annual guidance has been estimated at 93.5 BCFE at the midpoint. I'm of the opinion this may be somewhat conservative.

The quality of our assets and the success we achieved investing in Gulf of Mexico projects over the last several years including Big Bend and Dantzler that came online late October and early November respectively is reflected in our strong production volumes. In 2015, we made three significant deepwater discoveries that were all brought on production within a few months of reaching total depth, as the wells were drilled from infrastructure.

Two of the discovery wells were at our Medusa field and one was off our Ewing Bank 910 platform. These three projects are predominately crude oil producers, which is one of the reasons that we've been able to increase crude oil production year-over-year. The forward spending in the deepwater in previous years is ultimately starting to pay off.

So our track record for achieving a 100% exploration success rate is now extended to almost three years. We've also done an excellent job of evaluating non-operated drilling prospects and choosing the right operating partners.

We are finding high-quality and substantial deepwater projects near or relatively near existing infrastructure, which can be brought on production quickly. This is an important trend.

While the Big Bend and Dantzler wells required about two years to be put on, they were developed fairly quickly and put online ahead of schedule and on budget. More importantly, they achieved their expected peak production rate of well over 50,000 barrels of oil per day gross and are still maintaining steady levels with only a small decline from the peak.

We also see additional production starting in March from our Ewing Bank's 954 A-8 well drilled from our Ewing Bank 910 platform. This well was completed in two zones. As a reminder, the A-8 discovery well reached total depth in December and penetrated a total of 150 feet of measured depth hydrocarbon pay contained in two sands. It was a follow-up well to the South Ten 320 A-5 sidetrack discovery that was completed in June 2015. The A-8 well has achieved a gross initial production rate from the lower sand completion of approximately 3,500 barrels of oil equivalent per day and is still cleaning up. We're actually taking the rig off the platform as we speak.

As we mentioned in yesterday's press release, we also completed a second zone well that was actually the primary and larger target zone and plan to place this second zone on production later as the lower zone depletes. So we will move from the bottom up. We continue to believe the field offers additional opportunities for future drilling when prices recover a bit and margins improve.

Now that the A-8 is completed and online, we have no other new exploration wells immediately scheduled for this year. Our objective is to focus on very low cost operations and to work on identifying the best future drilling opportunities. The cost of goods and services have fallen dramatically but still don't match the 70% decline that we've seen in crude oil prices or the continued weakness in natural gas or NGL pricing for that matter.

As we reported in yesterday's news release, adjusted EBITDA for the full year 2015 was $225 million, down from $569.2 million generated in 2014. Our adjusted EBITDA margin was 44% in 2015 compared to 60% in 2014. This decline was driven by a 45% decline in the average realized sales price we received per barrel of oil equivalent. Reductions in prices that we saw in the back half of 2015 have deteriorated further so far in 2016. EBITDA and EBITDA margin have declined further in 2016 as well. The drop in commodity prices continues to outpace the drop in the cost of goods and services.

Additionally, we had of ceiling test impairment every quarter in 2015. We'll have another one in the first quarter of 2016, all due to pricing. The steep price decline impacted our year-end proved reserves as well. Excluding the reserves attributable to the Yellow Rose field sold in October, year-end 2015 proved reserves declined 6.2 million barrels of oil equivalent, which is a 7.5% actual decline from the prior year to 76.4 million barrels of oil. The impact of lower commodity prices reduced year-end 2015 reserves by 10.7 million barrels equivalent.

In 2015, production reduced reserves by 17 million barrels of oil equivalent. We reduced reserves by about 19 million barrels of oil equivalent from the sale of Yellow Rose. On the upside, net increases from revisions added 15.3 million barrels oil equivalent, extensions and discoveries added 4.1 million barrels oil equivalent from that. We added 1 million barrels of oil from purchases.

If not for the price decline, we would've more than replaced reserves with the drill bit, which is a great accomplishment considering the size of our capital budget. In fact, our reported year-end 2015 proved reserves don't yet reflect the success we had with the drill bit last year in the solid performance from some of our established properties.

We had positive revisions from over 13 fields, including a small contribution from Big Bend. The biggest upward revision came from our Ship Shoal 349, our Mahogany field. Other increases came from Fairway, Matterhorn, Neptune and Tahoe and our Brazos A-133 field. The reserve extensions and discoveries are primarily associated with Medusa and Ewing Bank 910 field.

So in 2016 we'll stay focused on managing our expenses as we did throughout 2015. As an example, our lease operating expenses decreased 35% in the fourth quarter compared to the fourth quarter 2014. We're down 27% for the full year.

G&A was down 29% before quarter of 2015 compared to the 2014 fourth quarter and were down 16% for the year. We expect further reductions in 2016 as you can see from our guidance.

If prices continue to be weak, we would expect even further reductions and not only LOE and G&A expenses but also plug and abandonment cost as well. For instance, we had forecast just a month or so ago to spend $84 million on P&A in 2016. We now think that some work can be done for as little as $65 million for a production of 23% -- for a reduction of 23%. Costs are coming down rapidly and hopefully commodity prices and the cost of goods and services will realign in the not-too-distant future.

So as I said earlier, balance sheet preservation is essential. We accomplished a lot in 2015 to enhance our financial flexibility. So we suspended our common stock dividend in early 2015, in April and October. We remitted our revolving Bank credit facility and modified or eliminated certain financial covenants.

In May, we obtained a five-year $300 million term loan financing to boost our liquidity and reduce borrowings outstanding under our revolving Bank credit facility. Our timing couldn't have been better with that transaction.

In October, we've repaid the balance from bank borrowings with the proceeds from the sale of our Yellow Rose fields in West Texas for $372.9 million and enhanced our cash balance by $100,000. In February 2016, we drew $340 million on our revolving bank credit facility to maximize our liquidity and ensure that we can navigate through these industry headwinds.

The Company's cash balance subsequent to the draw was $447 million. We also hired both legal and financial advisors to assist the Board and management as we work through challenging market conditions.

So in this commodity price environment, we believe that maximizing liquidity and adjusting our capital structure to remain in compliance with our financial covenants is essential. We are maintaining an active dialogue with our lenders and evaluating our options. Our spring borrowing base redetermination process is currently in progress. We expect the borrowing base to go down.

Keep in mind, our senior unsecured notes don't mature until June 2019. Our term loan doesn't mature until May 2020. We don't have long-term drilling contracts or drilling obligations of any significance. No material near-term lease expirations, as most of our acreage is held by production. This combination of things will go a long way to helping us weather this industry downturn.

So as previously discussed -- disclosed, we had been having discussions with the US Department of the Interior's Bureau of Ocean Energy Management, BOEM, regarding certain supplemental binary requirements for a potential offshore decommissioning liabilities including plugging and abandonment.

In February and March 2016, the Company received several letters from the BOEM ordering the Company to provide additional supplemental bonding on or before March 29, 2016 in the amount of $260.8 million to cover obligations under certain federal oil -- offshore oil and gas leases operated by the Company. So the issuance of any additional surety bonds to satisfy this order or any future orders could require the posting of cash collateral, which could be substantial.

We intend to continue our discussions with the BOEM to resolve these issues. If after we view this order, the Company deems it necessary and appropriate, we may exercise our right to appeal to the Interior Board of Land, appeals or otherwise challenges ordered. Separate from the BOEM's actions, we've set a budget for 2016, plug and abandonment activities of $84 million. But as I said earlier, we now think we can perform that same word for around $65 million.

Over the last three plus decades and through several market cycles, we've built a track record for acquiring, reducing Gulf of Mexico assets at favorable valuations and successfully exploiting the upside opportunities that we've identified. Those opportunities will continue to be there but we need to navigate carefully to take advantage of those opportunities. As always, we look for quality producing assets with bankable reserves. We then apply our expertise and knowledge of the Gulf of Mexico to assess the upside potential of those assets. That's a key ingredient. Of course, we need to get the price right on that purchase.

Our team of geo-scientists, who we believe are experts about the Gulf of Mexico will continue to analyze the advanced data that we've obtained to high-grade our inventory of drilling opportunities, evaluate the well data, recently drilled projects and identify potential exploration, exploitation, expansion projects.

So under the current market conditions, we don't think directing capital in drill bit is necessarily the right decision. We do hold a substantial amount of quality acreage by production, we believe that some of it is additional untapped upside potential including projects that could be impactful. Other things that we might consider under the circumstances are farm-outs, joint venture opportunities, asset sales, acquisitions just to name a few.

So W&T has some great assets. We are working hard to make we take full advantage of those assets in the future. I can promise you that as a majority owner of W&T this is very personal.

With that, operator, we can now open it up for questions.

(Operator Instructions)

John Aschenbeck, Seaport Global.

I was hoping you could quantify what we should expect coming out of redetermination season? Any idea of what a potential cut may look like? Thanks.

Yes. I don't think I'm prepared to answer that question. We're just in the beginning of that redetermination. So I don't really have anything that I'd want to impart to the market at this point in time, as it could be wrong.

Okay, that's fair enough. So it looks like the redetermination is set to be completed by the end of March, should we expect an announcement around that time?

Yes.

Okay, great. Appreciate that. One follow-up for me is in regard to the additional $261 million in BOEM bonding, how do you think that'll impact liquidity? Do you have any idea of what amount of cash or letters of credit you'll have to front for that?

Yes. We are having those discussions with the BOEM. I really can't give you any definitive solution at this point in time. This has been a process that's been ongoing for months now. We expect it will continue going forward. Certainly, it has an affect on liquidity. That is a concern for us.

Okay, really appreciate that. I'll jump back in the queue. Thanks.

Sure. Thank you, sir.

Richard Tullis, Capital One Securities.

Tracy, I understand -- certainly understand the rationale for the $50 million drilling and completions budget this year. What sort of impact do you foresee that it could have on 2017 production? Or what are you looking at, as say a 2016 production exit rate with that budget?

I really can't give you a prediction on 2017 with this budget at this time. I'd be hesitant to do that because we still think there's opportunities out in the Gulf of Mexico for us. We don't know what that can be at this point in time exactly, but normally when we come through these downtimes, we see opportunities that we can take advantage of. So I mean I could give a blow-down case but that would be outside our normal period of guidance.

What is the -- say the base production decline rate for your overall production -- the oil production at this point, including the new projects online?

Well, this year it looks like we're about 7% to 8% down on production.

Okay.

That's kind of what we're looking at.

Then what oil price would you be looking for, Tracy, say to start considering a resume in drilling?

That's a great question. People always ask me about the oil price. What I always respond is that is not just about the price, it's about the margin. It really is about the margin. So the difference in margin is what's important to us. The cost of goods and services play a huge role in what we can afford to drill and exploit and/or purchase.

So currently margins were about 44%, I believe for last year. They're normally around 60%. So we'd like to see the margins be closer to 60% before we'd say, yes, okay it's time to go back to work and do everything we can do to spend money and increase production and reserves.

It's difficult to operate in those margins -- of course, as you've seen from the ceiling test impairments, it's all price related on that. So I don't think it's necessarily difficult to predict that as prices continue to come down that we continue to have a ceiling impairments and the cost of goods and services needs to catch up with that. So there's still that disparity of cost of goods and services. The good news is we are seeing cost of goods and services accelerate -- decelerate. In that sense, prices are going down for cost of goods and services.

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

Yes, sure. Thank you.

Noel Parks, Ladenburg Thalmann.

I just had a question about the expense guidance. I was looking at the first-quarter items versus the full-year. With the LOE and the gathering lines is there a ramp up assumption embedded in the quarters? I look usually more on a unit basis. Or is it just we're seeing sort of the fixed expenses being sort of carried over across the base decline of production?

No. You're correct. There is a bit of a ramp up. That's because of seasonality. We generally tend to go back and go out and do more work in the better weather months. So that's spring, summer as opposed to winter and fall because the weather is a little worse in those periods, it's easier to do work in the better weather months.

Great, thanks. Roughly where in the quarter or currently -- the Dantzler and Big Bend production, where does that stand roughly?

Well, we're still in the 40,000 to 50,000 barrel a day range. We're monitoring it. We're changing choke sizes. We're analyzing reservoir drive mechanisms. So it's a little bit up-and-down, but generally 45,000 to 50,000 barrels a day

Okay, great. That's all for me.

Steven Karpel, Credit Suisse.

I was trying to understand what the bonding point, the $260 million, it doesn't seem like an overwhelming amount for the bonding market. Can you give us a sense on your conversations of talking to surety -- that talking with surety bond providers, is $260 million a very achievable number that doesn't require you to go outside of that, IE post direct cash in lieu of?

I can tell you that the surety bond market has closed. It's gotten very tight. The reason is because BOEM is expecting bonding from everybody now. That's their stated mission.

So that market has gotten a lot tighter. I guess it's probably not accurate to say it's absolutely closed, it hasn't. But as far as I can tell, it's really very narrow right now. Sureties are somewhat nervous about their exposures. So yes, that's been a problem for not just us but other companies.

So then the follow-up to that is, what does that mean for existing surety bonds that are already outstanding? Then secondly, what does that mean for direct [practically] LCs between companies? I think you have -- I think you're the recipient of a couple of those as well.

Yes, we are. I think BOEM needs to work through these issues -- not only with us but other companies, to resolve different methods of allowing for abandonment. There are different ways to manage that. We're having those discussions with them as we go through this cycle.

Just -- then maybe I'll ask a qualitative point if you would comment. Does the BOEM grasp the magnitude of the issue on the individual companies and what that means to the market? Thank you.

Yes. The short answer to that is, they have a lot of data to work through. I think they understand the magnitude of the issue. I'm not sure that everybody's quite on the same wavelength and seldom argue with regulatory agencies. But I don't think the intent is to close down the Gulf of Mexico at this point. I think there are reactions that they've had to situations that they've had to deal with.

The other problem that they've had is, they've had a lot of temporary Directors rotating in and out of the office in New Orleans. That's made it more difficult to solve some the problems that need to be there. Apparently, we have a -- not just an acting Director but a main Director in New Orleans now, so I think that's going to help solve some of the situations. We have little bit of permanency in that position.

Thank you.

Yes, sir. Thank you.

(Operator Instructions)

Jon Evans, JWEST.

Tracy, I was hoping maybe you could elaborate a little bit more about the production issues that you had kind of in the fourth quarter? Did you ex -- in the third quarter, you averaged about 46.7 MBoe a day. Then if you take out the sale that was about 2.3, then if you brought on 8 from Big Bend. So can you just help us understand the pipeline issues? Maybe what other issues you have?

Yes. Well one of them was scheduled and in fact, we're in the middle of that right now over at, I believe, it's Poseidon is the pipeline that was scheduled maintenance. Then one of them was unscheduled, that serviced our fields a little bit closer to shore. They're around Ship Shoal.

That repair has been completed, but Poseidon is now down. That affects our Mahogany field as well. So a big chunk of production there that's down for probably a total of about two weeks. So hopefully that answers your question.

Then did you have any other problems with any of your existing wells? You kind of alluded to that in your comments? Or did I just hear you wrong? I apologize.

No, you didn't hear me wrong. We've had a couple of well issues that deal with production. We've got one well out in Deepwater that has an effect from asphalting production. We're working on solving that now. We actually have begun to inject xylene through a control line to help solve -- we're having a little bit of success, we're still not back on production with it yet. So that's been the biggest impact.

Just the follow-up to that, do you feel like you guys will be able to bring that back on or given the insight? Yes?

Yes. The short answer is yes. The question is whether we bring it back on through a remedial action that doesn't require an intervention vessel? Or whether we put an intervention vessel on the well site itself. So we're working to not have to use an intervention vessel. We think we're having some moderate success with that, So as long as we can do that, that's the direction we'll head.

Okay, thank you for your time.

Yes, sir. Thank you.

John Aschenbeck, Seaport Global.

I was wondering if you could potentially talk on your comfort level and an ability to perhaps pull off some type of debt swap restructuring of perhaps even a significant asset sale to help right-size the balance sheet?

Well, okay. I could talk a lot about that. Do you have something specific you want to ask?

Yes, I guess really the follow-up is assuming the strip plays out through 2016, leverage does start to creep up a little bit. I guess really I just want to get your thoughts on where leverage would sit by the end of 2016? Any solutions you may have to just draw down debt and help credit metrics?

Yes. Well, the short answer is, the runway is a function of margins. So it's not just price of oil, again, it's price as a function of cost of goods and services as well -- or margins is a function of cost of goods and services as well. So clearly, if prices stay down for a longer period of time then that will put more risk into the equation.

If prices go up then obviously that makes it better for us. Clearly, if the cost of goods and services will march in lockstep with pricing, IE, go down, then that will extend that runway as well. Clearly, we recognize we have a debt issue that needs to be solved. We've hired advisers to help us do that.

Okay, great. Understood. So I guess it's not just only bringing down debt, but you could look to boost the denominator, keep margins up and help you on that front. So really appreciate the color there.

Yes, sir. Thank you.

Thank you. We have reached the end of our question-and-answer session. I'd like to turn the floor back over to Management for any further or closing comments.

No, operator, that's all I have. We'll talk again in the not-too-distant future. Thanks so much.

Thank you, sir. This does conclude today's teleconference. You may disconnect your lines at this time. Have a wonderful day. We thank you for your participation today.