W&T Offshore Inc (WTI) 2018 Q1 法說會逐字稿

Greetings, and welcome to the W&T Offshore, Inc. first quarter earnings conference call. (Operator Instructions) As a reminder, this conference is being recorded.

I would now like to turn the conference over to your host, Lisa Elliott with Dennard Lascar, Investor Relations. Please go ahead.

Thank you, operator, and good morning, everyone. We're glad to have you join us on W&T Offshore's conference call to review financial and operational results for the first 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, May 3, 2018, and therefore, time-sensitive information may no longer be accurate as of the date of a replay. Also, please refer to the first quarter 2018 financial and operational results announcement W&T released yesterday for a discussion on forward-looking statements and reconciliation 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.

Thanks, Lisa. I can't believe it's 3rd of May already. So good morning, everyone. Thanks for joining us today. With me this morning are Tom Murphy, our Chief Operations Officer; Danny Gibbons, our Chief Financial Officer; Steve Schroeder, our Chief Technical Officer; and Janet Yang, our Vice President of Business and Corporate Development. They're going to be available to answer questions later on during this call.

So it's been a busy last couple of months since our fourth quarter call. On March 12, we entered into various agreements with 2 initial investors to drill up to 14 specified projects in the Gulf of Mexico over the next 3 years. I'll refer to this as our joint venture drilling program. The transaction is structured such that we initially received 30% of the revenues contributing 20% of the cost of each project plus associated leases and providing access to the available infrastructure.

Once investors receive certain threshold, we'll receive about 38% of the economics on a well-by-well basis. The lead investor in the JV drilling program is an entity owned and controlled by funds managed by HarbourVest Partners, a Boston-based equity fund sponsor with over $40 billion of assets under management.

The other initial investors are W&T, a minority investment by an entity owned and controlled by myself. The Krohn entity invested on the same terms and conditions as with HarbourVest and is limited to 4% of total invested capital to all parties. Since the initial closing, we've had a second closing, we brought in additional investors, including Baker Hughes GE, and we expect to have a third closing in the relatively near future.

W&T contributed 88.94% of its working interest in 14 different projects to Monza Energy LLC, which is the newly created partnership to hold the contributed interest. W&T retained an 11.06% working interest in each project contributed. The joint venture drilling program allows us to accelerate the development of our high-return inventory with reduced capital outlay.

We're contributing leases with drilling prospects, along with the -- with the operations. So we believe this JV drilling program greatly enhances our financial flexibility to manage our balance sheet and to pursue additional accretive acquisition opportunities in the Gulf of Mexico. We believe the strategy to create the JV drilling program will allow us to develop our drilling inventory faster, diversify our drilling opportunities, reduce the risk profile and enhance shareholder value. I think that's a pretty good model going forward and could work even better when directed towards acquisition opportunities.

I mentioned earlier that we have been busy since the last call. That includes working on something that we think we do pretty well and that distinguishes our company from others. By April 5, we closed on the acquisition of the 9.375% working interest in the Heidelberg field from Cobalt. The Heidelberg field interest that we purchased is in Green Canyon box 859, 903 and 904. Our gross purchase price is $31.1 million.

Our production from the Heidelberg field, which flows into the Heidelberg Spar was a gross of 33,513 barrels of oil per day and 16 million cubic feet of gas per day or 36,300 barrels of oil equivalent per day in the month of February. The net benefit to W&T from that was almost 3,000 barrels of oil equivalent per day. So an acquisition of this nature is an example of the types of opportunities that we see in the Gulf and boost our ability to generate cash on an accretive basis.

So yesterday, after the market closed, we announced solid results for the first quarter of 2018, which showed strong earnings and cash flow. Production averaged about 37,000 barrels of oil equivalent per day, which was in the middle of our production guidance range. Again this quarter, we estimate that production would have far exceeded guidance if we hadn't been impacted by substantial downtime and deferrals associated with well maintenance, weather, pipeline outages and platform maintenance. These collectively resulted in deferred production of almost 4,200 barrels of oil equivalent per day, this compared to production deferrals in the fourth quarter of 2017 with around 5,000 barrels of oil equivalent per day due to similar issues. We've spent a lot of scheduling for that matter -- unscheduled pipeline outages for maintenance, and we believe that much of this is now behind us. Our current production rates are closer to 38,000 barrels of oil equivalent per day, and we expect that will go up as couple of pipes are off-line, return to service.

So our A-17 well at Mahogany came on line at the end of March, and we will be including the Heidelberg production starting with April business. A portion of new wells from the JV drilling program will also help with production going forward. The A-17 well at Mahogany came on at an internally restricted rate of 1,925 barrels of oil equivalent per day. And we believe that well is capable of producing around 4,750 barrels of oil equivalent per day.

So we recently completed and placed on line the Viosca Knoll 823 Virgo A-10 sidetrack well. It's currently producing at test rate of 1,250 BOE per day. By the way, first quarter revenues grew 8% from a year ago to $134.2 million as our average realized sales prices increased $7.80 per BOE to $39.92 per BOE.

So during April of this year, we entered into 4 different commodity derivative contracts for crude oil for a total of 11,000 barrels per day starting in May and going through the balance of this year. We've posted those commodity derivative positions to the Investor Relations section of our website under Other Reports.

The positions include swaps, costless collars and purchased puts. We've hedged a portion of our PDP at a floor of about $60 per barrel for the remainder of 2018. This derisks the portion of our cash flow stream and serves to ensure that we generate cash to reduce debt and pursue acquisitions.

I believe we continue to do a great job of managing the expenses. Total lease operating expenses came in as expected in the fourth -- excuse me, in the first quarter and were down 8% from a year ago. Total G&A expenses came in above expectations, driven by increases in incentive compensation 2018, which is a function of substantially better financial performance, partially offset by reductions in legal costs.

So adjusted EBITDA for the first quarter of 2018 grew 18% to $77.2 million, and our adjusted EBITDA margin has now increased to 57.5%. Both of these are improvements over the first quarter of 2017 when we reported adjusted EBITDA of $65.2 million and an adjusted EBITDA margin of 52.4%.

Net cash provided by operating activities for the first 3 months of 2018 was $75 million, so cash generation was pretty good. It wasn't quite as good as the first quarter of 2017 when we received $30 million from an insurance reimbursement related to a Hurricane Ike claim from 2008, so a one-off event. The first quarter of 2018 reflects advances from investors in JV Drilling Program of $19.2 million. So excluding both of these one-line (sic) [onetime] items in both periods, the 2018 results were better than in 2017.

Our adjusted net income was $28 million or $0.19 per share compared to adjusted net income for the first quarter of 2017 of $22.8 million or $0.16 per share. Net income for the first quarter of 2018 included $100,000 of income tax expense, whereas net income for the first quarter of 2017 included an income tax benefit of $7.6 million.

At March 31, 2018, our total liquidity was $280.4 million, consisting of an unrestricted cash balance of $130.7 million and $149.7 million of availability under our $150 million revolving bank credit facility. That's up from $248.8 million in liquidity at year-end 2017 as our cash balance grew $31.7 million.

So we do continue to expect to receive $65 million in federal income tax refunds in 2018. We expect to receive $13.7 million in June time frame and $52.1 million in the September to October time frame. But if you'll recall, these tax refunds are associated with what is called specified liability losses associated with our plug and abandonment activities, which is a provision of the tax code that allows net operating losses to be carried back for longer periods.

So as a result of establishing the JV drilling program, we have revised our 2018 CapEx program downward to $75 million from $130 million as previously reported. The revised amount is net of approximately $20 million in reimbursements for capital expenditures, which W&T incurred from wells included in the JV drilling program before the closing date.

The $75 million capital budget does not include the cost of acquisitions. The Mahogany field will contribute only one well in the JV drilling program, the A-5 sidetrack well at Mahogany that is currently being drilled as part of the JV drilling program. The A-19 well will be drilled later this year after the A-5 sidetrack is drilled and completed. Other major wells this year that are part of the JV drilling program are the Viosca Knoll 823, which is the Virgo field, and also wells at the Ewing Bank 910 field. W&T's gross working interest in JV wells will generate a higher rate of return with less capital outlay, thus freeing up cash for debt reductions and accretive acquisitions.

So this budget also includes a number of recompletions that are expected to cost approximately $13 million. Additionally, we estimate that we will spend approximately $31.6 million on plug and abandonment activities in 2018, which is down substantially from the last several years. We currently predict our 2019 P&A expenditures will drop even further to the $17 million range.

We're pleased with our drilling results so far this year, with continued success in our Mahogany and Virgo fields. The Ship Shoal 349 A-17 -- excuse me, A-17 well came on line towards the end of March and is producing an internally restricted rate of approximately 1,925 barrels of oil equivalent per day. That's about 82% oil, by the way. We believe this well is capable of producing around 4,700 barrels of oil equivalent per day from the ‘P’ Sand, which is a previously undiscovered deeper sand. The A-17 well also found a 'Q' sand, which has been completed with a [sighting] fleet, is now behind pipe reserves, it can be produced independently or combined with a 'V' sand production in the future.

So let me brief you a little bit on the activities at our Virgo field. The Virgo field was brought online in 1999. No drilling or development has occurred in that field since that time until now. The Virgo field is in 1,132 feet of water, and when it was installed, it was the fourth deepest conventional platform on the planet.

We initiated a field redevelopment program in late 2017 and mobilized the platform rig in January and began drilling operations on the A-10 sidetrack in late January. We've now identified 8 prospects at Virgo that we believe are relatively low risk and could have a nice impact on our production.

The A-10 sidetrack well is the first in the program, and it encountered up 300 feet of gross hydrocarbon column and 113 feet of measured depth in the [JL] upper sand. The well was placed online in April in a test mode as we monitor bottom hole pressure and various other activities. Well's currently producing at a test rate of 1,250 barrels of oil equivalent per day.

The next well is the A-12 well, which is structurally higher [than another well that is oil play.] So once that well is completed, we will then move to the A-14 well. All these new Virgo wells are part of the JV drilling program.

Finally, let's talk about activities at Ewing Bank 910 field. This field includes South Timb 320 and 311 as well as Ewing Banks 954. The wells drilled in the Ewing 910 field are all high-quality, low-risk projects with access to existing infrastructure that can generate cash flow quickly, assuming success.

The redevelopment effort at Ewing 910 is split into 3 different phases. The first phase was the drilling of the successful Ewing 954 A-8 and the South Tim 320 A sidetrack back in -- I think that's A-5 sidetrack back in 2015 and 2016. Both of those wells are online, making good contributions to the bottom line.

So the second phase will consist of the South Tim 311/320 A-2 and A-3 wells. We've mobilized the rigs to the South Tim 311 platform and have begun drilling the A-2 at South Tim 320. Once that well is complete, then we will begin drilling the A-3.

The third phase will likely include a well at Ewing 953, which is an open water location. We believe both of the wells in this year's Ewing 910 program are low-risk exploration opportunities with multiple stacked pay sands. As you can see, we've revised our guidance upward for the full year, which reflects the positive impact of the Heidelberg acquisition and some of the estimated production volumes from our drilling success.

Let me again -- let me just reiterate that we continue to expect to be able to either pay off the upcoming 2019 debt maturities during the fourth quarter of 2018 and first quarter of 2019 or refinance or do some combination of both. We also expect to take advantage of attractive acquisition opportunities that we believe are available in the Gulf of Mexico.

With that, operator, we'll open the lines up for questions.

(Operator Instructions) Our first question comes from John White with Roth Capital.

You've had a busy -- like you say, you've been real busy, a lot of deal making going on so congratulations on that. Your press release mentioned you've got wells drilling at Ewing Bank 910, Mahogany and Virgo. Could you talk a little bit about the timing of reaching total depth and bringing those wells on?

Yes, the Mahogany well, the A-5 sidetrack probably within the next couple of weeks will be at TD and setting pipe. Virgo, again, probably about the same kind of time frame. South Tim 311 is going to take a little bit longer, with probably 45 days or so, maybe 60 days to get to TD and setting pipe and everything.

And are all 3 of those wells in the drilling joint venture program?

They are.

Our next question comes from Jon Evans with SG Capital.

I know you've been frustrated by the maintenance and the pipeline outages, et cetera. You talked about it was 4,200 in Q1. Do you see those outages in the platform maintenance getting better as you go into Q2 and Q3?

Yes, we do. We think that most of that's behind us. Some of it was scheduled, so we knew about it ahead of time. Some of it was unscheduled. Some of these pipes had gotten a little bit older and they've developed maintenance issues they had to deal with. Some of them are actually on platforms where we had to do some redesign around existing pipe connections. Some of them were subsurface. So we -- and also, we do take into account that we have regular maintenance in our platforms. We take a little bit of extra care, I think, to make sure that even during these down times, I've done enough of these things and, unfortunately, about 6 of them in my career, where we have these downward pricing cycles. But I found that it makes sense to invest money in maintenance now while prices are lower to save money later on when prices are higher and cost of goods and services are higher. It just seems to be a better formula and similarly, we're doing the same thing with our plug and abandonment operations over the years. In the last couple of years, we've got a pretty robust P&A program, similar kind of reasoning that prices are lower, and we can get more work done. Now we're feeling the benefits of it as we reduce that capital program going in the higher pricing cycles. So it seemed to work out better for a little longer-term planning.

Got it. So if you think, I mean, I know you can't control if the platform goes down, et cetera. But if you think about the acquisition, et cetera, and where you're producing, are you producing roughly kind of in that 4,200 to 4,400 range? I mean, if you just add that 7 back a day, 4,200 from the outage and then you get about 3 from the acquisition? Is that a fair number now, whether you're going to bring that to market is different because you can't control the pipelines, et cetera. But is that fair, do you think?

The answer to that is yes. Yes, the productive capacity is there. That's why we can measure it. Yes.

Okay. And then the other question I have for you is you haven't been a hedger in the past. Just kind of struck me uniquely that you put these in. So could you go into some kind of detail of your thought process? Is this a change of strategy? Or is it just because you got these debt maturities, you want to make -- get some insurance on the cash flow and what you're trying to do?

Yes, it's a little bit -- it's not quite true that we haven't been hedging in the past. We have. It's just not a normal course of business for us. It's not an automatic that we will hedge. We hedge to protect our budget. We hedge to manage different kinds of acquisitions and that sort of thing. So that's fairly routine for us. Hedging this year helps us to ensure that we are able to meet our debt obligations and helps ensure our continuing acquisition efforts.

Okay. And then just the last question because of where kind of WTI is, et cetera, in really light sweet, are you getting any benefit from that sliding scale that you had in Yellow Rose when you guys did that deal, et cetera, or no?

Short answer to that is yes.

Okay. So does that just come through -- it doesn't come through as barrels, it just comes through as revenue? Or is it going to be below the line? Or how do I see that? Or will it be identified in the Q?

It's not -- I don't know that it's necessarily specifically identified in the Q. Since it's not really that material to the company at this point, it comes through as just revenue to us. So I don't break that out. But yes, I mean, they're continuing to make progress out there.

(Operator Instructions) Our next question comes from Dustin Tillman with Wells Fargo.

Can you talk about your revolver? In the 10-K, it said that the banks were unwilling to extend the revolver. What does it take to get them to extend or to re-up? And what the conversation's been like with other potential revolver lenders?

I'm sorry, you cut out there a little bit, Mr. Tillman. Would you please repeat the question?

Yes. So in the 10-K, it said that the revolver banks were unwilling to extend under current -- under the current cap structure. So what does it take to get them to extend? Or what have conversations been like with other revolver lenders for potential replacement facility?

Yes. Well, since Wells Fargo was in that revolver, I would think you guys have a pretty good idea what your own opinion is. But I would tell you that you first have to frame that along the lines of the fact that, that amended and restated credit agreement expires at about November of this year by its own terms. So we didn't see any need to go in and press another agreement at this point in time with our banks. I think what we'll see is pretty much a business-as-usual-type approach here. So I don't anticipate any issues with that at all. I do anticipate that we will refinance, in one way, shape or another, the entire corporate structure, debt structure and credit facility go in, in fairly short order. So that's not -- revolver is not my top priority. It's undrawn, so it doesn't quite -- essentially undrawn, so it doesn't really get a whole lot of attention.

Okay. What is having the ability to have a revolver do in terms of your willingness to go buy assets? It looks like a lot of the deals that are taking place today include relatively large letter of credit or bonding type of facilities in terms of taking care of P&A?

Well, our revolver is our cheapest form of capital. So that's our dry powder for things in which we feel like we would need to move fairly quickly. Our financial assurance is something that we do as a regular course of our business in any event, and we've always dealt with that over the last 35 years. So it's kind of hard to say there's a cookie-cutter approach to how you manage all this. But it's always nice to have an undrawn facility and the support of 20 different banks.

Appreciate it. One more question and maybe more of a strategic question. Now that you're starting to generate a reasonable amount of free cash flow, when you thought about the joint venture, how did you decide what goes into the JV and what doesn't? And how -- what is the balance of using free cash flow on high IRR opportunities versus effectively selling down a large part of that interest into the joint venture?

It was a very complex question. It's not simple, the answer to that. It's taking a look at our portfolio and determining what's going to be best for all parties concerned. Since I sit on both sides of that transaction, I think it's been structured as a very fair type of investment for all the investors and for W&T as well. I think that's a major part of the attraction of the program. I've got a lot of my own capital involved in it and the company does as well, and we're the operator for most of it.

We do have another question, and that comes from Hassan Ahmad with Serengeti.

A quick question for you. I'm looking at your guidance. I'm just trying to figure out, does that include the Heidelberg acquisition? Or is that -- is the guidance -- production guidance separate from that?

No, it does include Heidelberg, yes.

Okay. And so I guess, the second question I have based off of that is, if I'm looking at your production guidance sort of year-over-year, we're still kind of -- with the JV guiding to maybe down a little bit year-over-year. So I guess, what do you think is going to take to kind of get your production back up as you work your way into sort of those refi wall coming up in the next couple of years? Obviously, the oil helped out, but then you do need to kind of get production back up as well, I would imagine. So how do you sort of think about your production over the next year or 2, given...

That's a great question. Some of the issue, as I've tried to explain in or as we tried to explain in the earnings release and in this conference call this morning, has to do with production that's off-line for various reasons that we can't really control. There's a portion of it that is scheduled maintenance, but that's generally with the pipeline companies, things that they have to do to ensure the integrity of the transport system. And some of it was unscheduled which is completely unexpected. But we've had a pretty tough weather cycle this -- over the last 6 to 7 months. Probably worsened than anything I've ever seen. We talk a lot about hurricanes, but we don't really talk about normal winter weather type of activity. When you get big winds and seas, and it's hard to get equipment and supplies to location, even sometimes by helicopter. So we've had a good bit of that this winter and early spring. Normally, activities pick up late spring, early summer, that sort of thing, and then they start to go a little bit slower toward the winter months. So we have experienced some of that. As far as how are we going to replace production, well, that's always part of what we have is our incentive compensation goals. So that's one of the things that spurs the activity. We have to do it with a reasonable approach and a lot of that is done by acquisition. So this company doesn't just live and die by the drill bit. We make acquisitions. We think that market is pretty good. We don't budget that because we don't know how to predict it, but we're -- I fully expect to have more acquisitions this year. I fully expect to have really good success with the drill bit. Mahogany, by the way, is excluded from our JV drilling program. We have a specified number of prospects in our portfolio. We're going to make sure that we manage our debt issues first as well because that's imminent within the next 12 months. So we're to the point where now we will manage that as well and we wanted to be able to have enough cash flow to pay off the first 2 tranches or $269 million -- I'm sorry, $289 million of debt. We will be able to do that with cash. So we're lowering our net debt. I wanted to be able to do that, whether we actually paid off immediately or we paid off through a reasonable time period in a refi scenario. It just gives us a lot more options and it also frees up capital to do acquisitions and replace production. So I think we've come up with a pretty solid way of doing business to not only continue to grow the company, grow production but to reduce our debt.

Our next question comes from Jon Evans with SG Capital.

In your SG&A this quarter, did you have expenses from the joint venture deal or from the Heidelberg transaction? On a BOE, it jumped up pretty big in just in absolute dollars, it was a big increase. I know you guys have been pretty tight on that.

Yes, the answer to that is no on the expenses for the JV drilling program. They're pretty minimal in regard to the size of the facility. Expenses will jump up as a result of Heidelberg, a much more expensive field to operate but also pretty good revenue increase. So keep an eye on both of those figures because revenue is jumping up as well.

Okay. And then just with Heidelberg, is there any like offset wells or any opportunities to increase that production over time or to keep it? Or is it just producing asset that we're just going to see the flows of it?

Well, whenever we buy fields, we look at 3 things. We look at cash flow, we look at upside in drilling, and we look at whatever we can do for workovers, recompletes and facilities upgrades that can increase throughput. We're not the operator there. However, we do take a pretty serious look at all the data we have. We're still continuing to examine the data from the field. So we're fairly confident that we'll find something in the future that will be worth pursuing.

And then Noble today had some pretty positive comments on their call just about the jackup market in general, the harsh environment. I know that's not really in the Gulf where you are, but can you just give us your thought process on kind of expenses in the Gulf and what you're seeing there? Are you starting to see any kind of inflation or no?

We generally -- the short answer is no and if you realize, it's not a lot. We generally see some seasonal adjustment. We get a little bit busier this time of the year because the weather is better. And then we get less busy toward the end of the year because the weather isn't very good. So -- but I'm not seeing any real predictable long-term cost of goods and services creep.

There are no further questions at this time. I'll turn -- I'll now turn the call back to Tracy Krohn for closing remarks. Thank you.

Thanks, operator. We appreciate it, and we'll do this again next quarter and hopefully, we'll have some other good news in between now and then. Thanks so much.

Thank you. This concludes today's conference. All parties may disconnect. Have a great day.