W&T Offshore, Inc. (WTI) Q1 2018 Earnings Report, Transcript and Summary

Greetings and welcome to the W&T Offshore, Incorporated 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 are 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 Company, I would like to remind you that information reported 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 any replay. Also, please refer to the first quarter 2018 financial and operational results announcement that W&T released yesterday for a discussion on forward-looking statements and reconciliations of non-GAAP measures. At this time, I would like to turn the call over to Mr. Tracy Krohn, W&T's Chairman and CEO.

Thanks, Lisa. So, good morning, everyone and 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 are going to be available to answer questions later 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 initial investors, drilled up to 14 specified projects in Gulf of Mexico over the next three years. I would refer to this as a joint venture joint program. The transaction is structured such that we initially received 80% of the revenue contributing 20% of the cost in each project cost associated leases and combining access to the available infrastructure. While investors received certain threshold, we received about 38% of the economics on a world-by-world basis. The leading investor in the JV drilling program is an entity own controlled by funds managed by Heidelberg partners of Boston based every fund sponsor with over 40 billion of assets under management. The other initial investors are W&T in minority investment planning, the own and controlled by myself. The Krohn entity team invested on the same terms and conditions as the [indiscernible] 4% of total invested capital to our partners. Since the initial closing, we had a second closing with buying additional investors including Baker Hughes GE and we expect to have a third closing of relatively new future. W&T contributed 88.94% of its working interest in 14 different projects to Monza Energy LLC which is the newly created partnership the whole 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 by high return inventory with reduced capital outlay. We are contributing leases and drilling cost specs along - with the operations. So we believe this is JV drilling program greatly enhances our financial flexibility to manage that balance sheet and to pursue additional accretive acquisition opportunities in the Gulf of Mexico. We believe the strategy to create the JV during the 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 it can 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 believe pretty well and distinguishes our company going forward. I hope we closed on the acquisition of 9.375% working interest in the Heidelberg field and Cobalt. 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 far was a gross of 33,513 barrels of oil per day and 16 million of cubic feet of gas per day or 36,300 barrel for oil equivalent per day in the month of February. The net benefit prudently from that was almost 3,000 barrels oil equivalent per day, so an acquisition of this nature is an example that will - types of opportunities that we’re seeing in the Gulf - and generate cash on an accretive basis. So yes, we have a month close, we’re now starting results for the first quarter of 2018 which shows 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 far exceed the guidance that have been impacted by substantial downtime and deferrals associated with oil maintenance, weather, pipeline outages and platform maintenance. These collectively resulted in differed production of bonds produced 200 barrels oil equivalent per day. This compares to production that falls in the fourth quarter of 2017 which was around 5,000 oil equivalent per day due to similar issues. We’ve seen a lot of scheduling for that matter, unscheduled pipeline outages for maintenance and we are much of this is - now behind us. Our current production rates are closer to 38,000 barrels oil equivalent per day. We expect that we will go up as capital prices are offline return to service. So 817 wells Mahogany came online at the end of March and we will be including the Heidelberg production starting with 8 of business. A portion of new wells from the JV drilling program will also help the production going forward. The 816 well, Mahogany came on an internally restricted late 19,025 barrels oil equivalent per day and we believe that we are always capable of producing around 47,150 barrels oil equivalent per day. So we recently completed and placed online Viosca Knoll 823 Virgo A-10 side track well. It’s currently producing a test rate of 12,050 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 beginning April for this year we ended into four 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 posted those commodity derivative positions to the Investor Relations section of our website under other reports. The positions include swaps, costless collars and purchase puts. We hedged a portion of PDP at about $60 per barrel for the remainder of 2018. The list of portion of our cash flow stream and serves to ensure that we generate the cash through reduced debt end and pursue acquisitions. I believe we continue to do a great job of managing expenses. Total lease operating expenses came in as expected - excuse me, in the first quarter and we are down 8% from the year ago. Total G&A expenses came in above expectations driven by increases in incentive compensation 2018 which is a function of substantial 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 adjusted EBITDA margin of 52.4%. Net cash provided by operating activities for the first three months of 2018 was $75 million. So cash generation was pretty good. We also find good as first quarter of 2017 where we received $30 million from insurance reimbursement related to a Hurricane Ike claim from. The first quarter of 2018 reflects advantages for our investors in JV drilling program of $19.2 million. So excluding both of these online 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 the 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 2017 includes 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 a 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 for funds in 2018. We expect to receive $13.7 million in June timeframe and $52.1 million in the September to October timeframe. If you recall these tax refunds are associated with what is called specified liabilities losses associated with our plugging and abandonment activities, which is the probation of the tax flow that allows net operating losses to be carried back to longer periods. So as a result of establishing 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 for wells including 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. 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 A-5 sidetrack is drilled and completed. Other major wells this year that are part of JV drilling program are at Viosca Knoll 823, which is the Virgo field and also wells at the Ewing Bank 910 field. 70 growth working interest in JV well generate a high rate of a return with less capital outlay thus freeing up cash for debt reductions and accretive acquisitions. So with 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 plugging and abandonment activities in 2018, which is down substantially from the last several years. We currently predict our 2019 P&A expenditure will drop even further to the $17 million range. We are pleased with our drilling results so far this year with continued success on Mahogany and Virgo fields. The Ship Shoal 349, A17 well came online towards the end of March and is producing an internally restricted rate of approximately 1925 barrels of oil equivalent per day that’s about 82% or above. We believe this well is capable of producing around 4700 barrels of oil equivalent per day from the T sand which is previously I have discovered deeper sand. The A-17 well also found T sand which has been completed with a side in fleet is now behind [indiscernible] it can produced independently or combined with the V sand production in the future. So let me bring a little bit on the activities of our Virgo field. The Virgo field was brought on line in 1999. No drilling or development has occurred in that field since that time until now. The Virgo field is in the 1130 feet of water and when it was installed it was a fourth deepest conventional platform on the planet. We initiated a field redevelopment program in late 2017 in globalized platform rig in January and began drilling operations on the A-10 sidetrack in late January. We have now identified 8 side track of Virgo that we believe are relatively low risk and could have a nice impact on our production. The A-10 sidetrack well is first in the program and it did encounter up 300 feet of oils hydrocarbon column and 113 feet measured deep in JV upper sand. Well was placed on line in April and have test modes, as we monitor bottom hold pressure and various other activities. Oils currently producing a test rate of 1250 barrels oil equivalent per day. The next well is A-12 well which is structurally higher to another well that is oil rig. So once that well is completed we will then move to A-14 well, all these new Virgo wells are part of the JV drilling program. Finally let’s talk about activities that Ewing Bank 910 field. This field includes South Tim 320 and 311 as well as Ewing Bank 954. Oil field 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 of Ewing 910 is putting the three different phases. The first phase was the drilling of the successful Ewing 964A8 in the South Tim 320 A sidetrack back in - I think that 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 consists of the South Tim 311/320 A-2 and A-3 wells. We have mobilized rigs through South Tim 311 platform and have begun drilling A-2 South Tim 320. Once that oil is complete then, we will be begin drilling the A-3. The third phase will likely include a well Ewing 953, which is an open water location. We believe both of wells of this year Ewing 910 program are low risk exploration opportunities with multiple stack space heads. As you can see we biased our guidance effort for the full year, which reflects the positive impact ahead of Heidelberg acquisition consent with the estimate production buying from our drilling success. Let me just reiterate that we continue to expect be able to either pay off the upcoming 2019 debt maturities during the fourth quarter of 2018 and first quarter 2019 or refinance and or do combination of both. We also expect to take advantage of track of acquisition opportunities that we believe are available in the Gulf of Mexico. With that operator, we will open the lines up for questions.

[Operator Instructions] Our first question is from John White with ROTH Capital. Please state your question.

Your press release mentioned you 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?

The Mahogany well A-5 sidetrack probably within the next couple of weeks will be at PV-10. 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 the TD in 75…

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

They are.

Our next question comes from Jon Evans with SG Capital Management. Please state your question.

I know you have been frustrated by the maintenance and the pipeline now that is et cetera. You talked about it was 4200 in Q1. Do you see those outages in the platform maintenance getting better as you go into Q2 and Q3?

We do. We think that most of that's behind us, some of it was scheduled so we knew that ahead of time. Some of it was unscheduled. Some of these pipes have gotten a little bit older in a developed maintenance issues that had to deal with. Some of them are actually on platforms what we had to do some redesign around existing pipe connections. Some of them were sense surface. 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 downtimes, I have done enough for these things and unfortunately 6, 7 in my carrier, all we have these downward pricing cycles, but I found it makes sense to invest money in maintenance now, while prices are lower, to save money later on when the prices are high and cost of goods and services are higher. It just seems to be a better option and similarly we’re doing the same thing with our targeted operation over use. In a last couple of years, we’ve had a pretty robust P&A program similar kind of worries raising prices are lower and we can get more work done. Now, we’re feeling the benefit as we reduced that capital program going into higher pricing cycles. So it seems to works out better for the longer term plan.

So, if you think I mean I know you can’t control of 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 42 to 44 range. I mean if you just add that 7 back a day, 4200 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 product line et cetera, but does that fair do you think?

The answer to that is yes. Yes, the production capacity is there, that’s why we can measure, yes.

And then the other question I have for you is, we haven’t been hedged in the past this kind of struck me uniquely, you put these in. So could you go into some kind of detail of your thought process, does it also change your strategy or it’s just because you and you got the debt maturities you want to make get some assurance on the cash flow and what you’re trying to do?

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

And then just a last question, because of where kind of WTI is et cetera and 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.

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

It’s not - I don’t know it is necessary specifically identified in Q. Since this not worry that material to the company at this point. It comes through is just revenue. So I don’t - I would break that out, but yes, I mean they are continuing to make progress out there.

[Operator Instructions] Our next question comes from Dustin Tillman with Wells Fargo. Please state your question.

Can you talk about your revolver in the 10-K you had said that the banks were unwilling to extend the revolver. What does it take to get them to extend or reap, then what are the conversations then like with, other potential revolver lenders.

I am sorry, you cut out there a little bit Mr. Tillman, would you please repeat question?

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

Yes, since Wells Fargo was in that revolver, I would think you guys have a pretty good idea which only convince, but I would tell you that, you first have to find that along the lines to the fact that, in fact amended restage their credit agreement expires it about November of this year, by its own terms. So, we didn’t see any need to go in and perhaps another agreement at this point in time with our banks, I think what we’ll see is a pretty much business as usual type of 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, and fair short orders, so that’s not - revolver is not my top priority. It’s undrawn so it doesn’t quite, in order to change with drawn, so then we will get hold out retention.

What is having the ability to have a revolver do in terms of your wiliness to go buyouts 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 insurance is something that we do is regular course of our business in any events. And we always deal double of that over the last 35 years. So, it’s kind of hard to say we’ll, there is a cookie cover approach to how you manage all this, but it’s always nice to have an undrawn facility in the support of 20 different banks.

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 saw about the joint venture, how did you decide what goes into the JV and what doesn’t and 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’s a pretty complex question, it's not simple, the answer to that it’s taking a look at our portfolio and determine what’s going to be best for all parties concern, since I sit on both sides of that transaction. I think it is structured as a very fair type of investment for all the investors and for W&T as well. I think that’s major part of the attractions of the program. I have got a lot of my own capital involved in and the company does as well and will be operator, promotes them.

We do have another question and that comes from Hassan Ahmad with Serengeti. Please go ahead with your question.

Quick question for you. On looking at your guidance, I am just trying to figure out, does that include the Heidelberg acquisitions or is that, is the guidance, production guidance separate from that?

No, it does include Heidelberg, yes.

And so we guess, the second question, I have to offer that is you know if I am looking that production guidance is sort of year-over-year was still kind of, JVs 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 backup as you work the way in the sort of this refi wall coming up in the next couple of years. You know obviously, the oil has helped out, but then you need to try to get production back as low I would imagine. So how do you sort of think about your production over the next year or two given that terminal loans something that?

That’s a great question. Some of the issue as I try to explain, as far as we try to explain in the earning release and in this conference call this morning has to do with production this offline for various reasons that, that we can really control. There is of course, these schedule maintenance but that’s generally with the pipeline companies, I think that they have to do to ensure integrity of the transport system. And some of which unscheduled which was completely unexpected. But we had a pretty tough weather cycle this, over the last six to seven months, probably worsened than anything other. So, we talked a lot about hurricanes, we now talk about normal winter weather type of activities, we get big winds in seas and it's hard to get equipment and supplies to locations, even sometimes back over the capital. So we had a good bit of that this winter and early spring. Normally activities pickup late spring, early December that’s 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 we’re going to replace production, well that’s always part of what we have is our incentive compensation goes. So that’s one of the things that surge the activity. We have to do with a reasonable approach, and lot of that is done by acquisition. So this company doesn’t just live and die by drill bit. We make acquisitions, we think that market is pretty good. We don’t budget 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 pretty good success with the drill bit. Mahogany by the way is excluded from our JV drilling program. We have a specified member of prospects in our portfolio. We’re going to make sure that we manage our debt issues first, as well, because that’s eminent 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 $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 we paid off through a reasonable time period in refi. It just gives us a lot more options. And it also pleases up capital to do acquisitions and replace production. So I think we’ll 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. Please state your question.

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 an absolute dollars it was a big increase and you guys have been pretty tight on that?

The answer to that is no, on the expenses for the JV Drilling program, that pretty minimal in regard to size of facility. The expenses will jump up as a result of Heidelberg much more expensive field to operate, but also pretty good revenue increase. So, we’re keeping eye on both of those figures because revenues jumping up as well.

And then just with Heidelberg, is there any like offset wells or any opportunities to increase that production overtime or do you keep it or is it just, producing assets that we’re just going to see the flows over?

Whenever, we buy fields we look at three things. We look at cash flow, we look at upside drilling, and we look at whatever we can do for our workovers rig completes 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 afraid to capture the all times up in future that will be work facility.

And then, Nobel today has some pretty positive comments on their call just about the jack-up 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 are seeing there. Are you started to see any kind of inflation or no?

Yes, we generally - the short answer is no and it’s not a lot. We generally see some seasonal adjustment. We get a little busier this time of the year because weather is better. And then we get less busy toward the end of the year, because the weather isn’t pretty good. So, but I am not seeing any really predictable long-term cost to goods and services.

Thank you. And there are no further questions at this time. I’ll turn the call back to Tracy Krohn for closing remarks. Thank you.

Thanks Operator. We appreciate and we will do this again next quarter and hopefully we will have some other good news in [June]. Thank you so much.

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