W&T Offshore, Inc. (WTI) Q4 2015 Earnings Report, Transcript and Summary

Greetings and welcome to the W&T Offshore Fourth Quarter Earnings Conference Call. At this time, all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation. [Operator Instructions] As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Lisa Elliott. Please go ahead Ms. Elliot.

Thank you, operator and 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 that I would 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 March 16. To use the replay feature, call 201-612-7415 and dial the pass code 13629410. Information reported on this call speaks only as of today, March 09, 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 the question and we will be filing our Form 10-K with more details in a day or so. So throughout last year 2015 we focused on completing the projects that were already in progress at the beginning of the year or that we're committed to with partners' projects like Big Bend and Dantzler with two Medusa wells in the Ewing Bank 910 project. Once we have 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 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 and set at about $15 million not including plug abandonment activities. It includes the completion of the A-8 well Ewing Bank's 954, which came online this month, but no other new wells are currently planned in 2016. Based on the high volume of production editions from our recently developed projects, we had expected only very modest decline in production in 2016 over 2015, where crude oil production basically flat. However, due to unplanned pipeline outrages and maintenance and some unexpected well performance issues, we now expect production to be approximately 4 Bcfe lower than our initial expectation. Thus 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 like late October and early November, respectively as reflected in our strong production volumes. In 2015 we made three significant deepwater discoveries that were all brought on production then a few months of reaching total depth as the wells were drilled from infrastructure. Two new discovered wells in our Medusa field and one was our Ewing Banks 910 platform. These three projects are predominately crude oil producers, which is one of reasons that we have been able to increase crude oil production year-over-year. The forward spending in the deepwater in previous year has ultimately started to pay-off. So our track record for achieving, 100% exploration success rate is no accident to almost three years. We've also done an excellent job of evaluating non operating drilling prospects and choosing the right operating partners. We are finding high quality in substantial deepwater projects near or relatively near existing infrastructure, which can be bought on production quickly. This is an important trend. While the Big Bend and Dantzler wells require about two years to be put on where you developed very quickly and put on line ahead of schedule and on budget. More importantly, they achieve their expected peak production rate well over 6,000 barrels oil per day gross and are still maintaining steady levels with only the small decline from the peak. We also see additional production starting in March from Ewing Banks 958 A-8 well drilled from our Ewing Banks 910 platform. This well was completed in two zones. As a reminder, the A-8 discovery well reached total depth in December and penetrated the total of 150 feet measured depth hydrocarbon pay contained into sands. It was a follow up well to the South Tim 320 A-5 Sidetrack discovery that was completed in June 2015. The A-8 well has achieved a gross initial production right from the lower sand completion of approximately 3500 barrels of oil equivalent per day and is still cleaning up. We are actually taken the rig off the platform as we speak. As we mentioned in yesterday's press release, we also completed the second zone in the well. It was actually the primary and larger target zone and planned to place this second zone on production later as a lower zone depletes so will move from the bottom up. We continue to believe the field offers additional opportunities, which for a future drilling when prices recover a bit and margins improve. Now that the A-8 is completed in online, we have no other new expiration 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 [78%] [ph] decline that we have seen in good 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 45% decline the average realized sales price we received per barrel of oil equivalent. Reductions in prices that we saw on the back half of 2015 have deteriorated further so far in the 2016. EBITDA and EBITDA margins 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 a 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 and improved results as well. Excluding the results attributable to Yellow Rose field sold in October, year-end 2015 proved results 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 results by $10.7 million barrels equivalent and 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 of oil equivalent, extensions and discoveries added $4.1 million barrels of oil equivalent from - and we added 1 million barrels of oil equivalent from purchases. If not for the price decline, we would have 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 and the solid performance from some of our established properties. We had positive revisions from over 13 fields including a small contributions from Big Bend based up revision came from our Ship Shoal 349 Mahogany Field. Other increases came from Fairway, Matterhorn, Neptune and Tahoe and our Brazos A-133 field. The reserve extensions and discoveries of primary associates with Medusa and Ewing Banks 910 field. So in 2016, we will stay focused on managing our expenses we did throughout 2015. As an example our lease operating expenses decreased 35% in the fourth quarter compared to the fourth quarter of 2014 and were down 27% for the full year. G&A was down 29% in the fourth 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 in not only LOE and G&A expenses but also plug and abandonment cost as well. Right since we forecasted just a month or so ago it has been $84 million on P&A in 2016. And I think there is some work can be down from as little as $65 million for reduction of 23%. Our 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 and we accomplished a lot in 2015 to enhance our financial flexibility. So we suspended our common stock dividend in early 2015, April and October, we remitted our revolving bank credit facility and modified or eliminated financial covenants. In May we obtained a five year $300 million term loan financing to boost our liquidity and this borrowing is outstanding under our revolving bank credit facility, a timing could have been better with that transaction. In October we repaid the balance for our bank borrowings with the proceeds from a sale of our Yellow Rose fields and West Texas for $372.9 million and enhanced our cash balance by $100 million. In February 2016 we drew $340 million on our revolving bank credit facility to maximize our liquidity and assure we navigate through these industry headwinds. The company's cash balance subsequent to withdrawal was $447 million. We also hired those legal and financial advisors to assist the board and management as we work through a challenging market conditions. So, on this commodity price environment we believe that maximizing liquidity and adjusting our capital structure to remain in compliance through our financial covenant is essential. We are maintaining an active dialogue with our lenders and evaluating our options. Our spring borrowing base with determination process is currently in progress and 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 disclosed, we have been discussions with the U.S. Department of the Interiors Bureau of Ocean Energy Management BOEM regarding certain supplemental binding requirements for 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 and the amount of $260.8 million to cover obligations under certain federal offshore oil and gas leases operated by the company. So the issuance of any additional surety BOEM satisfy this order or any future orders could require the positing of cash collateral which could be substantial. We intend to continue our discussions with the BOEM to resolve these issues and if afterwards review this order the company mean to necessary and appropriate we may exercise our right to appeal the Interior Board of Land Appeals or otherwise challenge this order. Separate from the BOEM actions, we set a budget for 2016 plugged and abandonment activities of $84 million but as I said earlier now I think we can perform that same work for around $65 million. Over the last three plus decades and through several market cycles we built a track record for acquiring producing Gulf of Mexico assets favorable valuations and successfully exploring the upside opportunities that we've identified. Those opportunities will continue to be there but we need navigate carefully to take advantage of those opportunities. There is always we look for quality producing assets with bankable reserves. We then apply our expertise and now to the Gulf of Mexico to assess the upside potential of those assets that's key ingredient. And of course we need to get priced right on that purchase. Our team of geoscientists who we believe our experts about the Gulf of Mexico will continue to analyze the advanced stages that we have obtained to high grade our inventory of drilling opportunities, evaluate the well data recently drilled projects and identify potential exploration exportation, expansion projects. So on to the current market conditions we don’t think direct in capital is drill bit is necessarily the right decision. We do hold a substantial amount of qualitative acreage by production we believe as some of it is additional upside potential and including projects that could be impactful. Other things that we might consider under these circumstances are farm-outs, joint venture opportunities, asset sales, acquisitions just to name a few. So WT has some great assets. We’re working hard to make sure we take full advantages of those assets in the future. I can promise you there is a majority own of guarantee this is very personal. So with that operator, we can now open it up for questions.

[Operator Instructions] Our first question today is coming from John Aschenbeck from Seaport Global. Please proceed with your question.

Hi, thanks for taking my question here. I was hoping you could quantify what we should expect coming out of redetermination fees and any idea 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 to that I want to impart to the market at this point in time as it could be wrong.

Okay, that's fair enough. And 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. A – Tracy Krohn: Sure.

One follow up for me is, in regard to the additional 261 in BOEM bonding, how do you think that will impact liquidity? Yet any idea of what amount of cash or letters of credit you’ll have for that?

We’re 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. And we expect it will continue going forward. Certainly, it has an effect on liquidity and that is a concern for us.

Okay. Really appreciate that. I’ll jump back in the queue. Thanks.

Thank you. Our next question today is coming from Richard Tullis from Capital One Securities. Please proceed with your question.

Hi, thanks. Good morning everyone. Tracy, I understand the- certainly understand the rationale for the $15 million drilling in completion budget this year. What sort of impact you foresee that it could have on 2017 production? Or what you’re looking at, say, 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 is 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 could give a blow down case, but that would be outside our normal period of guidance.

What is the set of base production decline rate for the overall production, oil production at this point including the new projects online?

This year, it looks like we are about 7% to 8% down on production. That's, kind of where we are looking at.

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

That's a great question and people always ask me about the oil pricing and what I always respond 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. The cost of goods and services play a huge role in what we can afford to drill, and exploit in oil purchase. So currently margins were about 44%, I believe for last year. And they are normally around 60%. So we'd like to see the margins being closer to 60%, for 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 and of course, as you're seeing 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, we will continue to have ceiling impairments and the cost of goods and services needs to catch up with that. So there is still that disparity cost of goods and services. The good news is we're seeing cost of goods and services decelerate in that sense, prices are going down for cost of goods and services.

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

Thank you. Our next question today is coming from Noel Parks from Ladenburg Thalmann. Please proceed with your question.

Good morning. Just had a question about the expense guidance. I was looking at the first quarter items versus the full year. And with the LOE and the gathering lines, is there a ramp up assumption embedded in the quarter? I’m looking those usually more on a unit basis, or is just - we’re just seeing fixed expenses being carryover across the basic line of production?

No. You’re correct. There is a bit of ramp up. And that's because of seasonality. We generally tend to go back - 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 little worse in those appearances - if these are still working in the better weather months.

Great, thanks. And roughly whether in the quarter or currently, the bands were in Big Bend production, where does it stand roughly?

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

Okay, great. That's all for me.

Thank you. Your next question is coming from Steven Karpel from Credit Suisse. Please proceed with your question.

Good morning, Tracy. I was trying to understand with the bonding point that $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 - the surety - talking with surety fund providers is 260, a very achievable number that doesn't require you to go outside of that i.e. post direct fashion in lieu of.

I can tell you that the surety bond market has closed. It's gotten very tight and the reason is because the OEM is expecting bonding from everybody now. That's their stated mission. And so that market has gotten a lot tighter. I guess it's probably not I could say it's absolutely closed. It hasn't. But as far as I can tell is really very narrow right now. Our sureties are somewhat nervous about their exposures. So yes, that's been a problem for not just as per other companies.

So then the follow up to that is, what does that mean for existing surety bonds that are already outstanding. And then secondly, what does that mean or 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 and not only with us, but other companies to resolve different methods of allowing for abandonment. And there are different ways to manage that and we are having those discussions with them as we go through this cycle.

And just - then maybe I'll ask qualitative point of view comment. Does the BOEM grasp the magnitude of the issue with - on individual companies? And what that means to the market? Thank you.

The short answer to that is they have a lot of data to work through. And I think they understand the magnitude of the issue. I'm not sure that everybody is quite on the same wavelength and seldom are you 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 have had to deal with. The other problem that they've had is that they have a lot of temporary directors rotating in and out of the office in New Orleans. And that's made it more difficult to solve some of the problems that need to be there. Apparently, we have 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 situation we have a little bit of permanency and in that position.

Thank you.

[Operator Instructions] Our next question is coming from Jon Evans from JWest. Please proceed with your question.

Hi Tracy, I was hoping maybe you could elaborate a little bit more about the production issues that you had coming in the fourth quarter did you. In the third quarter, you averaged about 46, 47 a day. I mean if you take out the sale that was about 23. And if you know you brought on eight from Big Bend. So can you just help us understand the pipeline issues and maybe what others usually have?

Yes, one of them was scheduled and in fact we are in the middle of that right now - its beside, pipeline scheduled maintenance and then one of them was unscheduled that serviced our field a little bit closer to around Ship Shoal. That repair has been completed but preside is now that - that affects our Mahogany field as well. So big chunk of production there that's down for probably total is about 2 weeks. And so hopefully that answers your question.

And then did you have any other problems with any of your existing wells, you kind of alluded to that in your comments or I just heard you wrong, I apologize.

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

And just the follow up to that, I mean you feel like you guys will be able to bring that back on or give any insight? A – Tracy Krohn: 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 along the on the well side itself. So, we are working to not have to use intervention vessel and we think we are having some moderate success with that. So as long as we can do that, that’s the direction we will hit.

Okay. Thank you for your time.

Thank you. The next question is a follow up from John Aschenbeck from Seaport Global. Please proceed with your question.

Thanks. 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 or perhaps even a significant asset sale that help right size the balance sheet.

Well, okay, I could talk a lot about that, do you have something specific you want to answer.

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

The short answer is, the run way is a function of not 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. Our margins is a function of cost of goods and services as well. So, clearly if prices stay down for a longer period of time than that will put more risk in the equation. If prices go up and obviously that makes it better for us and clearly if the cost of goods and services will margin lockstep with pricing i.e. go down then that will extend that run way as well. Clearly we recognize we have a debt issues that needs to solved and we've hired advisors 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 beyond that front. So really appreciate the color there.

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

Well, operator that's all I have. We'll talk again in the not too distant future. Thanks so much.

Thank you. So this concludes today's teleconference. You may disconnect your line at this time and have a wonderful day. We thank you for your participation today.