Contango Oil & Gas Company
Q1 2014 Earnings Call Transcript

Published: 11 May 2016

[Operator:]

Good day and welcome to Contango Oil & Gas Company’s Results for First 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, Leo. I’d like to welcome everyone to Contango’s earnings call for the quarter ended March 31, 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 Vice President of Exploration; and Carl Isaac, our Senior Vice President of Operations. I’ll start off by giving you a brief overview of our financial results. I’ll then turn it over to Allan and he’ll give you a brief overview of current operations. And then, we’ll have a Q&A session after that. And as is typical for most companies, we will limit questions to those from analysts that follow our stock closely as we believe that that is a most constructive and productive use of everyone’s time. But, 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 the brief summary of financial results, net loss for the quarter was $11.4 million, $0.60 per basic and diluted share compared to a net loss of approximately $18.6 million in the prior year quarter. We achieved this improvement despite lower revenues related to lower prices and production, due to improvement in cash cost, lower exploration expense and DD&A and a gain on hedging instruments [ph] for 2016. Adjusted EBITDAX, as we defined in our release, was approximately $7.3 million or $0.38 per basic share for the current quarter, compared to approximately $14 million or $0.74 per share for the prior year quarter, a decline attributable primarily to lower revenues, but offset in part by the lower lease operating and cash G&A expenses. Cash flow per share for the quarter was approximately $0.33 per share, compared to $0.70 per share for the prior year quarter. To illustrate the benefit coming from our emphasis on cost improvement, quarter-over-quarter, we’ve reduced cash costs that is LOE excluding production taxes and recurring cash G&A, by 29% and unit cost by almost 29%, despite 17% decrease in production. And we stay focused on further improvement in reducing cost in both of those areas. Production for the current quarter was approximately 7.2 Bcfe, or 79.4 million equivalent per day, compared to approximately 8.7 Bcf, or 96.3 million equivalent per day in the prior year quarter, and that was within Company’s guidance. We have provided guidance of 74 million to 79 million equivalent for the second quarter of ‘16, slightly below the first quarter with roughly the same commodity mix as in the most recent quarter. Until commodity prices show sustainable improvement, we will continue to focus on balance sheet strength rather than expanding capital mainly to maintain production rate. Commodity prices during the quarter were substantially below prior year levels for all products. Our weighted average equivalent price declined 31% from $3.54 per Mcfe to $2.43 per Mcfe. Lower prices contributed approximately 57% to the total decrease in revenue compared to the prior year quarter. In response to the dramatic, but unfortunately -- but hopefully short-term increase in gas prices at the end of year, in January of 2016, we entered into swaps on approximately 60% of our forecasted PDP gas production for February through December at a fixed price of $2.53 per MMBtu; and then in April, we also capitalized on a little run up in gas prices to enter into costless collars for approximately 27% of forecasted 2017 PDP gas production with $2.65 and $3.00 puts and collars respectively. Total lease operating cost, excluding production and ad valorem taxes, were approximately $6.7 million for the quarter or $0.93 per Mcfe, compared to $8.8 million or $1.01 per Mcfe in the prior year quarter, an approximately 24% improvement. We continue to identify and pursue opportunities to reduce field operating cost through efficiencies as well as concessions from our service providers. Guidance for the second quarter is $6.2 million to $6.7 million, excluding production and ad valorem taxes. Exclusive of non-cash stock compensation expense, cash G&A was $4.2 million for the current year quarter or $0.58 per Mcfe, compared to $6.7 million for the prior year quarter, a 37% decrease, resulting from lower incentive based bonuses, reduced staff and related cost, and lower legal fees and franchise taxes. Just as we have done in the field, we have emphasized internally the need to reduce administrative cost. And accordingly, in August of last year, we implemented a reduction in force in our corporate offices to reduce headcount approximately 30%. Guidance for the second quarter cash G&A is $4 million to $4.5 million. We had approximately $112 million outstanding on our credit facility at quarter-end, which was slightly below yearend and have additional borrowing capacity of approximately $26 million under our newly redetermined $140 million borrowing base. The decline in our borrowing base from the previous $190 million level was a function of lower commodity prices and a lack of new reserves being added, as a result of our conservative CapEx strategy in 2015 and ‘16. Our next regular borrowing base redetermination is scheduled for November 1st. Based on current prices and our focus on repaying debt during 2016, we’re optimistic that it will still reflect a comparable facility availability amount after that process, as we expect to be paying debt through the year. In conjunction with the just completed redetermination process, we’re also successfully extending the maturity of our credit facility for two additional years, so it now matures on October 2019. As part of the extension, we also agreed to more market-based pricing and other amendments that are available on the exhibit to the 10-Q. That concludes the financial review, and I’ll now turn it over to Allan for an operations update.

[Allan Keel:]

Thanks, Joe. Good morning, everyone. Thanks for being on the call with us today. I’d like to give you a brief update on what we focused during the quarter, which was another period marked by fairly low prices and continued to post challenges for the industry as a whole as well as Contango. I think everybody is familiar with the drop, continued drop in rig count. For us at Contango, it’s pretty quiet quarter from a capital spend perspective and will likely continue to be fairly quiet from a drilling standpoint until we see a little bit more sustainability or improvement in commodity prices that will help us get more confidence in being able to get up and be active again. As Joe mentioned, we’ll utilize our excess cash flow and reduce debt and continue to focus on trying to identify acquisition opportunities that may serve as the year progresses. We are evaluating each one of our drilling areas for cost, getting a cost update in those areas to see -- particularly as it might apply to putting more capital work, we think that if we can get prices a little bit higher than where they are maybe in the 50 to 60 barrel range and show some sign of stability, we would reengage on our drilling program later in the year. During this quarter, we completed our third well, the Christensen #1 in our North Cheyenne Muddy Sandstone play in Wyoming. We utilized a more robust frac recipe than used in our first two wells with improved results. We didn’t report the IP 24 rate for the Christensen well like we did for the first two wells because we started out producing in a more conservative or restricted rate with the expectation that we might produce a flatter [ph] decline profile over time. And so far that has worked, at least at the initial 30-day average rate of 483 barrels equivalent per day. And that’s slightly better than the first two wells and is continuing on a flatter decline. We remain optimistic that this play will provide meaningful long-term growth but we currently believe that it will take an estimated $55 to $60 barrel oil price to generate our minimum threshold -- rate of return threshold that we would like to see before going into development mode. We have approximately 39,000 net acres in the area and we’ll be able to extend any 2016 expressions for three to five years at minimal cost. We also remain optimistic about the multi-pay potential that we have in the Madison/Grimes, area as we’ve been successful in the Woodbine and Lewisville formations and where we still have meaningful upside potential in the Eagle Ford, Lewisville and Buda in a slightly higher price environment. On the cost side, we have continued our reduction efforts in each and every aspect of our business, drilling, completing, field operations, and in the corporate offices. As Joe mentioned, our recurring period-over-period LOE costs for this quarter were down approximately 23%, cash G&A was down by 37% versus prior year quarter, and we provided guidance for slightly better numbers than those for the second quarter. I guess I’d say on our acquisition efforts, we’ve reviewed and analyzed numerous opportunities, both last year and in the current year. There have been a number of reasons why we haven’t been able to consummate a deal, there is -- reach an agreement with a seller’s -- the bid spread. [Ph] But we do believe that that’s going to continue to narrow as the year goes on. We can continue to look for opportunities that contain a good mix of producing reserves and meaningful resource upside that can that can provide a strong platform for future growth as prices and costs improve. While we consider our acquisition strategy to be opportunistic, our preference is to focus first on all the onshore resource plays in the Texas Gulf Coast or Rocky’s regions where our current areas of concentration are. And we’ll also consider other areas where we might be able to establish an additional onshore platform that could be scalable going forward in such as the West Texas and Midcontinent areas. So that’s just a quick overview. We do anticipate prices to continue to be challenged. So, we believe the appropriate near term strategy is to be conservative with our drilling program and preserve our acreage through extensions of our core positions, use our excess cash flow to reduce debt and remain positioned to capitalize on acquisition opportunities that could provide a good combination of production and drilling upside. So, with that, open it up for questions.

[Operator:]

Thank you. [Operator Instructions] We’ll take our first question from Don Crist of Johnson Rice. Your line is open.

[Ron Mills:]

Hey, Allan. It’s Ron. Thanks for the details on the Christensen IP 24. Just, if you could, could you just provide a little bit more color about how the well performs around IP 30 versus the first couple of wells and get some sort of quantification of the shallower decline rate?

[Allan Keel:]

I’m going to let Carl respond to that. Okay?

[Carl Isaac:]

So, Ron, the Christensen well is a third well in the Muddy and Weston County. And we didn’t reach IP 24s on the Christensen because they really weren’t relative to what happened on the first two wells. We went straight to [indiscernible] on the Christensen well with the 583 barrel 24 hour IP, but 30-day was 483 which is about 20% higher than the Popham, which was just slightly better than the earlier well, the original well. And it was really our idea that within a more intense frac job on the Christensen well, roughly a third more proppant count on the Christensen over the course of the lateral that was relatively the same length as the Popham and Elliot that we might see a better slope on the decline curve, and that’s exactly what we’ve seen through 30 days, and we expect to see that continue.

[Ron Mills:]

And then of your 39,000 acres, there you’ve drilled three wells, how disperse have they been across your acreage position in terms of a de-risking component and how does your lease schedule look up there?

[Tommy Atkins:]

Yes. This is Tommy Atkins. I think we drill those very wells basically I would say in the west half of our leasehold. So, I think that you can feel pretty good about the west half of the leasehold being representative of that leased -- that Christensen well that the most recent well or we feel pretty good about that. Almost all of the leases out here have extension language. So, we feel like that we’re able to maintain this acreage out here at minimal cost for the next three to five years. So, really, I think we’re kind of looking at 2019 to 2021. So, pretty far out there.

[Ron Mills:]

And then last from me. On -- and Allan, you may have talked about it a few weeks ago, but on the deal that you’ll had an agreement on and that eventually didn’t get consummated, is it fair to assume that that was in one of your preferred focus areas of the Gulf Coast or the Rocky Mountains or was it potentially in one of the other areas you also highlighted you would look?

[Allan Keel:]

Yes, it was in one of the other areas, Ron. It’s one that industry favors right now. So, we are hopeful that we can approach that once again, and we are looking for other areas -- other opportunities in that area as well.

[Operator:]

Our next question is from Neil Dingmann of SunTrust. Your line is open.

[Neil Dingmann:]

Allan, can you just talk -- you didn’t say too much about it, but it seems to be pretty stable, as I have always seen your slides, just on the cash flow from the offshore. Do you continue to see that pretty much like we have seen the last quarter to I mean any -- I guess you certainly won’t put any dollars. So, I’m just wondering about how you see that cash flow sort of playing out or at least the production sort of playing out the next few quarters?

[Allan Keel:]

It’s a very steady decline as we -- and we’ve talked about in the past, it’s a depletion drive reservoir, not really a water drive. And so that gives us a lot of confidence predicting what the decline might be. So, we have been able to do that now since we’ve been managing the asset for several years now. So, we’ve worked with our third-party engineers to keep up-to-date on that. And we feel that that asset is just a solid asset that just provides us with cash flow, and it should be -- we see that as being consistent for the going forward.

[Neil Dingmann:]

And then, looking to Southeast Texas, can you talk just what you think as far as inventory or opportunities? I know you guys have talked more on the Woodbine sea and then the upper, lower and middle Lewisville than others, just again, opportunities you have now and are you able to do anything bolt-on that you might have some additional opportunities in that area?

[Allan Keel:]

We certainly hope we can do bolt-on. There is -- we think we’re one of the few of public companies that surely the only probably healthy public company in that area, there are a couple of other guys that are in the neighborhood that have been -- that are being recapitalized or restructured or whatever. But, we think that in terms of the inventory, I think that certainly we still have Woodbine and Lewisville potential across our acreage but we also believe that the Eagle Ford is a very attractive target. There has been quite a bit more drilling for that zone, both adjacent to it and to the south of it. So, we think that there is a lot of potential associated with the Eagle Ford in that area. It’s all just a function of how much is it going to cost to get it out of the ground and what price can you afford. But, the Eagle Ford is productive in our area and that is something that we are trying to evaluate in terms of what it takes to make a good rate of return there.

[Neil Dingmann:]

And then just lastly, not a typical question as far as just what price it takes to run the activity back, I think you addressed that pretty well. How do you and Joe think about -- again, you have able to keep a very balance sheet. How does that factor and I mean if the right price, would you guys take on a bit more leverage, would you do something like that or how do guys think about liquidity leverage in relation to bringing activity back?

[Allan Keel:]

Yes, I think that -- and Joe, you might have a different answer. I think what we would like to do is we would like to find either a singular transaction or a series of transactions that would help further build our story, pivot a little bit more away from the Gulf of Mexico. I mean that is again great asset for us, but we would like to develop more of it onshore, presents with more of an oil focus that has some runway associated with it. So, that’s what we’ve been focusing our efforts on pretty tirelessly here between last year and this year. And we think that ultimately, we will be able to get that done. We are just continuing to scan the market for that type of opportunity.

[Joe Grady:]

And one thing I’ll add to that is historically, we have been pretty conservative and that we stayed within cash flow and to protect our balance sheet. So, again, especially in this price environment, we would continue to do that as we move forward. And it’d just be a matter of allocating resources to those that give us the most value either from a returns standpoint and/or strategic standpoint.

[Operator:]

Our next question is from Kyle Rhodes of RBC. Your line is open.

[Kyle Rhodes:]

You’ve seen a few months of production now from the Muddy wells in Wyoming, just curious how you view that asset competing for capital versus your legacy Southeast Texas assets, if we do get that $50 to $60 oil price?

[Allan Keel:]

I think that’s a very -- we think that the Muddy asset is very competitive; it’s -- we have a large acreage position there. It would be a very core asset for us to be able to develop and very important asset for us to develop. So, that’s something that we’re continuing to evaluate what lateral lanes, what the frac recipe should be. So, there are a lot of moving parts associated with that. But, we really like the play. I think that if we get to those -- to that price point, we would probably be active not only there but also with some of our legacy assets back on in Southeast Texas.

[Carl Isaac:]

One of the advantages we have in Madison, Grimes is lot of that is HPP. And so we don’t have leased uses [ph] that might factor into that capital allocation exercise. But, as Allan mentioned, we do still have a lot of optimism for that play in general. It’s just from a timing standpoint Wyoming is kind of an acreage that needs to factor into the equation as well.

[Kyle Rhodes:]

I think you guys have previously noted that the best way to increase production in 2016 was through an acquisition. It seems like we’ve seen the A&D [ph] market start to fell out a little bit here recently. Any regions you guys are looking at that you see assets maybe more likely to shake loose? And what is the scale that you would need in an acquisition to enter a new region, like West Texas?

[Allan Keel:]

I would say, we’d like to look in our areas where we have existing operational footprint, so that would be Woodbine, Eagle Ford all the way from Southeast Texas, down in the South Texas, but also I would say that would be our first preference. Also, I would say we’re looking at West Texas; obviously things are pretty robust there at the moment, pretty frothy. But, I would say in terms of scale from a production standpoint, maybe 3,000 barrels a day of production, maybe 10,000 acres, 20,000 acres of running room. So that might be a sweet spot for us; in terms of size, maybe $200 million, $250 million or not that we would have to do that; we’re certainly looking for more tactical acquisitions. But if we’re going to do something transformative that would like be more in the ballpark.

[Kyle Rhodes:]

And maybe just to clarify just one point earlier, did you say that you would be interested in going back to reengage the deal that was not consummated earlier this year?

[Allan Keel:]

Yes, well that along with the other things that we’ve looked at, we’re certainly interested in those -- in that area and would like to find an opportunity to grow in that area.

[Operator:]

Our next question is from Stephane Aka of Seaport Global. Your line is open.

[Stephane Aka:]

Just a couple of quick ones for me, one, you’d mentioned that at kind of a $50 to $60 type world, you might be looking to get more active. I was just wondering what -- can you maybe talk about what kind of cost inflation we might see in that type of world?

[Carl Isaac:]

Obviously, I spend a lot of time looking at what happens when we go back up to ramp on commodity prices. And we’ve tuned all of our cost projections, both on the capital and expense side to what we feel like service markets will do in the future. And quite honestly, our greatest concern will be capacity in terms of both equipment and people coming out the other side. And we’ve tried to model that as best we can conservatively, I would say. So, with any luck, our actuals in the future should outperform our current conservative estimates.

[Stephane Aka:]

And then maybe just to follow up on something you touched on earlier, you talked about really having kind of minimal lease exploration issues here going forward. Just wondering, in the context of your -- just thinking about 2017, is it fair to assume that really the capital needs are fairly de minimis at this point versus this year?

[Carl Isaac:]

As far additional explorations, yes.

[Operator:]

Our next question is from James Magee of GMP Securities. Your line is open.

[James Magee:]

Just one quick question on the Western County acreage, if we do see that 55 to 60 price environment, would the next well be going in the northeast, do you think or would you kind of stick to that southwest side of it?

[Tommy Atkins:]

Yes, we would probably still probably stay in the southwest side. But, we’ve got Permian -- because we’re still experimenting with a couple of things and would like to keep the variables minimal, we’ve got -- I can’t remember, two or three spacing units already up in the northeast and so we’re fully prepared to go up there as well. So, we can do both.

[James Magee:]

And just one follow-up on that one. Would you test more frac stages or do you think you’ve kind of maxed out there with the 40?

[Tommy Atkins:]

I think that we would look at as maybe be even longer laterals. We’re getting pretty good uplift on a per stage basis. So, yes, I think more stages is always good. So, if we can recipe just a little bit, so we’ll probably see different things.

[Operator:]

At this time, I would like to turn the call over to Allan Keel for closing remarks.

[Allan Keel:]

I’d like to thank everybody again for joining the call today. And hopefully we’ll have again, another good quarter and give you an update after the end of the next quarter. So, thanks again for your participation.

[Operator:]

This does conclude Contango Oil and Gas Company’s results for first quarter 2016 conference call. You may now all disconnect your lines. And everyone have a great day.