Battalion Oil Corp (BATL) 2014 Q4 法說會逐字稿

Good day, ladies and gentlemen and welcome to your Halcon Resources 4Q 2014 and full-year 2014 earnings conference.

(Operator instructions)

I would now like to introduce your host for today's conference, Chairman and CEO, Floyd Wilson. Sir, you may began.

Thank you. Good morning. This conference call contains forward-looking statements. For a description of our disclaimer, see our earnings release issued yesterday afternoon and posted on our website.

From an operational standpoint, 2014 was another good year for Halcon. We consistently exceeded production expectations despite through the second half of the year reducing rig count throughout.

Proved reserves increased by 60% during the year and drill-bit reserve replacement was 570%. We reduced our 2015 drilling completion budget several times over the past few months. Service costs have come down significantly and continue to come down since the beginning of the year.

Company wide, we currently have 26 operated wells being completed or waiting on completion. We are operating three rigs, two in the Williston and one at El Halcon in east Texas.

Up in North Dakota, we had 57% production growth year over year in 2014. We are concentrating our two rig drilling program during this year in our highest return area and since it's only two rigs, there's minimal impact to our operated drilling inventory because of the low rig count.

Completed well costs in this area have come down 25% since the fourth quarter of 2014. We expect to see more. The current AFE for wells drilled on acreage in the Fort Berthold area is less than $8.5 million.

Wells we spud in that area continue to outperform our published 800,000 BOE type curve. Drilling and completion efficiencies are ongoing as always at Halcon.

Our drilling cycle times, spud to rig release improved by over 20% on the reservation and approximately 15% in Williams County last year. Our completion cycle times rig release to the end of the completion improved by over 30% company wide.

During 2014, up in North Dakota, we have been utilizing a modified or hybrid water slickwater completion design in an effort to further decrease completed well costs and the results have convinced us to move forward on this completion design on most wells. This frac job is designed to place the same amount of proppant, but uses less water. We also had some success in reducing operating costs: more efficient power sourcing, better produced water offloading solutions, better chemical programs and effectively managing our work-over program including offset frac preparation.

We also continue to make progress in pipeline construction to increase gas capture. Approximately 84% of our gas produced in the Williston basin is now being sold, which is well above the limits imposed by the NDIC.

At El Halcon in east Texas we had production growth of 136% year over year. We operated an average of three rigs in El Halcon during the fourth quarter, but we quickly dropped two of those rigs and we have one rig running there now. Our 2015 drilling program is designed to capture leases and hold acreage.

We remain focused on identifying ways to reduce completed well cost. The current AC for wells we drilled in El Halcon is approximately $8 million or a little more than 20% lower than where we were for most of the fourth quarter.

We anticipate completed well cost will decline by an additional 10% to 20% by mid-year. Aside from across-the-board service cost reductions, we are also in-sourcing certain items to reduce middlemen cost: some directional work, several types of supervisor work we brought in-house.

On the completion side, we are looking to direct the source of materials for our frac jobs. Plus, we have been providing our own chemicals since December and this is going quite well.

It is important to keep in mind that we're still in lease capture mode at El Halcon, which means we are only drilling one well pad per drilling spacing unit. This means that the current AFE includes full cost for location, [tile opinion], production facilities, gathering, tie-in and artificial lift expenditures, all charged to the first well. That is about $1.25 million on per-well basis that you would expect to see reduction once we are in development mode.

Drilling efficiencies continue to be realized. Our drilling cycle times for three string wells improved by approximately 30% in the second half compared to the second half of 2013. Our completion cycle times at El Halcon improved by more than 35% throughout the year. Bottom line, we have 100,000 net acres in the core of this great oil play and we will keep that position vibrant.

Mark, go ahead with the financial results.

Okay. Thanks. I will give begin with a review of the full year 2014 results as compared to guidance and also touch on fourth-quarter results. Production for the year came in above our guidance on average, right at 42,107 barrels of oil equivalent a day. Production in the fourth quarter was 46,076 BOE a day, which is actually a record for the company.

On the cost side, LOE was $9.52 per BOE in 2014, which is within our guidance range and about 20% lower than prior year and LOE was right at $9 per BOE for the fourth quarter. After adjusting for some selected items, cash G&A was $5.98 for the year. It came in well below guidance and about 33% lower than 2013.

If you look at G&A for the fourth quarter, it came in at about $4.80, representing about a 21% improvement quarter over quarter the second half of 2014. Taxes other than income were $6.92 per BOE, which is in-line with guidance. As such, you can see overall operating costs across the board this past year have improved and we will continue to see some improvement in 2015.

We did end the year with liquidity at about $553 million, which consisted of our undrawn revolver capacity plus cash on hand and we were right at about $580 million of liquidity if you take into consideration the December hedge developments that we collected in the first week of January. As disclosed in our earnings release, the $1.05 billion borrowing base within our revolving credit agreement led by [Tracy Morgan] and Wells Fargo was recently reaffirmed in conjunction with our regular spring redetermination.

In this environment, that just further validates the quality of the core assets combined with the hedge book that we have in place. This liquidity position clearly sets up the company nicely to fund its 2015 operations and well into 2016.

With regards to D&C funding, we spent right at $1.2 billion last year, which was more or less in line with expectations. We are very focused on both capital discipline and efficiency in 2015, as indicated by our reduced 2015 capital budget.

Our current BFC budget for this year of, call it $350 million to $400 million is still going to translate into about 5% production growth. In addition to the reduced budget in 2015, it puts our capital spend more in line with cash flow.

We did recently reaffirm previously disclosed production and cost guidance for 2015 and provided first quarter 2015 production guidance in our earnings release issued yesterday. We expect production to be relatively flat in the first half of the year with an overall growth rate of 5%. D&C CapEx will be front-end loaded, primarily due to the number of wells that are currently being completed or waiting on completion.

Finally, with regards to our hedge portfolio, we did have a mark-to-market right around $0.5 billion. On our hedges today, we have about 31,332 barrels per day of oil hedged in 2015 at an average price of just over $90 a barrel.

For 2016 we have about 20,497 barrels of oil hedged at an average price of just under $85 a barrel. When all our hedging for 2015 is complete, we will continue to layer in additional hedges in 2016 to attempt to hedge about 80% of what we expect to produce at an average floor no less than $80.

With that, I will turn the call back over to Floyd.

Thanks, Mark. So here we are in the middle of the quarter, first quarter this year. Things have changed dramatically from last year, but they are changing all around the board, not just on oil prices.

Costs are screaming down and we are finding that we are targeting single well rate of return targets, single rate of return investments that are similar to what we had last summer with lower costs. We are comfortable with our liquidity right now and this year's drilling program. Our strong hedge portfolio has positioned us well in this environment.

Having said this, we are not the kind of company that sits around and hopes that things get better over time. We are constantly thinking about ways to strengthen our balance sheet, which in turn will put us in a better position to take advantage of opportunities in the areas that we care about. We have been through this before and we will be through it again sometime.

I think that is all I have to say. Operator, you can take a few questions if there are any.

(Operator instructions)

Neal Dingmann, SunTrust.

Good morning. Two questions; first, you previously mentioned in your prepared remarks about the Bakken well costs. I know those continue to come down for you. Could you discuss about, as far as how much ceramic you use in proppant? I'm wondering there if you're pretty set in the current recipe or could you continue to cut costs with that?

Neal, [Charles is here] I will make a brief comment and then he will really respond. It looks like we're going all the way to white sand. We've had enough wells and our peers up there have drilled enough wells with this. We haven't really seen a huge difference and it saves a lot of money per well; [$0.5 million to 1 million] barrels, depending on which will you are on. So some of the cost reductions are due to different design, but a lot of the cost reduction is due to lower service costs. Charles, what would you add to that?

That pretty well covers it, but the key is what Floyd says, going 100% white sand. That cuts that $0.5 million or so off of it. We have, with our large [non-opposition], we're in with a lot of other companies. There's enough production history now from wells that just have 100% white sand and say we don't see any difference in the basin. So we are very confident going in that direction.

Also Neal, in certain areas, putting some gel in a slickwater frac reduces the water requirement and in the north, water is not quite as expensive and down at Fort Berthold, it is quite expensive. So that's a big factor as well.

Good. Great point. One last follow-up, Floyd, wondering, you look at liquidity out there, obviously you guys have no problems there. How do you view the M&A market or more specifically, are there any bolt-on opportunities you have and any interest in doing any step-outs with this kind of macro environment?

We're very comfortable where we are. We will continue to grow the Company for the next few years and see what goes on. The M&A market seems to be a bit quiet right now. There is a lot of shock out there with how quickly things have moved. Historically, these times create opportunities and we certainly have our eyes open. We are very focused on quality and core-area discipline, so you wouldn't expect us to try to do anything that wouldn't follow those comments.

That makes sense. Thank you.

Ron Mills, Johnson Rice.

Good morning, Floyd. For you or Charles, on the production history with the hybrid slickwater and or with the use of white sand versus the resin coated sand, how much production history do you have on using those methods? Do you still feel comfortable that the wells are outperforming as we see in your new presentation?

We have about a year on three wells that are all white sand. The ceramic wells, we have a couple of years now, plus others. But in our non-op wells and wells around us, there is a couple of years on all of them. And we don't see any difference at all. The bigger differences are the amount of profit in place, not the type.

Okay. As you talk about self sourcing portions of it, Floyd, I think you mentioned mud and maybe even some proppant and chemicals, how much of that $1.5 million of cost savings so far do you think is related to the self sourcing versus vendor pricing?

There's some of all of that in there. The self sourcing is more along the lines of supervisory services, which we used to farm out a lot. We are trying to do as much of that in-house as we can. So it is a combination. But over time, we expect this in-house in-sourcing that we are doing to be quite a factor. And also, not that we weren't close, but keep us really close to exactly what is going on minute by minute. We stay close, as you can tell from our results, but we will be even closer.

All right. Mark, on the hedging side, obviously, 2015, it looks like you are pretty much done. As you look to 2016, how dynamic has the hedge market been, given the volatility in this, in other words, ability to look out 12 to 18 months from now and structures allow you to meet that $80 minimum floor?

There has been pockets of opportunity. We have been able to layer in some additional hedges. But really what we have been doing and are looking to continue to do is slight better restructuring where we can take some value out in the future year, bring it forward and utilize it to maybe buy up a position whenever you get a little bit of a run in the oil market. So we have a plan where we think we are going to be able to, depending obviously on what the markets do exactly, but we don't have that much further to go to reach our goal of about 80% of anticipated production hedge at around $80.

That is for 2016, Ron.

Right.

Keep in mind, it's not a -- it takes two hands to clap, right? So it's not just the hedging. It's contango now, which is usually the signal you should be hedging. And costs have come screaming down, so it is a different scenario than it was before. We have a group led by Mark and some others here that are constantly viewing, almost minute by minute what is going on in the hedge markets and we intend to continue to be very active in that.

All right. Lastly, on the production profile, Mark, for the year -- or maybe Floyd, you plan on -- do you expect it to be pretty linear in terms of pace of completions through the year? Or is it going to be more concentrated?

Like much of the industry, we are working with service providers to get cost in appropriate level. And sometimes, regrettably, that requires waiting. So, it is not exactly linear. We are pulling the trigger. Charles' group is pulling the trigger on frac jobs on a very specific basis, based on how fair we think that the pricing is, given where we are in this cycle. We have clearly postponed some fracs and we have cut rig count down. So I think you are going to see that we are going to try to manage that frac schedule so as to keep things flattish for the year, while overall, year-over-year, we are going to be up, we think.

But, it's not perfect. You are doing pad drilling up in North Dakota. And it's not like you can give somebody one well because you need to frac all of the wells that you drilled on the pad at once. At El Halcon it's a little different. We are drilling single well pads for the few remaining lease capture items that we have on our ticket. We intend to keep it a little flattish, but it is probably going to be a little lumpy because we have to wait for our partners in the service industry to give us a hand here.

Great. Thank you.

Michael Rowe, Tudor, Pickering, Holt & Company.

Good morning. I was wondering if you could maybe speak a little bit to where your corporate PDP decline rate is today and given the reduced activity level in 2015, how that could change as you enter into 2016?

In a general sense, and I don't have the exact numbers in front of me, the corporate decline rate when you drill in more shale wells, more horizontal wells, is higher, so it's going to be around 30% to 35%. When you're drilling fewer wells, the decline rate is lower. It's going to be closer to 25%. That's about where we are today. This can change. It all has to do about scheduling. So if you wanted to try to muddle this, if we said we're going to grow 5% or 10% this year, we'll have to overcome a 25% decline as well.

Okay. That is helpful. You do have quite a large acreage position [in El Halcon], given your size and current level of drilling activity, you are seeing some service costs reduction so far, but still waiting to get to full development that will really bring those down more. So I was wondering and I know you don't have liquidity issues now, but have you considered partnering with [alternative] operators to try to fast track that process to get to the full development and bring down that cost structure further?

Michael, at our Company, everything is on the table all of the time.

Fair enough. Thank you.

Our next James Spicer, Wells Fargo.

Hello. Good morning, everybody. I have a couple of quick questions on the balance sheet, probably for Mark. First of all, can you talk a little bit about how you view the appropriate level of leverage and/or absolute debt in a price environment that could be lower for an extended period of time? As a follow-up to that, you mentioned that you are looking at some possible ways of strengthening the balance sheet. I wondered if you could elaborate on that a little bit.

As we have indicated, leverage is higher than we want to be, of course and that is something that we are focused on. There are some thoughts here in the Company that we have been working on, on ways to bring that down. Obviously, we can't get into specifics on what may or may not happen in the future, but we're obviously very focused on it. That is also reflected in what we have done with our 2015 capital spend to try to stay as close to within cash flow as possible so that number doesn't continue to creep up too much on us.

Appropriate level of leverage would be at least a third less than we have, but we don't have that right now. So we have backed off the spend. We have done a lot of hedging. We have made other reductions around the Company so that we can get through this. And we will. Of course, it would be lovely to have less leverage than we have right now. If you would of called me a year ago and said that we were going to have this oil price, we would have less leverage than we have right now. But you didn't call me.

(Laughter) So it sounds like there is nothing that you can provide at this point in terms of additional detail on specifics about what you are looking at?

Not at this time. No, thanks, though.

Okay. One more question on the borrowing base redetermination. I thought that was great news that, that was reaffirmed. Can you clarify that you are in the clear now for the next six months as far as borrowing base redetermination goes and a little bit about what drove the banks to ultimately reaffirm you guys at the current level.

Look, [Michael], that is sort of a Mark question. But let me just a we have a long history with all of our banks. We have a long history of strong production reserve growth, which we delivered last year as well and this weighs heavily into their thoughts. Our big hedge book also is a big factor for this because they are driven by loan price decks.

So Mark got 100% of the banks in. And we are good until the next time of redetermination and we will see what goes on then. But I point out that we have a very strong hedge book at that moment too, in the fall for this year and for 2016. So, it is a combination of experience that the banks have with us and Mark's foresight in making sure that we hedge.

All right. Thanks a lot, guys.

Chad Mabry, MLV & Co.

A question on reserves; obviously, a strong reserve report that you put out last week. I was hoping to get a little color on your inventory up in the Bakken. I was curious how much [Netherland Sewell] gave you credit for on the 660 foot downspacing? Any color you could give on -- (technical difficulty).

Obviously, the location count goes up and down with oil prices. And we have this five-year limitation within our estimates of all of those kinds of things. The great news -- the sideline to the bad news of low oil prices is there was a low rig count. We're barely touching our inventory of locations. The location spacing, and Charles is sitting here -- I want him to add if I blow this question, but it is very dependent on where you are in the field and we feel it is very dependent if you are drilling Three Forks wells, top bench Three Forks wells right underneath your middle Bakken wells.

So it is not just a question of well, it's [660] or 800,000 foot. It is different across the field and it is a highly technical discussion that leads to us to draw our conclusions. There is clearly lots of the field that's good for 660 and there's some of the field where the Three Forks is quite good that you might not want to quite drill it that much or you might drill more Three Forks than you would and less middle Bakken. So we don't really publish that inventory number. It is in the hundreds and hundreds and hundreds of wells. Charles, what else would you say?

My only general comment on that, I would say is NSA did not give us credits for as tight as we are actually drilling right now. And we are drilling everything on 660s or 880s [foot], depending on existing wells that are in that unit already. We have 20 operated the DSUs, all in Fort Berthold, that are already what we call downspacing tests. And they are not tests anymore, because that's the norm these days. It's not just us. It's all of the other operators in the basin as well.

That is very helpful. That is all I have. Thank you.

Gary [Stromberg], Barclays.

Good morning. A follow-up, Mark, on the borrowing base question. When will the next borrowing base redetermination be and do you have any expectations on where that could wind up?

Yes, Gary, the next redetermination will be in the fall. We technically do that in the October, maybe into early November timeframe. Where it is going to go will clearly be dependent on what commodity prices do. But again with the hedges that we have in place, we will have some protection there. We are also going to have the impact of drilling between now and then. That will, of course, be beneficial to the redetermination.

With our hedge book, I would be surprised it changes, but I could be wrong.

Okay. Do you know what price deck the banks use for the $1.05 billion borrowing base?

Every bank, as you would expect, is a little different. The [JP] deck I believe starts in the high 40%s and I think worked up to a long-term price in the 70%s, 75%s, somewhere in that ballpark.

Okay. And then, Mark, on the budget, $350 million to $450 million, I know that doesn't include capitalized costs. How should we think about capitalized costs this year?

I believe probably $150 million to $200 million.

Okay. That is all I have. Thank you.

Jason Gilbert, Goldman Sachs.

Hello. Good morning, guys. Thanks for taking my question. A production guidance question; I think you said the backlog of wells uncompleted right now was 26 maybe. I was wondering, where do you see that at year-end 2015, where do you see the exit rate 2015 production versus where we were at year-end 2014?

This current level has been driven by postponing frac jobs. Last year, at the end of 2013, we had 20 or 25 wells that were waiting on completion that were driven by a higher rig count. At the end of this year, assuming costs come into line, we would guess this inventory would be a bit smaller, but we will still have an inventory by the end of the year. It is just timing and particularly up in Fort Berthold, doing three and four and five fracs at a time on pads. It is inevitable we will have some.

It is not a matter of us not going to frac the wells, we're just trying to get the costs in sync with what the real-time oil prices are unhedged. And that is coming into line. So we are about to release some new frac work and we are bidding everything several times because it is changing for the service providers too. So the inventory will be up and down a little bit during the year, but I'd say it would be down by the end of the year a bit. We will still have 10 or 20 [wells] by the end of this year, though, 10 or 15. We don't really project that right now.

Okay. Also, you mentioned the Fort Berthold wells were generally up in the type curve. [Any thoughts on when you might account for the type curve?] (technical difficulty)

Was that about changing the type curve, was it?

Yes.

No. The data is out there. You can make a type curve that is a lot higher. We are doing a lot of 1 million barrel wells, 1.25 million barrel wells. No, I don't think so, just accept it. There is a lot of daylight there and we will come out with something sometime. But it just doesn't seem important right now.

Okay. And last one, if I might. What are your plans for the [Utica] -- (technical difficulty).

We have no plans this year for the Utica, the northern Utica nor the TMS. We have some good land there. There is lots of gas up in the Utica and there is lots of oil in the TMS, but the prices and our concentration and our better targets that we have at El Halcon and North Dakota demand that we don't do anything with those at this time.

Will much of the inventory expire up there if you don't do any drilling? In the TMS or the Utica?

No, hardly any. We have a pretty rigorous process and we've winnowed that acreage down that we've kept on our books as valid acreage. So no, we don't have hardly any expirations up there.

Great. That is super helpful. Thank you.

Jason Wangler, Wunderlich Securities.

At El Halcon, you talked about, obviously, just drilling the one wells and where are we in the lease capture side of this business? Is it next year when we're going to start looking at pads and the cadence of that?

I can answer that. That is our current plan right now. As Floyd mentioned earlier, it is over $1 million, $1.25 million less cost once you go into development mode. So that gives you an extra 10% to 15% rate of return on top of that.

We are probably around 75% or plus or minus rate of the lease capture. Some of the leases, we don't care about because they are small chunks within units that we control. It's like the frac jobs, if you're going to release something, you have to wait for the lease prices to get in sync with oil prices. So you don't rush around to do anything. We will hold all of the acreage that we really care about with our drilling program this year and the first part of next. And we will be into pad drilling sometime next year towards the end of the year.

That is helpful. Thank you.

We have no further questions in the queue. I would like to turn the call back to Mr. Floyd Wilson for closing remarks.

There are no remarks. Thanks for dialing in and if you think of something we didn't answer, just give us a call. Thank you, operator.

Ladies and gentlemen, thank you for participating in today's conference. This does conclude the call. You may now disconnect. Everyone, have a wonderful day.