Contango Oil & Gas' (MCF) CEO Allan Keel on Q2 2016 Results - Earnings Call Transcript

| About: Contango Oil (MCF)

Contango Oil & Gas Co (NYSEMKT:MCF)

Q2 2016 Earnings Conference Call

August 04, 2016, 10:30 ET

Executives

Joe Grady - CFO

Allan Keel - President & CEO

Analysts

Kyle Rhodes - RBC Capital Markets

Ron Mills - Johnson Rice & Company

Operator

Welcome to the Contango results for Second Quarter 2016. Today's conference is being recorded. At this time, I would like to turn the conference over to Joe Grady, Chief Financial Officer. Please go ahead, sir.

Joe Grady

Thank you. I would like to welcome everyone to Contango's earnings call for the second quarter of 2016. On the call today are myself; Allan Keel, our President and CEO; Steve Mengle, our Senior Vice President of Engineering; Tommy Atkins, our Senior VP of Exploration; and Carl Isaac, our Senior VP of Operations. I'll give you a brief overview of financial results and then we'll turn it over to Allan, who'll give you an update on our recent operations. We'll follow that with a Q&A session. And just as a reminder, as typical for most companies, we'll limit questions to those from analysts that follow our stock closely, as we believe that that is the most constructive and productive use of everyone's time.

Before we get started, I want to remind everyone that the earnings press release and the related discussion this morning may contain forward-looking statements as defined by the Securities and Exchange Commission which may include comments and assumptions concerning Contango's strategic plans, expectations and objectives for future operations. Such statements are based on assumptions we believe to be appropriate under the circumstances. However, those statements are just estimates, are not guarantees of future performance of results and therefore should be considered in that context.

Moving on to the financial results, our net loss for the quarter was $17.3 million or $0.90 per basic and diluted share, compared to a net loss of approximately $19.5 million or $1.03 per share for the prior-year quarter. As you noticed in the release, there were a number of factors that contributed to the change. The major positives being lower cash costs, lower exploration expenses and lower DD&A in the current-year quarter, offset in part by lower revenue due to lower production and prices and the fact that we fully reserve the potential deferred income tax benefit for the current-year quarter.

Excluding the pre-tax impact of non-cash impairments and non-cash mark-to-market hedging loss for both periods, pre-tax loss for current quarter was $9.3 million, compared to a pre-tax loss of $29.3 million for the prior-year quarter. To put the quarterly results on a comparable basis as consensus recurring estimates -- so, that is, excluding the mark-to-market loss on hedging and excluding the valuation allowance for the income tax provision, net loss for the quarter would have been approximately $0.35 per basic share which is comparable with the consensus estimates of a loss of $0.33 per share.

Adjusted EBITDAX, as we've defined in our release, was approximately $10.1 million or $0.53 per basic share for the current quarter, compared to approximately $19.9 million or $1.05 per share, for the prior-year quarter, a decline attributable primarily to the lower revenues, but offset in part by success in lowering lease operating and cash G&A expenses for the quarter. Cash flow per share for the quarter was approximately $0.47 per share compared to $1.01 per share for the prior-year quarter.

To illustrate the benefit coming from our emphasis on cost improvement for the second quarter, we reduced per-unit cash cost -- that is, cash G&A and LOE and excluding production and ad valorem taxes -- by 13% and that's despite a 24% decrease in second quarter production, period over period. We continue to stay focused on further improvement in reducing costs, especially those that we have the ability to control.

Production for the current quarter was approximately 6.8 Bcfe or 74.6 Mmcfe per day which was within guidance but below the 98.4 million per day in the prior-year quarter, a decline that was expected due to very little drilling in the last 12 months. We have provided guidance of 67 million to 72 million equivalents per day for the third quarter of 2016, with roughly the same commodity mix as in the most recent quarter. As noted in our release, we shortly will be commencing drilling on our newly-acquired acreage in the Southern Delaware Basin. However, we expect very little production from that drilling prior to year end.

Crude oil and natural gas prices during the quarter were down 27% and 25% respectively which, combined with the decline in oil production as a percentage of total production, caused a weighted average 28% decrease in our equivalent price to $2.85 per Mcfe for the quarter. We continue to identify and pursue opportunities to reduce field operating cost, as evidenced by the $3.3 million decline or 36%, in quarterly lease operating cost. As I mentioned earlier, that also represents a 16% decrease in per-unit cost, despite the fact that the vast majority of our lease operating expenses are fixed and despite the 24% decrease in production.

Guidance for the third quarter of 2016 is $6 million to $6.5 million, a little higher than the second quarter LOE due to some planned expense workovers. Exclusive of non-cash stock compensation expense, cash G&A expense was $4.1 million for the quarter or $0.60 per Mcfe, compared to $6 million or $0.66 per Mcfe, for the prior-year quarter, a 32% decrease attributable to an August 2015 reduction in force in our corporate offices that reduced head count by 30%. Just as we have done in the field, we will stay focused on minimizing administrative cost in this low-price environment.

Guidance for the third quarter is $4 million to $4.5 million and we do believe that, despite the reduction that we had in 2015, we do still possess the right team as we reengage in drilling on our new Delaware Basin acreage and do not anticipate any meaningful increase in G&A associated with that program. We had approximately $111 million outstanding on our credit facility at quarter end which was a reduction of about $4.5 million from year end. In conjunction with the closing of our recently-announced Delaware Basin acreage acquisition in late July, on July 22 we also completed a public offering of 5 million shares of our common stock for net proceeds of $46.9 million, to use in funding the initial payment on that acquisition and the funding of the first several wells. Allan will expand on that in a little bit when he's in his operations review.

At July 31, we had approximately $69.8 million outstanding on our revolver, with approximately $68.2 million available for future borrowing under our $140 million borrowing base.

That concludes the financial review and I'll now turn it over to Allan for the operations update.

Allan Keel

Thanks, Joe. Good morning, everyone and thanks for being with us today. I'll give you a brief update of kind of what's been happening during this past quarter. From a calendar standpoint, the second quarter ended quietly, with the results within guidance and with very little CapEx activity. As you've seen from our news releases, things got a little bit more active in July. We've been working with a private company for a few months regarding the position in the Southern Delaware Basin and we were able to close that acquisition and exploration agreement here recently. We feel really good about the fact that the seller wanted to retain a 50% working interest in the leases we acquired.

So, after the carry portion of the purchase price has been paid, we'll be 50/50 partners. In order to fund our early capital needs for that project, we also completed a public offering in which we received proceeds of approximately $47 million. We're very excited about this new acreage position and our ability to raise new equity capital that will allow us to develop this acreage, using internally-generated cash flow and also maintain a healthy balance sheet. We've been looking for an entry point here into the West Texas area for quite some time. We were looking for an area that could give us inventory of high-quality drilling opportunities that give us good returns in this lower-price environment that we're in now.

I think, in terms of structuring the transaction in the way that we did which includes an upfront cash payment of $10 million in carries or through well carries, over time and an approximate $5 million contingent amount to be paid in the form of spud fees after we drill the first six wells, we think that's -- the deal structure was very fortuitous for us and very helpful for us to get it done. As you saw from the press release that we issued, upon closing the transaction the total consideration, assuming all fees are paid, will be approximately $25 million or $5,000 an acre. We think that compares very favorably with other transactions that have been announced in the area.

Just to the north of us, there's been a few public companies and a -- and private companies purchasing acreage, more in the, I'd say, $25,000 to $35,000 per acre range, so we're very -- feel very fortunate to be able to -- have been able to purchase this at that price. Our current plan is to spud our first well sometime in October. Working on some logistics now; but, soon as we iron that out, we'll be ready to go. We would expect first production as 60 days after spud. We expect to have a rig drilling continuously as we monitor production results.

And again, assuming success and assuming oil prices hang in there, we would expect to have a second rig, kind of the middle part of 2017 and possibly a third rig in 2020, all designed to keep our CapEx program with internally-generated cash flow. And on that pace, we hope to produce a modest annual increase in production over the next 4 years and meaningful increases in cash flow, reserves and reserve value, as we move to a more balanced commodity profile. Again, assuming current commodity prices and service costs and using our strategy of staying within cash flow, our CapEx program over the next few years is expected to be focused almost entirely on this project.

We'll continue to preserve our lease position in our other core areas, a lot of which are either HBP or have a lot of term remaining. And to the extent prices improve or other conditions change, we might allocate some capital to those areas. So, I'll share a few detailed expectations we have for our Southern Delaware project. We estimate that we have between 150 and 160 gross locations from three benches -- the Wolfcamp A, the Wolfcamp B and the second Bone Springs, with additional potential for more locations in other less-developed Wolfcamp benches and the Bone Springs. These locations are assumed based on approximate 1000 spacing and 10,000-foot laterals.

Completion design includes approximately 50 stages on a 10,000-foot lateral, 2000 pounds of sand per lateral foot and approximately 80 barrels of water per lateral foot. A 10,000-foot lateral in a Wolfcamp A well -- it's expected to cost approximately $8.2 million. If average results are consistent with our type curve, the average well will provide an estimated 41% rate of return at yesterday's strip. So, you can see that this is one of the few areas that it makes sense to drill in this price environment. And by contrast, most of our other areas require oil prices in a stable $55 to $60 range to get us a 20%, 25% rate of return at the well level. Just quickly, regarding our ongoing acquisition strategy, we continue to look for opportunities that contain a good mix of producing reserves and meaningful resource upside, that can give us a more -- stronger platform for future growth as prices and costs improve. While we continue to do that, though, we're completely focused on our Southern Delaware Basin project. That's where the entirety of our capital will be dedicated for the near future. We're completely focused on that. We would love to continue to grow our position in the West Texas area for the reasons I've already mentioned. So, I guess in summary, until we gain a lot more confidence in the price environment, we believe that our near term strategy continues to be limit drilling only to the higher-return projects or strategic projects. We'll preserve our acreage through extensions of core position -- in our core positions and limit our CapEx program to internally-generated cash flow in order to maintain a strong balance sheet.

So, that concludes our remarks for this morning and with that, we'll open it up for questions on the line now.

Question-and-Answer Session

Operator

[Operator Instructions]. We will now take our first question from Kyle Rhodes with RBC Capital Markets.

Kyle Rhodes

Just curious if there's any differences in type curve expectations between the three benches that are prospective on your acreage. And I guess, what's the early game plan as far as delineating the other zones? I know you're targeting the Wolfcamp A on the first well; but just curious how you're thinking about testing those other zones, going forward.

Allan Keel

As far as type curve, I mean, we're using one type curve for all three at the moment. The reality is, we have a lot more data in the Wolfcamp A, then in the Wolfcamp B, second; and the Bone Springs really is just developing in the area. And so, until we get more information on it, we're just keeping one type curve. So, it's a little -- we don't know as much about the Bone Springs yet.

Kyle Rhodes

So, fair to think the first kind of six wells -- they're all going to be Wolfcamp As?

Allan Keel

Yes, A or possibly B, but yes.

Kyle Rhodes

And then, how is your Delaware acreage set from a gathering and processing standpoint? Are there any current agreements in place there? And I guess, what are the plans on the salt water disposal side?

Allan Keel

So, from a takeaway standpoint it's actually pretty mature. There's actually a gas takeaway in the leasehold and then there's actually a second gas takeaway that's fallow that would have to be retested to reengage; but really, in good shape from the gas standpoint. From an oil standpoint, we'll start out hauling oil away with trucks, but we feel pretty confident that the oil pipeline that's about 3 miles away from us is going to be excited to build to us, so that we can get away from some of the other issues related to trucking oil. So, the acreage sets up really nice, from a product takeaway standpoint.

Your second question was regarding salt water disposal. And within 10 miles of the acreage, there's three commercial facilities that are available. But our plan generally will be to control our own destiny in terms of salt water disposal and water management, with a recycling plan enacted to provide us adequate volumes of frac water.

Kyle Rhodes

And you mentioned potentially wanting to grow your position in the Delaware. Obviously, prices have been moving north here. What's the, I guess, running room you guys could see, kind of in your immediate target area and is there anything left to do on the organic front or is it, larger packages kind of all that remains at this point?

Allan Keel

Yes. I think that we'll take expansion out there, for sure. I mean, we can't speak about it all, but our plans are to expand out here. No doubt about it.

Kyle Rhodes

Okay. And then just one on the other kind of legacy properties. I know in the past you'd talked about an Eagle Ford test on the KM Ranch there in South Texas. Assuming that's kind of off the board for a while now?

Allan Keel

Yes. We need higher prices to reengage in that area.

Operator

We will now take our next question from Ron Mills with Johnson Rice.

Ron Mills

On the updated presentation, you call out some recent wells that have been drilled. There's nothing on your acreage, but I think 20 wells in and around -- within 3 to 4 miles of your position. Any color you can provide on those wells and how those wells are performing relative to your type curve; and, if you know, are those -- were those wells completed with the same frac recipe that you plan to use?

Allan Keel

Yes. So, our type curve was generated using those wells. So, that's -- other words -- so, our type curve is the average performance of those 20 wells. And those 20 wells were wells that had lateral links where between 6000 and 9000 feet. Their average lateral link was about 7500 feet, 7300 feet, I think. And they were -- generally had the higher-profit concentrations in the half out of the larger frac fluid concentration. So, they were similar in nature to what we're talking about doing.

Ron Mills

Okay. And then, on your acreage position, is there any bias in terms of where your first well will be drilled -- East-West; North-South? And when you look at your first six under the initial carry, is the plan to spread those across the position?

Allan Keel

Yes. Well, our first well, we're going to plan on going East-West. We think the raw properties show that, so that that's the most advantageous place to go. There is a mix out here, of North-South and East-West. We're pretty comfortable with -- that you can go either direction., but we think that raw mechanics basically show that an East-West direction, at least in this area, is preferable. We do have to hold the acreage first and so there will be somewhat of a spread across. Probably the bias will be done into Wolfcamp A and the B which will therefore hold the Bone Springs. So, that's kind of the way that we'll go about it.

Ron Mills

Okay. And then, the acreage position -- at least, you highlight that all of your 157 wells can be 10,000-foot laterals. I guess that points to the contiguity of the acreage position. Did I read that correctly or will you have some shorter laterals? And then, to follow on Kyle's question, the -- if you increase organically, is it just through picking up small pieces here and there in kind of adjacent areas?

Allan Keel

Yes. The latter question first. Yes. I mean, we will houseclean in and around us, we think, as well as looking at other opportunities as we go forward. I can't remember your first question, I'm sorry.

Ron Mills

It had to do with the contiguity of the position and you point to 10,000-foot laterals. It's -- I mean, it's impressive that the -- that your whole inventory's able to be developed on that -- at that length.

Allan Keel

That's correct. And we think that we can do that. There will be -- we'll have to work at it, but we think that most, if not all, of the lateral -- the wells would be 10,000-foot laterals.

Ron Mills

Okay. And then one last one. I think you've mentioned this, Joe -- the plan in terms of -- as we start thinking about growth from this program. And it sounds like, based on yesterday's strip -- is that the price point where you would be able to remain balanced between your cash flows and CapEx? Or is that at a higher price deck?

Joe Grady

Well, it was originally at a little higher price deck. But where we're today, versus where we first talked about that, is not a meaningful difference.

Operator

Thank you. And I will now hand the program back over to Allan Keel.

Allan Keel

Thank you and like to appreciate -- tell everybody we appreciate your time today and look forward to giving you an update soon. And hopefully if we get some improvement in these oil prices. So, thanks again.

Operator

And that does conclude today's program. We'd like to thank you for your participation. Have a wonderful day and you may disconnect at any time.

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