Welcome to the W&T Offshore 2016 Fourth Quarter Earnings Conference Call. [Operator Instructions]. As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Lisa Elliott. Thank you. You may begin.

Thank you, Operator and good morning, everyone. We appreciate you joining us for W&T Offshore's conference call to review the fourth quarter of 2016 financial and operational results. Before I turn the call over to the Company, I would like to remind you that information recorded on this call speaks only as of today, March 2, 2017; and therefore, time sensitive information may no longer be accurate as of the date of any replay. Also, please refer to the fourth quarter of 2016 financial operational results announcement that WT released yesterday for a disclosure on forward-looking statements and reconciliations of non-GAAP measures. And 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 on the back end of earnings season. With me this morning are members of our senior management team that can help answer questions when we get to the Q&A part of the call. Yesterday, we released our financial and operational results for the fourth quarter of 2016. Over the last month or so, we announced our 2016 production and year-end pre reserves, our 2017 capital plan and our 2017 production and expense guidance. The Investor Relations slide presentation has been posted to our website that contains additional details regarding these announcements. We will be referring to some of those slides today during the call, so if you get a chance, pull up your computers and take a look at the slide presentation, I'll be referring to them, if you hadn't already done so. So in the fourth quarter, we produce approximately 3.7 million barrels of oil equivalent or 40,300 barrels of oil equivalent per day, of which about 55% was oil and liquids. Our production held fairly steady compared to the third quarter's production of 41,500 barrels of oil per day. In 2016, we spent $48.6 million on capital projects. This included 16 recompletions, 11 of which were successful and contributed to production at a lower cost compared to drilling a new well. 2016 production also benefited from major projects that were completed in the fourth quarter of 2015, including Big Bend and Dantzler. So in 2016, obviously we dramatically reduced our capital budget for the second year in a row, only completed one new well in 2016 and we were still able to maintain a fairly stable production profile. This is clearly a testament to the quality of our assets and the highly prolific projects we invest in. So comparing…

[Operator Instructions]. Our first question comes from the line of Richard Tullis with Capital One.

Tracy, you talked a little bit about costs in the Gulf of Mexico. And as you know, we've been hearing from some of the shale operators that they're expecting costs to rise, are already seeing costs rising. Could you give us a little more detail on what you expect in the Gulf this year? And also, maybe talk a little bit about what's the current cost to drilling complete a sub salt well at Mahogany?

I think that, obviously, the Gulf of Mexico is a lot different basin that what you see over in West Texas and in the Bakken and whatnot. Our cost profile is, we think, is going to be fairly steady and really, we think of it more in terms of margin, as opposed to just cost, Richard. So as prices go up, clearly costs will go up some. We're pretty confident that we can retain those margins. Again, we don't have as much competition in the Gulf Mexico. There's a lot of equipment available and personnel, as well. So that's not something that, while we expect to see a little bit of cost creep, we also expect to maintain those margins.

Okay. On LOE, you made a lot of progress over the past year, especially if you look at it on a barrel basis. How do you see 2017 shaping up on the ability to maintain some of the gains that you've achieved there?

You know, that's an excellent point. If you think about it, from where we started in late 2015, the cycle is that as prices drop, so do your costs. As you think through the entire cycle, if the price of oil drops 50%, then you would expect costs to drop 50% over time. It was a little bit slower than other cycles that we've seen. Usually, it takes about 9 months. This one was little bit slower, but it's finally back where would we expect to see it and a lot of that's driven by transportation costs, boats and helicopters. As people roll off contracts, those prices go down. So we've begun to see pretty stable pricing on LOEs and CapEx.

Okay. And just the last one for me, Tracy, with the Deepwater projects online over the past couple of years and having a bigger impact on the overall production base, what is the current companywide base production decline rate?

I'm going to say it's less than -- it's around 10%.

[Operator Instructions]. Our next question comes from the line of John Aschenbeck with Seaport Global.

Tracy, I had a follow-up on the economics you laid out in your prepared remarks and you also touched on these in one of your ops updates earlier in the quarter. Speaking to 80% to 100% rates plus of return, I think that's a lot higher than what most investors expect for the Gulf. So I was just hoping you could maybe lay out what's been the primary driver behind the improvement in economics. Is it just a function of costs or are there other factors at work?

Well, it is primarily function of cost and as well as CapEx, again it's margins, but also because of the fact that we've done a pretty good job with how we manage our risk, how we manage our selection of projects and we look at it holistically from cradle to grave. So I think that we've certainly high graded the portfolio. We've had a lot of time to work with it here, because we haven't been as active as we had in past years. So the team does a peer review that's pretty comprehensive and we do a lot of work on the geological side of it. We've got better data. We've got more knowledge of the fields that we own and I think that some of that is also due to the completion techniques we use out in the Gulf now. We do what are called frac packs, where we do a small frac, as well as a gravel patch, as well, because of the nature of the reservoirs and that opens up permeability and porosity near the wellbores, probably more than you wanted to hear.

No, no, that actually touches on my follow-up. And that is, the other way you can improve margins is not only reduce costs, but hope for an improvement in commodity prices, but also potentially boost well performance. So I don't know if you could quantify what's been the associated production benefit from the frac packs you were speaking of.

As you get close to the well bore, you often experience a dramatic decrease in pressure. In an optimal situation, you would have zero decrease in pressure. If you get it right, that's the optimal position you want to be in. So we take a lot of care in the completions in how we filter our fluids and also how we manage delta P, the change in pressure, near the wellbore with the frac packs. Now it doesn't necessarily mean that we frac pack every reservoir, it depends on the nature of the reservoir itself, but we do put a lot of work into that. We do think that often times, we may spend a little bit more money on a completion, but we get a better result. So as result, I think that the kind of returns that we're seeing are going to be fairly typical going forward. Obviously, as you get out further on the risk scale of drilling, then you have perhaps different results in overall performance in your drilling program, but the completion part of it, I think we have pretty well figured out.

All right. That's great detail. I'm not sure if it's as simple as just throwing a number on it, but on average, has it resulted in a 10% improvement in performance, 20%?

I think I could quantify it around that range, yes.

Our next line comes from the line of Patrick Fitzgerald, Robert W. Baird.

Why are you -- you kind of hit on this question earlier -- but why are you expecting higher LOE on a per barrel basis in 2017, based on your guidance, versus what you've been experiencing the last couple quarters?

Well, I think there is going to be some cost creep there, but we've got a number of workovers to do and we've got a little bit of work to do on the facilities that we own. Normally, we see activity during the summer months on the facilities because the weather is really good. I think that there is some cost creep as a function of the industry and a little bit more optimism with regard to oil and gas prices, but again, that's a margin function. I think that probably we had some work that we deferred from 2016 in an attempt to save a little bit of cash that will now be performing in 2017, as well.

It's really interesting to hear the talk on acquisitions. I'm just wondering how those would be financed, given your current capital structure?

That's a great question. Stay tuned.

Okay. All right. On CapEx, how long could you maintain production? You've hit around this issue, but how long could you maintain production? You're growing production 4% next year, but if you spent $125 million in CapEx, is that sustainable or is that just because you're doing the low hanging fruit this year and you'd have to spend more next year? Any thoughts on that would be helpful.

Yes. Part of what we're seeing here is the increase due to the probable and possible reserves that weren't previously booked and that's a fairly common theme with regard to our production out in the Gulf and the types of fields that we've been discovering and working on. So very often in Gulf of Mexico -- and I really appreciate the question, Patrick -- I try very hard in our presentations to make people understand that most of the time, when we start our initial bookings, we're not getting all the reserves that we feel should be booked. Over in Europe, they book 1p and 2p. Here in the U.S., the SEC doesn't allow you to book anything other than 1p and it's a very strict guideline on 1p. On land, if you drill a well in a block, you'll get credit for several blocks around you for those type of reserves. We don't have that luxury in the Gulf of Mexico, the SEC guidelines are much stricter and the nature of the reservoirs are different. So very often -- in fact, if you'll look at slide 13 in our presentation, I'll refer to that again -- the initial booking isn't nearly what it should be. We prove that over time, very often by the time we get to where we should be booking 2p and 3p, we've already produced it, in excess of our initial 1p production.

And then I didn't completely hear what you said on bonding. Is that takeaway that there's likely no additional, no bonding needed in the near term?

I can't -- yes, nothing in the near term. Apparently one of the rules came out on sole liability leases, in other words, leases where there are no other co-owners and no predecessors entitled. There was an NTL that came out close to the end of 2016, in fact, right at the end of 2016, that demanded bonding for all sole liability leases that operators had, gave them 60 days to accomplish that. That was just rescinded last week, it was actually revoked.

Okay. Is there any reason to expect your differentials in 2017 to be any different from 2016?

Oh, it could be. That's a function, again, of availability and local markets driving that. I can't really predict what differentials have been. They do change fairly often. But think a little bit about Venezuela. What happens if the country implodes? A lot of that oil comes to the United States, heavy mining crude comes to -- I'm sorry, heavy Venezuelan crude -- comes to the U.S. for refining. There's a fairly substantial risk in that country that reserves won't be able to get out of the country for a while. That could dramatically change differentials here in the U.S.

Our next question comes from the line of Craig Kelleher with Millstreet Capital.

Following up on the bonding question there, so the BOEM was asking for, what, $261 million? So based on what you said was revoked or rescinded, can you break down what part of the $261 million was that or can you give any sort of -- has the full $261 million gone away?

Actually, the $268 million was a separate bonding demand made, what, back in 2015, latter part of 2015. There is some part of that that's included in that $268 million, but mostly, it was an addition and it was revoked.

Okay. So what about the $268 million or what about that number now? I know you were negotiating that.

Yes. We've been doing that for well over a year now. So there was another NTL that came out that was a separate guideline for bonding in the Gulf of Mexico. The $268 million is on appeal with the IBLA. That has been stayed several times and is now stayed until the end of May. So we've got new leadership in the Department of Interior. Stay tuned. We'll find out what happens. My prediction is that a lot of this will get sorted out in a more reasonable manner.

Okay. And then just to follow-up on your acquisition, your talk about acquisitions and creative financing, what debt levels are you comfortable with in terms of post an acquisition? And would it be more debt financed, more equity financed?

Well, obviously, I don't want to have any more debt to do these things. I think that there's other ways that we can accomplish our goal and we're planning on that. It doesn't mean we won't have zero additional debt included with it, but we're working on that and, again, I ask you to stay tuned. We're very cognizant of the fact that we have debt levels that are still not as acceptable as we'd like to have them. However, we see a lot of opportunity in the Gulf of Mexico, in Deepwater, as well as the shelf.

Our next question comes from the line of Gail Nicholson with KLR.

Just regarding the opportunities that you see available, do you have a preference between shelf and Deepwater and is there more opportunity in one of those regions in the Gulf?

No, ma'am. I only have a preference to make money. I don't care whether it's Deepwater or on the shelf. Fortunately, we have the ability and the personnel to operate in the Deepwater, so I think it gives us a little bit of a competitive advantage in that sense. I think that we'll see excellent opportunities in both areas of the Gulf.

And then I know when you sold your Yellow Rose prospect to Ajax back in the third quarter of 2015, that came with an overriding royalty interest in the field and I was wondering, are you receiving any of that interest in your production? Is that something that you could potentially monetize?

Sure.

Okay. And then my last question is, in regarding to the P&A liabilities, has this been relooked at based upon the lower cost environment or are P&A liabilities based upon a higher cost environment and the $268 million of bonding, is that based upon the current cost environment or a higher cost environment?

Okay. Let me break down your question, so that I get it right. The first part of your question dealt with whether or not we think the bonding amounts are fair, is that right?

Yes.

Okay. Well, no, we don't. We have just recently -- or we will, in the next, probably today we'll come out with a 10-K and you'll have our new ARO numbers, so that will give you comfort on what our current P&A liabilities are. With regard to the $268 million, that's under appeal at the IBLA. We expect that actually, in all fairness, we would expect that would dissolve away as a function of the NTLs that were published after that.

One other point, to your question there, Gail, we've actually just executed a whole series of pretty impactful subsea abandonments which are important part of our P&A liability and any Deepwater player. But to give you a sense of that, because your question really was about what's the BOE numbers and the $268 million, they generate their own numbers based on their thought process. It's a little bit difficult to follow exactly what the thought process is, but we just have executed almost about six or so very key projects and we're actually executing them between 30% to 50% of what the BOEM, quote - unquote, estimates are. So that might give you a sense of when they're throwing their numbers around -- and this is Tracy's point -- they're trying to seek some bonding elements of that and we actually just, we just don't believe that. Not only do we not believe it, we're executing them to, let's call it, a significantly lower number. It's not measured in single digit percentages lower. I'm talking 30% to 50% of the actual estimates that they have. So that is cooked into our annual review of our ARO and P&A liabilities.

So it's baked into your liabilities on your balance sheet, but the bond might not be necessarily taking the current cost environment into their calculations for what they feel the bonding needs to be.

That's right.

That's correct.

Okay. Perfect. Thank you.

And that's a big point of discussion and continual conversation space between the industry and the BOEM.

It's not just us. It's all of us in the Gulf of Mexico.

Thank you. We have reached the end of the question-and-answer session. I would now like to turn the floor back over to management for closing comments.

Thank you, everybody, for listening. We'll talk to you next quarter, if not sooner. Thanks so much. Bye-bye.

Ladies and gentlemen, this does conclude today's teleconference. You may disconnect your lines at this time. Thank you for your participation and have a wonderful day.