W&T Offshore, Inc. (WTI) Q3 2015 Earnings Report, Transcript and Summary

Greetings and welcome to the W&T Offshore Third Quarter 2015 Earnings Conference Call. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. [Operator Instructions] As a reminder, this teleconference is being recorded. It is now my pleasure to introduce your host, Ms. Lisa Elliott. Thank you. Ms. Elliot, 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 third quarter of 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 November 12. To use the replay feature, call 201-612-7415 and dial the pass code 13622343. Information reported on this call speaks only as of today, November 5, 2015 and therefore time-sensitive information may no longer be accurate as of the date of any replay. And please refer to the third quarter 2015 financial results announcement we released yesterday for a disclosure on forward-looking statements. At this time, I would like to turn the call over to Mr. Tracy Krohn, W&T’s Chairman and CEO.

Thank you, Lisa. Good morning, everyone. Thank you for joining us for our third quarter 2015 conference call. Joining me this morning is Jamie Vazquez, our President; Danny Gibbons, our Chief Financial Officer; Tom Murphy, our Chief Operations Officer; and Steve Schroeder, our Chief Technical Officer. I am going to provide an update on our key operations and then we will be happy to address questions. You can find a detailed financial and operations review in the news release we put out yesterday evening and we expect to file our third quarter Form 10-Q soon. So, I would like to begin this call by mentioning two high impact items first. We have completed the sale of our Yellow Rose field in the Permian Basin for $376.1 million that allowed us to payoff our entire revolving bank credit facility and add a $100 million to our cash balance. Second, our Rio Grande Loop, which includes the Big Bend and Dantzler deepwater oil projects, commenced initial production in late October. These are world class oil fields. So, we had a very solid third quarter operationally, with production holding steady and coming in at the top of our guidance range for the period. Production for the quarter averaged approximately 46,800 barrels of oil equivalent per day, including two wells in our Medusa field coming online to offset natural production decline. Oil production as a percentage of total volumes increased over 12% compared to last year’s third quarter, while NGLs and natural gas production volumes were lower. As you know, over the last few years, we have dedicated resources to more oil dominated projects and this shows the result of those efforts. One of the benefits of operating in the Gulf of Mexico is it is an area with quality oil and natural gas projects and good cash flow. We believe we have done an excellent job over the years of identifying and successfully developing higher economic impact oil projects in the Gulf and 55% of our third quarter 2015 production came from crude oil, condensate and NGLs. As we announced last week, the Big Bend field achieved first production on October 26 and has achieved a peak rate so far in excess of 20,000 barrels of oil equivalent per day gross, with over than 91% production being oil. If you will recall, we had a 20% working interest in that field. In addition, first oil from the Dantzler field reached the Thunder Hawk platform over this past weekend, ahead of our previous expectations and ahead of our plan set out in early 2015. With the discovery of Big Bend, a little less than three years ago and then a year later adding the Dantzler discovery about 12 miles away, we have created an epicenter for two high value assets. It’s been gratifying to see the co-development of these two world class and prolific fields coming to completion in a relatively short amount of time and on budget. These two wells – these two fields were co-developed via our Rio Grande Loop system and are tied back to the third-party Thunder Hawk production facility. We expect production from the Rio Grande Loop system to be variable over the next month or so as completions are tested and production has ramped up. The two Dantzler wells are both duly completed subsea wells that were produced from multiple reservoirs in each well. First production rates from Dantzler should be achieved by year end. We continue to estimate that the combined production from both fields will be at a peak rate of around 8,000 barrels oil equivalent per day net to our 20% working interest with about 81% oil. If both fields continue the positive trend that we have seen so far, we could see rates in excess of this estimate. So, W&T will be exiting 2015 with substantially higher production rate and expect to be above 50,000 barrels of oil equivalent per day in December. And with both of these fields primarily producing oil, our percentage of production for oil will of course climb even further. So, another project that’s expected to contribute additional near-term oil production is our Ewing Bank 910 field, the South Tim 320 85 sidetrack well, the first exploration well in a two-well program of the Ewing Bank 910 field was completed and is currently flowing at a growth rate of 2,150 barrels of oil equivalent per day or 900 Boe per day net to W&T. Production from this field is predominantly crude oil. The platform rig is currently on location drilling the second well the Ewing Bank’s 954 88 and is expected to reach total target depth of 23,200 feet around the end of November. We do have high expectations for the second well based on the seismic data and we anticipate having the second well on production by the end of the year. So, on the expense side, third quarter expenses came in substantially below our guidance range. We had year-over-year and sequential declines in all expense categories. We are guiding the expenses down further for the fourth quarter. The sale of the Yellow Rose plus reduced activity and lower cost of goods and services is driving down our expenses. Third quarter lease operating expenses were down $26.7 million, or 37% compared to last year, G&A decreased $4.5 million or over 21%. Our average realized sales price for the third quarter was $28.92 per barrel oil equivalent, that’s down from $54.13 per barrel oil equivalent in the third quarter of 2014. So, we will continue to push down costs where we can. Adjusted EBITDA for the third quarter of 2015 was $59.2 million and our adjusted EBITDA margin was 47% for the third quarter of 2015. Year-to-date, our adjusted EBITDA was $187.3 million and our adjusted EBITDA margin was 46%. And also year-to-date, our capital expenditures have been $192 million and we expect our fourth quarter expenditures will be approximately $29 million. Our CapEx will be a little bit higher than budget as development work has occurred for all the successful wells we had in 2015. We budget on our risk-based outcome with a 100% success rate offshore with drillbit in 2015. We simply needed additional capital for the completions and bring the wells online. So, it’s a quality problem. We are pleased to be able to manage this successfully. Our large cornerstone capital project, the Rio Grande Loop system will actually come in slightly below our initial cost estimates. Furthermore, the closing of the sale of our Yellow Rose field in West Texas has allowed us to repay all outstanding borrowings under our revolving bank credit facility. Remaining $100 million of cash proceeds is available to fund future operations, acquisitions or bond repurchases. Effective October 30, we amended our revolving bank credit facility to change or eliminate various financial covenants and allow us to repurchase outstanding indebtedness if certain specific conditions are met. The amended bank credit facility is at the borrowing base of $350 million. Our liquidity following the sale of the Yellow Rose field and the credit facility amendment is currently in excess of $485 million. So, our focus over the near-term will be to continue to control our capital outlays and operating expenses. With our improved liquidity, we will also continue to pursue opportunities that add value at current prices whether they are through acquisitions or the drillbit. So, that concludes my prepared remarks. Operator, with that, we can open the phone lines for questions.

Thank you. [Operator Instructions] Our first question comes from the line of Noel Parks with Ladenburg Thalmann. Please proceed with your question.

Good morning.

Good morning Noel.

I wanted to ask about the expenses, as you have pointed out they were lower than guidance and headed down. I was just wondering for the fourth quarter, how much of that is related to just the different expense mix with Yellow Rose out of the picture?

I am not quite sure I understand your question. I think you are asking me to segregate Yellow Rose from the expense profile, is that right?

Right. Just which item – I am assuming it had maybe more of an effect on D&A?

No, not really. What occurred was in the Yellow Rose, we were having some recurring expense with workovers and rod pumps and that sort of thing. So that would be the majority of the expanse associated with the Yellow Rose. To quantify that, I don’t know probably $4 million or $5 million a month. I am sorry excuse me, I mean for the quarter.

Okay, for the quarter. Okay, great. And just looking ahead a little bit, where we are with the pricing environment and everything, I was wondering, heading into next year, has there been any particular change for us to be aware of as far as any featured deepwater development drilling?

No, not at this point, we are still in the process of doing our 2016 budget. So we are sorting that out. We have obviously, we are a little bit preoccupied getting the sale done. But I think that we are more exploration oriented in 2016 than we are on development well oriented.

Okay, great. Thank you.

Deepwater. Thank you.

Thank you. Our next question comes from the line of Ravi Kamath with Seaport Global. Sir, please proceed with your question.

Yes. Hi guys. One quick question on the amendments to be able to repurchase bonds, can you quantify how much you would be allowed to repurchase and what the conditions are? Thank you.

The answer is we have the opportunity to do up to $100 million.

And under what conditions?

The conditions are no funded debt, the borrowing base has to be at a certain level and there is a limitation on the amount of LCs that are outstanding at the time.

Limitation on LCs, great. And then secondly, it looks like your current portion of ARO, I think went up to $84 million, $85 million, is that the kind of expectation for P&A spending over the next 12 months?

Well, it is, that’s what we actually put in current liabilities at any point in time as the expectation over the next 12 months. We had some projects that come into focus in the third quarter of 2016. So, they went from long-term to current and that’s what the change was.

Understood, great. Thank you. Great quarter guys.

Thank you.

Thank you. Our next question comes from the line of Jon Evans with JWest LLC. Please proceed with your question.

Tracy, I know you – that you said that you are still in the midst of thinking about your budget for 2016, but I am curious can you give us a sense, will you try to stay within cash flow or kind of maybe what you are trying to do, I am curious?

Now the short answer to that is, yes and of course that’s going to be easier this year because we are not doing the forward spend for all the deepwater development.

Okay, great. And then the other question that I had for you is just relative to acquisitions, I guess how would you think about funding an acquisition?

Well, that’s always Jon, a function of the type of acquisitions which you have. So the first thing you look at is the cash flow and that’s going to determine a lot about how you fund it, preferably we would like to fund it with our bank credit facility first, because that’s our lower source of capital, so we will have $350 million of revolver right now. And of course you may be able to add some to that based on what the merits of the acquisition are.

Okay. And then just a follow-up to that, on the acquisition side I assume if you did buy something, you would buy something that’s a producing asset that has the ability to have upsides from the drill bit, is that kind of the formula you are looking for?

Yes, absolutely. It always has been cash flow, little upside from the drill bit. Was there any low hanging fruit that the previous operator had that might include workovers, recompletions or facilities upgrade that will also increases the capital income and also reduce expenses. Those three things are arranged in a systematic with the right price, yes.

Yes, right, exactly. And then the last question I have for you is just, how much of potentially the facility would you guys be willing to use to make an acquisition, so you have $100 million in cash roughly or you have $350 million on the debt side…?

Yes, I mean that would depend upon the acquisition. The first thing you look at is cash flow, so if it made sense, we would use all of it.

Okay. And can you give us a sense of kind of where pricing is out there roughly, is it 10…?

Well, the NYMEX right now is hovering around $46 a barrel. As far as predictions going into the – as far as projections going into the future and we will run sensitivities on it up and down from there. Of course, to determine what we think our capital budget needs to be, yes. Go ahead.

Prices. I am sorry, I didn’t ask the question very well. Prices, if you paid for an acquisition, are you paying about $20 a barrel or?

Again, these are all hybrids. They can fluctuate based on what the cash flows are and what kind of reserve base you have, is it mostly proved producing or proved developed or is it mostly proved undeveloped [indiscernible] that sort of thing. So, I can't give you a specific dollar amount. Okay. Thanks.

[Operator Instructions] Our next question comes from the line of Jason Burns with [indiscernible]. Please proceed with your questions.

Hi guys. So just going back to the conditions required to buyback bonds, do you currently meet those conditions as we stand today?

Yes.

Okay. And will that credit agreement amendment be disclosed shortly in an 8-K or something?

Yes. I think maybe a day or so. Yes, soon.

Okay. And then in terms of your borrowing base, it’s been reduced for the Permian sale. However, you now have production coming online this quarter from Big Bend and Dantzler, what can we expect in terms of borrowing base redetermination AFO, would you expect to claw back some of that reduction?

Well, first of all you have to tell me what the price of oil is going to be and the price of gas will be, and then I can give you a more accurate reflection. And also of course, what we have done in the interim with regard to that borrowing base.

Okay. What is your current expectation at the current price strip however, can you give some sort of indication where you think your borrowing base would be?

Well, yes, we just did Jason, I don’t mean to be flippant here, its $350 million. And of course we have got another $100 million or so in cash. So you look at $450 million of dry powder that’s the liquidity, actually it’s around $485 million, that’s the amount of liquidity, we have and as to what you would borrow on top of that would be a function of the quality of the acquisitions that you were able to obtain.

Sure. And so, it seems like the operations and production out of Big Bend has been pretty favorable thus far and Dantzler obviously coming online pretty soon. Can you talk about the opportunity to drill other wells that would offset that next year and how the kind of the agreement with Noble would be, like if they were to tender an offer, would you guys take it, etcetera?

Well, the way it works these days, we have a joint operating agreement. We have actually talked about drilling additional wells at Big Bend and Dantzler already. We opted as a group to get a little production information first, so that we can determine drive mechanisms and what we would need to do in the future. That will play a big role in what we think we will have going forward. So, based on that, we will make additional plans for development and/or exploration in both of those fields.

Okay. And then my final question, you made a comment in your release that you have eliminated or amended financial covenants. Can you go into a little bit more detail there? Have you – is there anything that is at risk of being breached over the next 12 to 24 months at the current price?

The answer to that is no, there is nothing that’s in danger of being breached over the next 12 months or so. Obviously, continued low prices doesn’t help us or anybody else in our business, the most of the covenants that were amended were ratio tests.

Alright, thank you very much.

Sure. Thank you.

Thank you. Our next question comes from the line of John Aschenbeck with Seaport Global. Please proceed with your questions.

Good morning, everyone. Most of my questions have already been answered, but I did have one here on the Permian and that is how should we think about the value of the residual overrides you have left there or maybe to ask it another way how are you guys thinking about it?

Yes. Well, we have looked at it as additional cash flow in the future. Obviously, the way it’s setup is that the more production we get or the more production they get, the more wells they drill, then the more revenue we will obtain. When we sold the Yellow Rose, we had done a, what I thought was a pretty good job of identifying what the horizontal program needed to be and also the fact that we have several benches in the field. So, we had all those leases held by production. We spent a lot of money getting ourselves in a position to hold all the leases and we spent a good bit of money doing all of the horizontal testing. So, by the time that we were ready to sell or by the time that we did sell it the next operator was in a good position to go out and drill some more wells. So, they could focus their attention on drilling additional wells and hopefully that will increase the value of the override by volume and then the rest of it is by sliding scale on the price of oil. So, if price of oil goes up, our overriding royalty interest goes up. Above $70 a barrel, it goes to 2.5% and above $80 a barrel or so it goes to 3.5% and then above $90, 4% or so, yes.

Yes, it sounds like a good deal. I appreciate the color.

Well, we thought it was a good deal for everyone.

Thank you. Our next question comes from the line of Jon Evans with JWest. Please proceed with your questions.

Yes. Tracy, just a couple follow-up questions. Could you give us – you have talked before about kind of the 60% EBITDA margins that you guys have worked with over time? Can you give us your thoughts and opinions right now where you see service cost and do you see that opportunity in this price environment to be able to get that with the drill bit going forward as you go into ‘16?

I am not sure if I see all the way to the end of the tunnel on getting those margins with just a reduction of the cost of goods and services and LOEs. We are coming down, we continue to come down, vendors and our subcontractors or whatnot, are all working now earnestly to reduce their pricing to us, because the trickle down has become, now they can get better projects and better margins on their equipment and their services. So, over time, it will have to approach something that will be more in line with the reduction in the price of oil. So, that’s what we see in these downturns and the longer they are, the closer you get to the dollar per dollar reduction in cost of goods and services as a function of the lowering of the price of oil.

Great. And then you guys have done a great job on the cost side, much better than a lot of people thought you guys could do. You gave guidance for the fourth quarter being down again. As you look into ‘16, is there any more blood to squeeze out of that turn up or have you done basically everything you can do besides service costs?

What we would always like to think is there is little more blood in it, but at the same time, you have to be a little bit realistic. I mean, as soon as you get to that magic number of parity with the lowering in the price of your hydrocarbon product. Then I think you are pretty much done. There are of course efficiencies that you can do with the properties and locations and optimizing transportation. We have spent a lot of time in the last few weeks looking at transportation costs again and we expect that, that will go down lower as well.

And then the last follow-up, relative to the Permian residual, will that be in the revenue line or will you actually have another line maybe below that will just be the residual that comes in, so we will be able to see that directly?

That will be in the revenue line probably. We probably won’t isolate that.

Okay, thank you. Have a nice day.

Thank you.

Thank you. And that’s all the time we have for questions today. I would like to turn the floor back to Mr. Krohn for closing comments.

Yes, thank you very much, operator. That’s about all I have for today. We look forward talking to you next time. Thanks so much.