W&T Offshore, Inc. (NYSE:WTI) Q3 2018 Earnings Conference Call November 1, 2018 10:00 AM ET
Lisa Elliott - Principal, Dennard Lascar Associates
Tracy Krohn - Founder, Chairman, CEO & President
John Aschenbeck - Seaport Global Securities
Jay Spencer - Stifel
Jacob Gomolinski-Ekel - Morgan Stanley
Greetings, and welcome to the W&T Offshore, Inc. 2018 Third 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 with Dennard Lascar. Thank you. Ms. Elliott, you may begin.
Thank you, operator, and good morning, everyone. We're glad to have you joining us for W&T's conference call to review financial and operational results for the third quarter of 2018. Before I turn the call over to the company, I'd like to remind you that information recorded on this call speaks only as of today, November 1, 2018, and therefore, time-sensitive information may no longer be accurate as of the date of any replay. Also, please refer to the third quarter 2018 financial and operational results announcement W&T 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, and good morning, everyone, and thanks for joining us for our third quarter 2018 call. So with me today are Tom Murphy, our Chief Operations Officer; Janet Yang, our acting Chief Financial Officer; Steve Schroeder, our Chief Technical Officer; William Williford, our Vice President and General Manager, Gulf of Mexico; and Jim Hersch, our Vice President, Geosciences. They are all available to answer questions later during the call and afterwards.
So we executed very well this quarter and we accomplished a number of key corporate objectives. In addition to generating substantial free cash flow and achieving really outstanding drilling success, we launched the refinancing of our balance sheet, so which we completed after the third quarter on October 18. But before we review our third quarter results and provide an operations update, I'd like to review that very important transaction.
As most of you are aware, we had certain senior notes and 1 1/2% lien notes coming due in 2019, plus other notes due in 2020 and 2021. We had a goal of reducing our overall level of debt. So we addressed these items. And to simplify our capital structure, we issued $625 million of new 9 3/4% senior second lien notes due November 2023. The net proceeds from the issuance, along with cash on hand and borrowings on an updated revolving credit facility are being used to retire all of our previously outstanding notes. Some of the notes were tendered in response the offer we made on October 3, with the balance to be fully retired by November 19, 2018. So concurrently, we entered into a Sixth Amended and Restated Credit Agreement with a six member bank group that primarily includes banks from the prior group, but also includes one new bank. Our prior group was 20 members, which was just too many for the $150 million borrowing base that the company had before. We're pleased to be working with this new group going forward. This revolving credit facility has an increased initial borrowing base of $250 million and will mature on October 18, 2022. So we used a portion of the availability to retire outstanding notes, and currently have only $61 million in borrowings on the facility and $9.7 million of letters of credit outstanding.
We may opt to reduce the borrowings outstanding with cash flow from operations and future tax refunds that we expect to receive or we may access them for growth opportunities. So our total liquidity after issuance on October 18 was $220 million, consisting of an unrestricted cash balance of $40.8 million and $179.3 million of availability under our revolving facility.
Total debt, including the $61 million borrowed on the credit facility, is now $686 million. That's down from $903 million. As a result of this major refi, we reduced debt by $270 million, extended the maturities of our revolving credit facility and high-yield debt to 2022 and 2023, respectively, while maintaining strong liquidity in excess of $220 million. So we got plenty of dry powder.
We were able to complete this important refi because of the strength of our asset base, our inventory of low-risk projects that can quickly produced high levels of cash with the diligent, resourceful work as well as creative thinking of our team here at W&T.
This industry, ourselves included, has weathered a long and challenging oil price and gas price downturn. But throughout, the company has remained focused on generating cash, while preserving capital and reducing liabilities. That includes our P&A obligations. We're also focused on working a little smarter, trying to figure out different ways to reduce lease operating and abandonment cost and refining our inventory of projects through seismic, reprocessing and detailed analysis. Our team of geoscientists and engineers are highly experienced in the Gulf of Mexico, and they have used this industry slowdown to identify future opportunities. So we have a pretty good inventory of opportunities going forward.
So with our balance sheet now much stronger, a new $250 million borrowing base in place and a high level of really positive free cash flow being generated, we are well positioned to refocus on growth. And for W&T, the Gulf of Mexico is an excellent basin, and wish to achieve that growth whether it's with the drill bit or by acquisitions.
Before we talk about our growth opportunities, I'd like to review our results for third quarter. Production volumes were 3.4 million barrels of oil equivalent, which remains steady with the third quarter of last year and the second quarter this year. Third quarter production came in at the top of our guidance range, primarily because our midrange included cushions for those storm downtime during the quarter, which turned out to be minor. We have had storm downtime in the fourth quarter though. 61% of our third quarter production is from oil and NGLs, which is has continued to see price increases.
We're also continuing to see our average realized prices for oil, which was $69.57 for the third quarter, has tracked well with WTI benchmark price, which was $69.69 for the same period. So pretty low differentials. We benefited from the 40% increase in our realized sales price compared to the third quarter of last year. This drove revenues up $43.2 million year-over-year to $153.5 million in the third quarter. That's a lot of revenue generated on a capital budget of less than $76 million for drilling and acquisition during the first 9 months of 2018.
So our total third quarter LOE came in substantially below our guidance because we performed fewer workovers and less facilities maintenance than planned. Some of these planned activities now are scheduled for the fourth quarter and early 2019. We have delivered a lift in cost of $10.86 per BOE year-to-date 2018. Like I mentioned last quarter, we have not seen any real cost inflation to speak of in the Gulf of Mexico, such as what's been happening in the Permian.
Higher revenue and flat expense has resulted in a 264% increase in operating income compared to the same period last year and an 18% increase compared to the second quarter of this year.
So with that, adjusted EBITDA for the third quarter of 2018 was $92.2 million, that's up $35 million or 61% compared to the third quarter for 2017.
For the first 9 months of 2018, our adjusted EBITDA was $262.7 million. And that's up 34% compared to the first 9 months of last year. Our adjusted EBITDA margin was 60% for both the third quarter and first 9 months of 2018. I do keep telling markets that normal margins for us are around 60%, so I believe this is pretty compelling evidence of that.
We enhanced our cash position at the end of the third quarter to support the refinancing efforts, but it did not have a meaningful impact to our production, our cash flow or proved reserves. So as for the tax refunds of $65 million we've discussed previously, we have had some delays to the IRS on finalizing the structure of agreements, but have now come to agreement with the IRS on structures, such that we can now proceed with the committee approvals to allow that payment.
It's noteworthy that we have received 100% of prior claims, totaling $175 million, and we expect to receive these claims as well. So our 2018 drilling program is continuing to achieve excellent results in the three fields where we are concentrating most of our capital this year. This activity at Mahogany, Virgo and Ewing Bank 910, where we're drilling low-risk wells at existing infrastructure, is a key reason why we kept production volumes pretty steady. These are projects that can be drilled and put online fairly quickly, which allows for quick cash flow generation that generally shortens payback times and enhances rates of return.
In 2018, on Mahogany field, where we have put the A-17 well and A-5 sidetrack online this year, we expect to have the A-19 on production by year-end. The gross production rates for the quarter for Mahogany field averaged in excess of 9,000 barrels of oil equivalent per day as compared to around 7,250 barrels of oil equivalent per day for the second quarter, turning to positive impact for two of those completions in that field. We will talk about that a little bit more here shortly.
As we discussed on the second quarter call, the A-5 sidetrack well was placed online in mid-July and was producing from the 'Q' sand, with the 'P' sand behind pipe. So as a reminder, the A-5 sidetrack [indiscernible] well in Mahogany field that is part of the joint venture drilling program we established with outside investors, while we have a 100% working interest in all of the other Mahogany field wells, we have a 30% interest in the A-5 sidetrack. And once certain thresholds are met, our interest increases to 38.4%, although we contributed only 20% of the total CapEx for that well.
So the Mahogany field platform rig is currently completing the A-19 well, which logged exceptionally high quality T-Sand pay, updip from the T-Sand first discovered in the A-14 well. The A-19 is being completed as a T-Sand producer, and we will have multiple zones behind pipe for future exploitation. It will be our third producer in the T-Sand, which has raised our cumulative production of over 6.7 million barrels of oil equivalent per day from the reservoir. Again, a very minor pressure drawdown. We expect to have this well online before year-end.
Following the completion of the A-19 well, the platform rig will then commence drilling the A-20 well, which is a development we are targeting in the T-Sand. Again, we have 100% working interest in the A-19 and A-20 wells.
We recently drilled and completed the A-12 well at the Virgo field, which follow the A-10 sidetrack well that was put online earlier in the second quarter. The A-12 well logs 60 feet of net pay and is in the final completion stages. The rig has subsequently moved to, and is currently drilling, the Virgo A-13 well. That's an exploratory well which is expected to reach total depth in November or December, and can potentially be online by year-end or early next year.
We do have some final completion work remaining on the A-12 well that dependent upon the actual drilling rig activity. We actually have to move the rig to get to it. And we're sequencing this work during the actual drilling of the A-13 well. This work is expected to be done by mid-November when we expect to see an initial peak rate with A-12 well during the month of November. The A-10, A-12 and A-13 wells are all part of the JV Drilling Program.
So moving on to our Ewing Bank field, we're currently completing the South Timbalier 320 A-2 well in the South Timbalier 311 platform. The South Tim 320 A-2 is a successful exploratory well that log approximately 163 feet of net pay; that's exceeded pre-drill estimates. We expect to have the well on production via existing infrastructure before year-end 2018.
So following the A-2 well, the rig is expected to drill the A-3 well in South Tim 320 area, a high-quality thick Miocene sand that was penetrated up over another well, has boosted our confidence that the A-3 well is a, I think, an exploration well that's quite a quality oil prospect.
Both of these wells are in the joint venture drilling program. So in early October, Hurricane Michael formed in the Gulf of Mexico and disrupted production in the eastern portion of the Gulf of Mexico, resulting in a temporary and partial shutting of some of our eastern assets. We estimate the storm could cause total net production deferment of 44,100 barrels from October 5 to October 14. 60% of volumes to deferred was from non op assets. Key fields impacted were our Mississippi Canyon 243, Main Pass 252, Main Pass 283, Ewing 910, Neptune Field, Cognac field and Big Bend and Dantzler fields.
We have -- continue to have some mechanical issues causing production deferrals as a result of Hurricane Michael, some pressure issues and generator issues that were caused by the storm. You will also note that we have revised our full year 2018 guidance, what we think is an overabundance of caution. We've tightened our production range, which is now expected to be 13.2 million barrels of oil equivalent to 13.6 million barrels of oil equivalent. And that modestly lowers the midpoint by about 3%. From our -- that's through the beginning of next year.
So primary reason that we're talking about a different type of philosophy at Mahogany fields is that we've had some impact on -- with new completions as a function of some of the drawdowns at the wellbore interface. We produce these wells at higher production rates, but during the year, we've evolved our reservoir management practices at Mahogany. Downhole pressures are still the same. We're having a skin effect at the wellbores. We're -- we've got a little bit of IP analysis, inflow performance analysis. We're performing a more conservative drawdown practice that we believe will result in more efficient completions, less secondary stimulations and higher ultimate recoveries. Recent completion performance results are bearing this out. The A-19 will be a slightly different type of completion, and we'll be able to give you results on that in the near future.
On the cost side, good news is that we have substantially lowered our LOE guidance for this year as we continue to execute very efficiently. Our G&A guidance is up slightly, but I'm pleased with the small increase, given the amount of activities we've had this year that generated third-party professional fees, bankers, lawyers, accountants, that sort of thing.
We also realize that many analysts and investors are trying to anticipate our 2019 capital budget and production forecast. It's premature to release our budget figures at this time for 2019, but broadly speaking, at the moment, we foresee spending kind of in the range of $100 million to $150 million, not including any acquisitions. As always, we will be opportunistic and consider what will provide the best shareholder value and return. Based on this level of capital spending, production would likely be in the range of level to about 5% increased production.
So of course, acquisitions are likely to play a significant role in our future growth. The current environment for acquisitions in the Gulf of Mexico is as good as I have seen it, and we intend to actively pursue those that meet our criteria. As I mentioned earlier, our decades of experience in the Gulf give us pretty good insight into risk management, preferred geologic targets and how to optimize operating results in this basin.
Our new and improved technology is positively impacting results in the Gulf equally as much, if not more, as what is occurring onshore. We're confident that we can acquire additional producing assets at attractive valuations and add substantial value through further development and exploration. We have both the size and the E&P equation with our improved liquidity. We're looking forward to moving forward with those opportunities.
With that, operator, we can open the line for questions.
[Operator Instructions]. Our first question is from John Aschenbeck with Seaport Global Securities.
Tracy, congrats on the recent refinancing and all the hard work you guys have made over the past couple of years. Yes, so for my first one, I wanted to get you thoughts on 2019, but you pretty much addressed that in your prepared remarks. So I appreciate that color there. I did have a follow-up, just a point of clarification on my end. Kind of looking through the details of your 2019 production guidance revisions, it just seems like the majority of those changes came on the gas side, not really so much on the liquid side. I was hoping you could possibly provide some color on the driver of those changes. Was that hurricane related? Or was it perhaps something else?
Yes. I want to make it clear, I think you said 2019 guidance, I think you meant 2018. But yes, to answer your question, yes, it was a combination of hurricane guidance that helped us. We built in a little cushion for third quarter. Fourth quarter, of course we had the hurricane. We do have that built in there. There are some continuing mechanical issues that we experienced post the storm that we are trying to address now, mainly compressor rotating equipment. We are, as I mentioned, changing our production philosophy at Mahogany just a little bit in hopes of solving some of these skin issues that we're having at the wellbore interface with formation. We're doing the IP analysis, the inflow performance analysis now. We've done some treatments on a couple of these wells. We've had pretty good success for the most part. We're trying to get a more formulaic approach to that. So we're slowing the production deliberately to reduce the drawdown into the end of the wellbore, although production is up in the field from 7,200 barrels a day to about 9,000 barrels of oil equivalent per day. So production is up, but we're being careful with some of these other wells because it looks like we've got some issues at the wellbore interface that can be treated, and that we're just trying to figure out ways to eliminate it so we don't have to treat it going forward.
Okay. Great. Great color there. Appreciate that. Then last one for me. More of a high-level question. Now that you have the refinancing behind you, I was hoping you could share with us what you're most excited about in terms of, let's call it, day-to-day activity, whether that be on the operations front or in terms of potential acquisitions or something else.
Yes. Well, I think it's a really good market for acquisitions right now. And clearly, we're -- as a result of the drilling joint venture, we're looking at a pretty good quality prospect inventory that's fairly mature. We've got, I don't know, about 50 prospects right now that are fairly mature that we expect to drill. And we're working on that budget now. And we are seeing some of the properties out there that we think will meet our criteria. And I'll just say that one more time: we look for cash flow, we look for upside that we can use the drill bit to increase the value of these fields. And then we look for production workovers and facility upgrades that we can do along with that.
Great. Awesome. And actually, just to dig into that one a little bit more. I was hoping you can share your thoughts just on the longer-term strategy here. I agree, it seems like a buyer's market right now on the Gulf. A good time to be active on the buy side. But just, as you look at this thing longer term, how do you see the company evolving, maturing and then -- I don't know if I'm getting too far ahead of myself here -- but just a potential exit strategy? Or just how do you see the whole story playing out longer term?
Well, fair question. I actually believe that we'll see more acquisitions. We will see M&A increase in this marketplace. The acquisitions help drive the drilling side of it, both on development wells and exploratory wells. So we've cleaned up the balance sheet. We're cash flow positive with existing operations. We're accumulating cash. We've reduced the debt. We've got dry powder to make more acquisitions. I do expect to make more. Whether it's acquisitions by nature of assets or corporate-type acquisitions is immaterial to me, it's still assets that we're thinking about. So that's kind of the plan going forward. They're opportunistic. But I expect to see large changes in the corporation over the next 12 months.
Our next question is from Jay Spencer with Stifel.
Congrats on a solid quarter and the refi. And then I appreciate the guidance -- or the rough guidance or rough thoughts you guys have given on 2019. Clearly, the trend with LOE is down. Just -- I wanted to see if you guys could expand on if you think that'll continue? And do you think you're able to lock in some of that? Or is that not really a possibility? Just kind of want to get a sense on this momentum, the decline in LOE?
Yes. Locking it in is a harder approach, but we do have a little bit of that with some of our vendors. And I do see, going forward, that really -- there's nothing that says that prices have to continue going down. But prices going up is not something that I see in the near future. Clearly, I mean, oil got up to $70-something a barrel and we had a pretty rough time the last couple of weeks. And we've seen that once before this year already. So I think that we've got a fairly recurrent pattern. I think vendors are reticent to increased prices, except on seasonal equipment rigs and boats that are required in certain areas, which are certainly the highest cash cost items. But I keep thinking that we're about level where we should be. Like some of it -- that we're seeing on the LOE side has to do with maintenance and on platforms that we own, rotating equipment, some domain that we have to replace and we're addressing those to try to make that a little bit more efficient. We did reduce our P&A expenditures through the year. But that was intentional as a result of actions that we took in '16 and '17 to accelerate plug and abandon activity. So that now going forward, we see that as a lower number. So we can focus on those dollars on -- for the next several years, on things that actually make us money instead of things that we spend money on. So we're proud of that decision we made a couple of years ago to get that done. I don't think that, at the moment, we're seeing much price creep. We're going into winter now, so I expect prices for rigs and boats to lower slightly, and then I expect to see them raise slightly in the spring and summer months next year.
[Operator Instructions]. Our next question is from Jacob Gomolinski-Ekel with Morgan Stanley.
Just wanted -- maybe a little bit more of a procedure or administrative question, but when do you expect to receive that $65 million payment from the IRS? And then maybe just more broadly, you obviously continue to generate a fair amount of cash flow when you talk -- when you're kind of using current EBITDA numbers. So currently, so curious how you think about uses for free cash flow going forward? I know you mentioned M&A opportunities. So it'd be great to hear about sort of -- I know you talked a little about criteria on that front, but just generally, thoughts around uses for free cash flow and when do you expect to get that IRS payment?
Yes. Right now, we're targeting end of first quarter on the IRS credits. So hopefully, that's when it occurs. I mean, they have a procedure, but the good news around that is that with the $175 million of claims so far that have been completely refunded to us, we believe that there's 100% likelihood that we'll get paid on this. We just don't necessarily have the exact dates on that. But right now, we're targeting the end of first quarter. As far as what we're going to do with the money, we'll -- certainly, if there's nothing pending at the moment, then we will use that to reduce any revolver debt that we have, we'll probably have that revolver debt reduced by that time to almost zero anyway. But in the event that we have some other uses for drilling opportunities or acquisition opportunities, then that's what we have the new revolver for, which we've increased about, I think -- well, exactly $100 million on the borrowing base for that. So that's kind of where we are right now. I think it's a good acquisition market, and I think that we'll get our fair share going forward.
Got it. And then just maybe -- I know you talked a little bit about it, but either initial thoughts on sort of 2019 CapEx plans and production growth targets or if that's not been budgeted yet, then maybe sort of when you expect to share those numbers?
Yes, we haven't finished with that budget action yet. We were somewhat delayed as a result of the refi. So I had kind of all hands on that, working on that. But I expect that we'll have it out by about the normal time, around the end of January, first part of February for that budget. Right now, we're thinking $100 million to $150 million, and that will keep us level to about 5% increased production for 2019.
Mr. Krohn, there are no further questions at this time. I would like to turn the floor back over to you for closing comments.
That's all I have, operator. I appreciate everybody listening in. And I think we had a really good quarter. We look forward to talking to you in the near future.
Ladies and gentlemen, thank you for your participation. This does conclude today's teleconference. You may disconnect your lines, and have a wonderful day.