MCF
#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; <UNK> <UNK>, our President & CEO; Steve Mengle, our Senior Vice President of Engineering; <UNK> <UNK>, our Senior Vice President of Exploration; and <UNK> <UNK>, our Senior Vice President of Operations.
I will start off by giving you a brief overview of our financial results then turn it over to <UNK>, and he'll give you a brief overview of current operations, and then we will 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 is the most constructive and productive use of everyone's time.
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.
I'll start with a brief summary of financial results.
Net loss for the quarter was $11.4 million, or $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 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 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 reduced cash cost, and that is LOE excluding production taxes, and recurring cash G&A by 29% and unit cost by almost 29% despite a 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 Bcfe, or 96.3 equivalent per day in the prior-year quarter.
And that was within Company guidance.
We have provided guidance of 74 million to 79 million equivalent for the second quarter of 2016, 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 expending capital merely 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% of 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 the 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 puts and calls, 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 approximate 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 $7 million, excluding production and ad valorem taxes.
Inclusive 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 costs and accordingly, in August of last year, we implemented a reduction in force in our corporate offices and reduced headcount by 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 year-end 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 the lack of new reserves being added as a result of our conservative CapEx strategy in 2015 and 2016.
Our next regular borrowing base redetermination is scheduled for November 1.
Based on current prices and our focus on repaying debt during 2016, we're optimistic that we will still reflect a comparable facility availability amount after that process as we expect to be repaying debt through the year.
In conjunction with the just completed redetermination process, we were also successful at extending the maturity of our credit facility for two additional years, so it now matures on October 1, 2019.
As part of the extension, we also agreed to more market-based pricing and other minor amendments that are available in the exhibit to the 10-Q.
That concludes the financial review and I'll now turn it over to <UNK> for an operations update.
Thanks, <UNK>.
Good morning, everyone.
Thanks for being on the call with us today.
I would like to give you a brief update on what we focused on during the quarter, which was another period marked by fairly low prices and continued to pose challenges for the industry as a whole as well as Contango.
I think everybody is familiar with the drop and continued drop in rig count.
For us at Contango, it was a 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 out and be active again.
As <UNK> mentioned, we will utilize our excess cash flow to reduce debt and continue to focus on trying to identify acquisition opportunities that may surface as the year progresses.
We are evaluating each one of our drilling areas for cost to get a cost update in those areas to see particularly as it might apply to putting in more capital to work.
We think that if we could 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 did not report those IP24 rate for the Christensen well like we did the first two wells, because we started out producing at a more conservative or restricted rate with the expectation that we might produce a flatter 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 rate of return threshold that we would like to see before going into a development mode.
We have approximately 39,000 net acres in the area and we'll be able to extend the 2016 expirations for three years 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 have been successful in the Woodbine and Lewisville formations and where we still have meaningful upside potential in the Eagle Ford, Lewisville and Buda at 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 <UNK> 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 have provided guidance for slightly better numbers than those from the second quarter.
I'd say on our acquisition efforts, we have 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's recent agreement with the sellers, the bid-ask spread, but we do believe that that's going to continue to narrow as the year goes on.
We continue to look for opportunities that contain a good mix of producing reserves and meaningful resource upside that could 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 oily onshore resource plays in the Texas Gulf Coast or Rockies regions, where our current areas of concentration are.
But we will also consider other areas where we might be able to establish an additional onshore platform that could be scalable going forward such as the West Texas and Mid-Continent areas.
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, 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.
Yes.
Sure, <UNK>.
Thanks.
I'm going to let <UNK> respond to that, okay.
So, <UNK>, the Christensen well was the third well in the Muddy in Weston County, and we didn't release IP-24s on the Christensen because they really weren't relative to what happened on the first two wells.
We went straight to rod pump on the Christensen well with the 583 barrel 24-hour IP.
But the 30-day was 483, which is about 20% higher than the Popham, which was just slightly better than the Elliot well, the original well.
It was really our idea that with a more intense frac job on the Christensen well with roughly one-third more proppant 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 have seen through 30-days and we expect to see that continue.
Yes, this is <UNK> <UNK>.
I think we drilled the three 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 at least the 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 are able to maintain this acreage out here at minimal cost for the next three years to five years.
So really I think we're looking at 2019, 2020, 2021.
So pretty far out there.
It was in one of the other areas, <UNK>.
One that industry favors right now.
We are hopeful that we can approach that once again and we're looking for other opportunities in that area as well.
Yes, it's on a very steady decline as we, I think we've talked about in the past, it's a depletion drop reservoir, not really a water drive.
And so that gives us a lot of comfort in predicting what the decline might be.
We have been able to do that now since we have been managing the asset for several years now.
We work with our third-party engineers to keep up to date on that and we feel that asset is just a solid asset that provides us with cash flow.
And it should be, we see that as being consistent going forward.
We certainly hope we can do bolt-on.
We think we are one of the few public companies and certainly the only healthy public company in that area.
There are a couple of other guys that are in the neighborhood that are being recapitalized or restructured or whatever.
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 have been quite a bit more drilling for that zone both adjacent to us and to the south of us.
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 get for it.
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.
<UNK>, 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.
That is our, again, a great asset for us, but we would like to develop more of an onshore presence with more of an oil focus that has some runway associated with it.
That's what we have been focusing our efforts on pretty tirelessly here between last year and this year.
We think that ultimately we will be able to get that done.
We're just continuing to scan the market for that type of opportunity.
And one thing I will add to that is historically, we have been pretty conservative in that we have stayed within cash flow to protect our balance sheet.
So again, especially in this price environment, we would continue to do that as we move forward.
And it would just be a matter of allocating resources to those that give us the most value either from a return standpoint and/or a strategic standpoint.
I think that's a very ---+ we think that the Muddy asset is very competitive.
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.
That's something that we are 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 that price point, we would probably be active not only there but also in some of our legacy assets back down in Southeast Texas.
One of the advantages we have in Madison and Grimes is a lot of that is HPP.
We don't have lease uses that might factor into that capital allocation exercise.
But as <UNK> mentioned, we do still have a lot of optimism for that play in general.
It's just from a timing standpoint, Wyoming is term acreage that needs to factor into the equation as well.
I would say we 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 into South Texas.
But also, I would say that would be our first preference.
Also I would say, if we were looking in West Texas, obviously things are pretty robust there at the moment and pretty frothy.
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.
That might be the sweet spot for us in terms of size.
Maybe $200 million to $250 million, 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 probably be more in the ballpark.
Yes, that along with other things that we have looked at.
We are certainly interested in those in that area and would like to find an opportunity to grow in that area.
This is <UNK> <UNK>.
Obviously, that's something we spend a lot of time looking at, what happens when we go back up to ramp on commodity prices.
And we have tuned all of our cost projections, both on the capital and the 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 other equipment and people coming out the other side.
And we have 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.
As far as additional expirations.
Yes.
Yes, we would probably stay in the Southwest side, but we got permit ---+ because we are still experimenting with a couple of things and we'd like to keep the variables minimal.
But we've got, I can't remember, a couple, two or three spacing units already up in the Northeast.
So we are fully prepared to go up there as well.
We could do both.
I think that we would look at as maybe even longer laterals.
We're getting pretty good uplift on a per stage basis.
I think more stages is always good.
Still tweaking the recipe just a little bit.
We will try a few different things.
I would like to thank everyone again for joining the call today and hopefully, we will have another good quarter and give you an update after the end of next quarter.
So thanks again for your participation.
