Allan Keel - President and CEO Joe Grady - CFO.

Neal Dingmann - SunTrust.

Good day, and welcome to the Contango Oil & Gas Company Results for Third Quarter 2017. 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..

Thank you. Welcome, everyone, to the earnings call for the third quarter for Contango Oil & Gas. On the call today are myself Allan Keel, our President and CEO; Steve Mengle, our Senior VP of Engineering and Operations; and Tommy Atkins, our Senior VP of Exploration.

I’ll give you a brief overview of the financial results, followed by Allan who will give you an overview of our current operations. And then we’ll open it up for questions from analysts that follow our stock closely as we believe that that is the most constructive and productive use of everybody’s time during the Q&A.

Before we begin, 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 or results and therefore, should be considered in that context. Starting with a brief summary of certain financial results for the quarter.

We recorded a net loss for the quarter of approximately $6.9 million or $0.28 per basic and diluted share compared to a net loss of $12.5 million or $0.55 per share for the prior-year quarter.

The improvement in our results was attributable to lower operating expenses and cash cost, lower DD&A impairments all of which are offset in part by a slight decrease in revenue and the mark-to-market valuation of our hedges each of which I will touch on a little bit in a minute.

Adjusted EBITDAX, a measure of operational cash flow and as we define it in our release, was approximately $7.5 million compared to $4.6 million generated in the prior year quarter, an improvement attributable to the aforementioned reduction in cash cost and a realized gain on hedge settlements this year versus a slight loss in the prior year quarter, again, offset in part by the lower revenue.

Cash flow per share, exclusive of the impact of changes in working capital, was approximately $0.26 per share for the quarter compared to $0.16 per share from the prior quarter.

Revenue for the quarter was just under $19 million compared to just over $19 million for the prior year quarter, a slight decrease attributable to lower production offset in part by across the board improvement in commodity prices.

Production for the quarter was approximately 4.9 Bcfe or 53.2 million Mcfe per day compared to 65.7 million per day for the prior year quarter, a decrease attributable to the factors noted in our release, offset in part by 3.2 million equivalent per day of new production from our Southern Delaware Basin drilling program.

Adjusting for the Hurricane Harvey-related downtime, our production was right at 55 million a day or just below the 56 million per day low end of the guidance we provided for the quarter.

Our guidance for the fourth quarter is slightly below the normalized production for the third quarter as we adjusted our late third and fourth quarter Delaware Basin drilling completion schedule in order to capitalize on cost and production opportunities.

Total operating expenses, exclusive of production and ad valorem taxes, were $6.4 million for the quarter better than the low end of our $6.8 million guidance and below last year’s $7.4 million, a decrease due in part to ongoing efforts to operate more efficiently and to a higher transportation cost in 2016 related to the initial accrual of the throughput minimum.

Our fourth quarter guidance of $6.5 million to $7 million includes approximately $900,000 in anticipated workovers compared to $1 million incurred in the third quarter. Also note that the current-year quarter included approximately $400,000 in operating expenses for our Delaware Basin properties that are new this year versus the prior-year quarter.

SG&A expenses that is excluding stock compensation expense, were $4.7 million for the quarter comparable to the prior year period exclusive of special items noted for that prior year quarter. Guidance for the fourth quarter is comparable to our most recent quarter.

On the CapEx front, we continued our Southern Delaware Basin drilling program but as I mentioned at a slower pace than originally forecasted.

Because of scheduling and scope changes, we have revised our expected 2017 capital expenditure total to be between $45 million to $50 million for the year compared to our previous guidance of approximately $55 million. As noted, we had $79.2 million outstanding on our revolving credit facility at quarter-end.

We are in the final stages of finalizing our borrowing base redetermination, which will be effective November 1 and expect that number to be in the $115 million to $120 million range, a slight decrease from our previous borrowing base of $125 million as changes to our completion strategy and schedules pushed PDP additions for recent drills to the next redetermination cycle.

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

Thanks, Joe, and good morning to everyone, and thanks for being with us today. As Joe mentioned, we are continuing to focus on our Southern Delaware position that we acquired last year. We’ve been active out there this year continuing to drill and complete wells. I’ll talk a little bit more about the exact sequencing and where we are in just a minute.

We did put out our operations release in advance of our investor conference that we attended, so we don’t have a lot of new information to share with you on our West Texas project, but I will give you a quick update. In addition to that, we continue to evaluate our inventory to look at other potential opportunities within our portfolio.

We have some acreage in the Eagle Ford that’s beginning to look a little bit more attractive with these higher prices that we’re seeing. Other projects that we have included is our Wyoming project in the Muddy that where we had drilled three successful wells.

We’d probably need a little bit higher prices to go back and re-engage there as the West Texas project continues to be a better place to invest at this time. Going back out to West Texas, we do have four of our wells on production in Pecos County, as most of you know, where these two wells brought online are performing better than the previous one.

The Gunner well, which is our most recent well, is performing in excess of our type curve so we’re very pleased with that. Also, as we previously discussed, the Crusader well which has been drilled, is waiting for completion. We’re trying to schedule a time for the frac crew to get there as soon as possible.

We don’t think that will be beyond the 1st of the year, but we are anxious to put that well online and producing as fast as we can. We are on location with our sixth well, the Ragin Bull that we’re currently drilling.

Subsequent to the Ragin Bull well, we’ll go back down to the location next to the Crusader well which is the Fighting Ace, to finish that well.

So as we continue to post improving well production performance, we like most other operators out here we’re trying to find ways to reduce our drilling and completion costs without really sacrificing our production performance.

As most of you might know, operators in the area just incurred are seeing higher cost from our vendors on the supply side and especially on the completion side. And so we’re looking at ways to vary our completion recipe and our completion design to drive those costs down.

And despite a soft oil price environment and the price pressure from the vendors, we remain optimistic about what our position here in Permian holds, what kind of value it can add to our shareholders. And we’re going to remain active out there for the foreseeable future.

One of the things I’ll mention too is that although all of our completions up until this day are in the Wolfcamp A, we are very encouraged about the well results entered in the Wolfcamp B and the Bone Springs by our offset operators.

It’s our plan to both delineate our acreage into those zones as we move forward with our development right here in Pecos County. We are in the process of developing our 2018 budget, including our capital program. We don’t have that information to share with you today, but we’ll be working on that and be able to provide that on our next call.

We expect that our budget to be finalized with our board and probably available by the middle of December, and we can share it with you at that time. So I think I will open it up to questions at this time and be prepared to respond to those questions..

[Operator Instructions]. And our first question comes from Neal Dingmann. Please go ahead..

Good morning gentlemen. Allan my question really is for you, obviously on the Delaware. I’m just wondering. I know you don’t have a ‘18 plan out yet but once you’re done, I think you mentioned in the press release here about the Ragin Bull that was spud in September.

I’m wondering, once now that you’ve moved on with that number one will you keep one active rig the entire time for ‘18? Or is it still too early to decide that?.

Yeah, I would say it’s too early to decide right now. I mean we’d like to add a rig in there but that’s subject to capital availability and how we see the development moving forward.

But given the fact that offset operators have had success both in the Bone Springs and in the Wolfcamp B, we’d certainly like to test those sooner rather than later while we’re continuing to develop Wolfcamp A..

Okay. And then just lastly the Gunner. You mentioned in the press release that you think it was your best result to date.

Was there anything that you can allude to there or was it the proppant-fluid mix, was it the lateral? I mean is there anything that you’ve gained there that you think you’ll continue to build on?.

Well, I think some of it I think had to do with the way we flowed back the well. We had a higher oil cut in that well. So I would say that those would be the primary factors that contributed to the better performance..

And our next question comes from Steven Ascott. [Ph] Please go ahead. .

I was just hoping to see if I could maybe get some color around, you talked about some of the opportunity that you see to drive well costs lower.

I was just hoping to maybe just get some context there and just kind of maybe quantify the magnitude that we should be thinking about?.

Well, I think the primary factors influencing that are how much proppant, how much fluid we’re using in our completions, also lateral length. I mean, we have stuck with the 10,000-foot lateral lengths to date. We’re continuing to evaluate that.

But I would say the primary factor would be proppant, fluid content, and then also we’ve used now fluids in our completions, which adds quite a bit of cost to our wells on the completion side. So those things would be the primary drivers.

We’ve noticed other operators have reduced the amount of proppant that they’re using in some of their completions relative to what we’ve used.

And so you always have a concern about, okay how is that going to impact performance? So those are the factors and I think in terms of costs, markets there were changing clearly but it’s our objective to drill our wells and complete those wells for around $9 million is what our objective is..

Great. That’s helpful. And then I think you mentioned to in the prepared remarks that the Eagle Ford maybe is starting to look a little more competitive here just given where we are with oil prices.

But is that something that you think gets reflected in the 2018 budget? And could you maybe just remind us what sort of commitments leasehold wise you have out there?.

Sure. Yes. So all of our Eagle Ford acreage is HBP, so we’re in no hurry or we’re under no pressure there. There is no primary term lease that we have to worry about.

Just to remind people, I mean, in Karnes County, we have 1,000-acre postage stamp in a very nice area, where all the offset operators around us have down space to as low as 250-foot or maybe even lower well spacing. Our wells that we drilled several years ago were all on a 1,000 foot spacing.

So there’s a lot of oil still in place there on our leasehold. And as prices increase we feel like there may be an opportunity for us to go and further develop some of our acreage. So that is a definitive opportunity for us.

We will review that as we move forward in the budgeting process and make our recommendation, whether it’s to go ahead and develop that acreage now or maybe somewhere a little bit later in the 2018 budget cycle. So that’s probably all I have to say about that at this time..

And it appears we have no more questions at this time..

Okay. Well we’d like to thank everybody for joining the call today and we look forward to sharing our results and success as we move forward into the new year. Thank you..

This does conclude today’s program. Thank you for your participation. You may disconnect at any time. Thank you for calling..