W&T Offshore, Inc. (WTI) Q4 2016 Earnings Report, Transcript and Summary

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 calendar year 2016 to 2015, 50% of our production volume decline was due to the sale of the Yellow Rose field located in West Texas in October, 2015. Gulf of Mexico production was down only 5% year-over-year. Again, that's a testament to the quality of our portfolio and assets. Our results demonstrate why we're committed to the Gulf of Mexico and believe it's an excellent investment vehicle. While the Gulf is perceived by some as a basin with a steep decline curve, many of our projects don't fit that profile at all and compare favorably to other basins regardless of whether they are conventional or shale plays. The high porosity and high permeability rock characteristics of the Gulf, coupled with the high likelihood of really good reservoir drive mechanism not only generate greater cash flow and faster payback which translates into superior rates of return and return on capital, but we also see better production decline curves compared to the very low permeability and low porosity rock common to the onshore shale and unconventional plays. I'll refer now to slide 10 of the presentation. That compares the decline performance of two actual wells illustrating this point. Production curve at the top of the chart is one of our Mahogany wells and is pretty typical of other types of Gulf of Mexico wells. The second or lower, production curve on the chart was a very good performing horizontal Spraberry well located in the Permian Basin and which would be considered a high performer. As you can see, the production decline in the GOM well in the early years is much shallower than the unconventional shale plays. This shallow decline curve of many of our projects contributed to our ability to maintain steady production on a small capital program. It's one of the things we've always liked about the Gulf of Mexico and which obviously contributed to our value. So during the year 2016, we also held our proved reserves steady, with our year-end 2016 SEC proved reserves coming in at 74 million barrels oil equivalent which was comprised of 55% liquids by volume. This is down only 3% over last year's reserves. We had a 1.2 million barrel oil equivalent negative impact on reserve volumes, due to SEC pricing assumptions and had a really great year on technical revisions due to performance which nearly replaced our entire annual production. According to SEC rules, the assumed oil price in this year's reserve report is set at $39.25 per barrel for the life of all reserves. We certainly believe this is not a likely scenario and believe realized prices will be higher and further enhance our value. So if you would, please refer to slide 33 of the presentation, when we present year-end 2016 proved reserves at the SEC price case on the left side of the page and also present 2016 reserves at year-end NYMEX prices in the center of the page. You'll see NYMEX base reserves of 77.6 million barrels of oil equivalent result in a reserve replacement rate of 102% over the year-end 2015 SEC reserves. That's actually pretty phenomenal on only $48.6 million in CapEx. You'll also note that our PV-10 at year end in the NYMEX case is $457 million higher than the SEC case. So we credit this ability to replace reserves to the unique characteristics of the Gulf and our asset base. So over the years, I've pointed out how strong the production drive mechanisms of reservoirs in the Gulf, along with superior rock and geological properties, allow for probable and possible reserves to come to a wellbore without incremental drilling costs. Sometimes, they even get produced before we get credit for them as proved reserves in the prior year reserve report. So in 2016, several of our most important oil fields, gas fields as well, performed substantially better than previously predicted by our external independent reserve engineers, primarily due to our ability to move probable and possible reserves into our proved reserves category due to positive field performance. So as a result of the exceptional reservoir characteristics of the Gulf, we almost replaced our entire 2016 production, again through performance revisions alone. So take a look now at slide 13 of the presentation. It shows three examples of fields where our current proved reserves associated with the field are higher than early reserves and upside volume productions. If you'll look at the first part of the slide on the left, it shows you one of our Deepwater fields where current 1p is now greater than initial 3p booking. And similarly, in the middle part of the page, it refers to Mahogany in the T2 sand. Current 1p is now greater than initial 2p booking. And finally, on the right-hand side of the page, we have another Deepwater field where we have current 1p that's greater than initial 1p booking. And we show you the rest of the reserve categories in all those three examples, as well. So again, we see that these reserves are significantly under booked on initial production due to the strict SEC guidelines; and therefore, our assumed asset value can be considerably understated and not indicative of our true underlying real asset value. So moving on, our fourth quarter financial results improved significantly over the prior year, due to higher commodity prices and the success that we had in lowering our operating expenses. Our average realized pricing was up 24% since last year, driving an 11% increase in revenues. Our operating results were boosted by a 31% decrease in LOE, a 43% decrease in DD&A, no ceiling test write down and an 11% decrease in general and administrative expenses. We reduced interest expense by 57% and generated net income, excluding special items, of $0.06 per share, compared to a loss of $0.40 per share a year ago. EBITDA margin for the quarter was 60% which is back near our historical range. That's a dramatic improvement over an adjusted EBITDA margin of 39% in the fourth quarter last year and 49% in the third quarter of this year -- excuse me, 2016. We're enthusiastic about our future opportunities at current commodity prices. And with a much improved cost structure for operating the Gulf of Mexico, we have a quality inventory of projects that offer really great returns. Before I discuss the projects we expect to pursue in 2017, I'd like to point out that the importance of this lower cost structure on profitability is really phenomenal. While high pricing -- higher pricing, played a major role in the improved EBITDA margin, our lower operating cost achievements were a major contributor, as well. Over the last two years, we've seen operating costs drop nearly 50% from cost expectations and projections from our planning cycle just a couple of years ago. Not only have operating costs declined, but drilling costs have come down, as well. Drilling new rates are much more competitive now and that's allowing us to return to drilling projects with strong economic potential. With acknowledge that all GOM operators have experienced regulatory challenges during the last administration, particularly post the Macondo well, but we believe that pendulum is most likely to be adjusting back to a more moderate level. Of note, we recently received notice that the BOEM withdrew certain orders related to sole liability properties, i.e., a request for additional bonding, issued late in the previous administration to allow time for the new presidential administration to review the complex financial insurance program under the Notice to Lessees Number 2016 - November 01. So as we outlined in our press release on January 24, our 2017 CapEx budget is currently set at $125 million. That excludes any potential acquisitions. We expect that we will drill six to eight wells and perform 20 to 25 recompletions with that capital. Our program is focused on projects that we believe are low risks and that are located near existing production and infrastructure and can be brought on production relatively quickly, offering fairly immediate cash generation. All of these projects offer rates of return of at least 80% and some are expected to achieve a return well over 100%. None of these projects are what you would consider high risk. Recompletions that we have scheduled are projected to also deliver very attractive rates of return and short payback cycles. Approximately 66% of the entire capital budget is allocated towards projects that will come online and begin production in 2017, but the biggest benefit will be felt in 2018 and beyond. Based on our current plan, we believe that our 2017 production will be about 4% above 2016 production levels. So operationally, we recently experienced some unplanned pipeline maintenance work occurring on the topsides portion of the export pipeline servicing our Deepwater Tahoe field. The field was temporarily shut in for about 12 days, but that work has now been completed and the field is currently back online at normal rates. We don't anticipate this 12-day outage will have a material impact on our full-year guidance and reiterate the 2017 full-year production guidance. One of the reasons we have a large inventory of low risk drilling opportunities is because many of our fields have reservoirs with multiple stacked pays. Over the next several years, we expect to drill wells in our core focus area of Mahogany, UM Bank 9-10, Virgo and other stacked pay fields. Our slide presentation contains diagrams based on actual data that show the location of pay in a few of those fields. So unlike a stacked formation shale play, we don't have to drill an complete a new lateral section. We just recomplete an existing well in a new horizon. Of course, Mahogany is a really great example of a stacked pay reservoir. We have numerous pays there so far and have named them M through U, with the U sand most recently discovered in January, 2017 via the A-18 well. As we mentioned earlier, we're currently drilling the A-16 sidetrack to the P sand. And this well is also expected to have additional uphole future completion zones above the main P sand. We expect this well could produce a gross rate in excess of 1,000 barrels of oil equivalent per day. Following the A-16, the rig is expected to conduct a few rate enhancement/optimization workovers prior to moving back into drilling mode, where we will most likely drill additional wells targeting the P, Q, T producer sands and the new U sand. That's following our recent successful outcome at the A-18 location. By the way, that well, the most recent one we drilled at Mahogany, A-18, is still producing over 5,000 barrels of oil equivalent per day. The Mahogany Field continues to get larger. And as it has, the work program has expanded along with it. Our most recent logged seismic data continues to allow us to image this field better and exploit the pays in the deep sub solid environment. As we mentioned in the press release, we have a high impact recompletion underway at our High Island 21 field targeting various zones above the producing zone in the wellbore. The recompletion is expected to produce at a gross rate of over 1,000 barrels of oil equivalent per day when completed in the first or second, I guess early second quarter of 2017. I'm hoping it will be more towards the latter part of the first quarter. So in addition to our organic opportunities, we believe the acquisition opportunities in the Gulf of Mexico are going to be really robust. We're seeing a lot of activity now and have a lot of hopes for the rest of the year to make some of those acquisitions. With a less competitive marketplace, we're pretty optimistic that we can find results -- or assets, rather -- that fit our pretty long-established criteria. This is one of our historic strengths. We've proven that we can identify assets with meaningful upside and complete transactions that add substantial value for our shareholders. Some of these potential transactions are significant and will have to be financed in ways that may be unconventional. So having said that, I would like to thank all of our employees for helping us navigate our way through one of the most challenging years for our Company and the industry as a whole. I appreciate everyone's hard work that has placed the Company on solid footing as we enter 2017 and beyond. With that, Operator, we can now open the lines for questions.

[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.