Emerald Oil's CEO Discusses Q4 2013 Results - Earnings Call Transcript

Mar.13.14 | About: Emerald Oil, (EOX)

Emerald Oil, Inc. (NYSEMKT:EOX)

Q4 2013 Earnings Conference Call

March 13, 2014 10:00 a.m. ET

Executives

Ryan Smith - VP of Capital Markets & Strategy

McAndrew Rudisill - President & CEO

Analysts

Ron Mills - Johnson Rice

Steve Berman - Canaccord Genuity

Ryan Oatman - SunTrust

Blaise Angelico - Howard Weil

Curtis Trimble - Global Hunter

Paul Grigel - Macquarie

Operator

Greetings, and welcome to the Emerald Oil Fourth Quarter and Year End 2013 Financial and Operational Results Conference Call. At this time, all participants are in a listen-only mode. (Operator Instructions) As a reminder, this conference is being recorded.

I would now like to turn the conference over to Mr. Ryan Smith, Vice President of Capital Markets and Strategy. Thank you, Mr. Smith. You may now begin.

Ryan Smith

Thanks you, and good morning. This is Ryan Smith, Vice President of the Capital Markets and Strategy. Welcome to Emerald Oil's 2013 Year End Earnings Conference Call. Yesterday afternoon we issued a press release and also the Form 10-K to report our financial and operational results for the quarter and year ended December 31, 2013.

On the call with me today is McAndrew Rudisill, our Chief Executive Officer. Please be advised that our remarks, including answers to your questions may include statements that we believe to be forward-looking statements within the meaning of the Private Securities Litigation Reform Act.

Forward-looking statements are subject to risks and uncertainties that could cause actual results to be materially different from those currently disclosed in our earnings release and conference call.

Those risks included, among others, matters that we have been described in our earnings release, as well as in our filings with the Securities and Exchange Commission including the Annual Report on Form 10-K and our Quarterly Reports on Form 10-Q. We disclaim any obligation to update these forward-looking statements.

During this conference call, we will also make references to adjusted EBITDA, which is a non-GAAP financial measure. Reconciliation of these amounts to GAAP measures can be found in our earnings release.

I will now turn the call over to McAndrew.

McAndrew Rudisill

Thank you, Ryan, and good morning. We will begin with some general comments, and then we will open the call for questions. We exceeded our annual guidance for 2013. Our 2013 average annual production increased by 80% year-over-year due to the success of our operated drilling campaign.

Our Middle Bakken wells continue to exceed type curve expectations, and we are actively evaluating our stated Low Rider type curve along with increased downspacing assumptions across our 63,000 net acre position in McKenzie County.

Our second Three Forks well, the Caper 3 had a 24-hour IP of approximately 1,300 BOE per day. We are very encouraged with the results of our initial Three Forks wells and continue to permit and drill more as we move south.

The previously announced third rig is currently moving two locations and will begin drilling at the end of March. Once the rig finishes drilling well within our Easy Rider focus area of Williams County, it will then move to the Emerald Pronghorn sand in the summer.

Despite the verily cold weather experienced across the entire Williston Basin year-to-date, we continue to feel comfortable with our 2014 average annual and exit rate guidance.

In the first quarter, we experienced weather-related frac delays, which could result in a first quarter production shortfall of between zero and 10%. Due to the large amount of production coming online during the back half of the first quarter and beyond, production in the second quarter will be higher than our previous guidance, and we plan to increase quarterly, annual, and exit rate guidance on the first quarter earnings call.

We are waiting until the first quarter call in early May, because at that point in time, we'll have analyzed over one-year data from certain Low Rider wells.

We successfully [cored] up multiple operated units in Richland County, Montana. This area has both recent Middle Bakken and Three Forks well control, and we are very encouraged by the strong results. We believe our style of completion of Low Rider can be replicated in Richland County due to geologic similarities. We anticipate a potential fourth rig addition will be used to develop this area and our Lewis & Clark position later in 2014, and will be financed through both our borrowing base and accessing fixed income markets.

Accounting for closed and pending acquisitions, we now have approximately 85,000 net acres in the Williston Basin with approximately 64,000 net acres or 75% being operable.

During the fourth quarter, we produced an average of (technical difficulty) BOE per day which produced total oil and natural gas sales of (technical difficulty) million of adjusted EBITDA. For 2013, we produced an average of 1,688 BOE per day, an 80% increase over 2012, which produced total oil and natural gas sales of $54 million and adjusted EBITDA of 20.2 million.

Our focus in 2014 is to grow production and cash flow. Continue the success (Technical difficulty) efficient drilling and completion and began to realize cost efficiencies derived from centralized infrastructure.

I will now turn the call over to Ryan to review our financial results and outlook.

Ryan Smith

Thanks, McAndrew. Pro-forma for the closing of the February 2014 Low Rider acquisition plus cash on hand at year end, we ended 2013 with approximately $105 million in cash and $35 million drawn in our revolving credit facility. We are currently in the process of assuming (technical difficulty) revolving credit facility which should be completed by April.

We believe that our cash on hand combined with cash flow from operations available (technical difficulty) three rig drilling program for the remainder of 2014.

We are maintaining our previously stated 2014 capital budget for well development at $182 million to drill and complete approximately 18.2 net operated wells at or below our previously estimated cost of $10 million per well.

We're maintaining our estimate net of cash received in acreage trades of spending approximately $125 million in 2014 to acquire operated acreage in the core of the Williston Basin. It should be noted that our land budget include (Technical difficulty) a 75.1 million in February 2014 acquisition amount. Our entire capital budget continues to be focused exclusively on the Williston Basin.

Revenues for the quarter and year ended December 31, 2013 were 17.9 million and 54.0 million respectively. The fourth quarter of 2013 revenue represents a 22% increase over third quarter 2013, while annual 2013 revenue represented 92% increase over the same period of 2012 (technical difficulty).

The increased expense is primarily due to the development, execution and acceleration of our operated drilling program. While the increased costs are primarily associated with workovers, artificial lift installations and the use of specific drilling equipment, these items have improved well performance and reduced downtime. As we and other industry players continue to successfully develop (indiscernible) Central and Southern McKenzie County, we anticipate further cost efficiencies.

We have guided to an annual 2014 LOE per barrel of $11, and we remain comfortable with that estimate. We also incurred two separate one-time G&A expenses in the first quarter. The first consisting of $2.8 million stock-based expense related to the severance of a prior officer of the company, and the second a $2.4 million cash charge attributed to transaction related fees and expenses.

For the quarter and year ended December 31, 2013, the company recognized unrealized non-cash losses on its warrant liabilities of $2.5 million and $7.1 million respectively.

This mark-to-market charge relates to the warrants attached to the preferred stock issued to White Deer Energy in February 2013. The warrant liability will correlate with the stock price performance of Emerald on a quarterly basis, each quarter going forward Emerald will mark-to-market, the warrants and adjust for the change in the statement of operations is a non-cash charge.

During the fourth quarter, our average sales price for crude oil was $84.18 per barrel, and we are currently hedged with swaps at $92 to $97 per barrel. Our credit facility with Wells Fargo allowed us to hedge a portion of our existing production, and we are near the maximum allowed. We plan to continue adding hedges as our production grows.

Our dedicated [Wheatland] (ph) pipeline is operational, and we are currently shipping crude through it. This pipeline improves our differentials about $1.50 per barrel, and we will retain the optionality to ship to other markets of differentials or superior.

At this time, we'd like to open the call for questions. I will turn the call over to our moderator.

Question-and-Answer Session

Operator

Thank you. (Operator Instructions) Our first question is from Ron Mills with Johnson Rice. Please go ahead.

Ron Mills - Johnson Rice

Good morning, guys. McAndrew, just to follow-on what you talked about wells outperforming, if I look at your new presentation and see the slide with all your cumulative production from your operated wells, obviously above the -- the type curve, is that the primary driver behind what you think will be an increase in guidance once you come to your first quarter call, or is there also a component that's related to once you get these completions that were delayed in late January, early February flowing through, that momentum combined with drilling efficiencies and potential, just maybe even drilling more wells, is that part of the equation too? Is it solely based on the well performance?

McAndrew Rudisill

Ron, thanks for the question. It's all good points that you raised. So, the type curve is obviously a primary driver in adjusting the production expectations for the balance of the year. But what we found over the course of the last couple months is that we've become a lot more efficient in drilling the wells. It's taking us less time to drill them. When the weather is less of a factor, we become a lot more efficient at tracking these wells, and due to the efficiencies and the lower amount of days because they're required to drill in the lower amount of days that we're using to frac, that's definitely a contributing factor to why the production will need to increase over the course of this year. And then there is a specific component in the first and the second quarter, because of the bulk of production that we have coming on in the back half of March here as well as into April and May because of the delay in fracking due to the cold weather in February that's going to cause the second quarter production to rise.

So, all of those three factors are contributing to why the production numbers are going to need to increase over the course of the year.

Ron Mills - Johnson Rice

And then, to drive that increase, I know you announced both Bakken and Three Forks well, but with two rigs running, where are you in terms of -- and given that you didn't -- intentionally didn't complete a lot of wells for mid January, mid December to late January, how does your inventory of drilled/uncompleted wells sit and just trying to get some visibility to the timing of those completions?

McAndrew Rudisill

Yes, we have been using one frac crew over the course of the last couple of months. We are going to move to two frac crews for a period of time here to backfill some of those wells that we were drilled in the fourth quarter and in the first quarter that we were able to frac in January and February.

We actually plan no fracking operations in January purposefully just because of historical weather conditions that just ended up being substantially colder in February, we got started a little bit later. And that's one of the reasons why we are bringing the second frac crew on here in March and April to get those wells fracked at our drill.

Ron Mills - Johnson Rice

Okay, great. And then lastly, any commentary about -- you mentioned (indiscernible) in the release, in addition to type curve looking at reviewing drilling inventories that relates to spacing, is that solely given years in some offsetting Three Forks results, or you're also thinking about potentially more than four Bakken wells per DSU? Just little more color on that inventory comment.

McAndrew Rudisill

We've been using seven wells historically as our spacing assumptions for Middle Bakken and Three Forks, because of the results we've seen in the Low Rider area on the Three Forks wells that we've drilled in particular, and in some of the results surrounding us particularly to the South. We are re-evaluating the number of Three Forks wells that can be drilled in per drilling spacing unit. And other operators in the Williston Basin have been talking about more Middle Bakken wells per DSU. I think until we finish this initial round of drilling; the increase in density will come from more Three Forks locations on our side. And I'd like to address that on the first quarter call after we drill a couple more Three Forks wells.

Ron Mills - Johnson Rice

Okay, great. Let me let someone else jump in. I'll get back in line.

Operator

Thank you. The next question is from Steve Berman of Canaccord Genuity. Please go ahead.

Steve Berman – Canaccord Genuity

Thank you. Good morning, guys. A couple of questions on Easy Rider, on McKenzie, at one point you weren't sure where that third rig would go first, how was it determined to go to Easy Rider, which is the timing of permit, there was something else. And also, do you anticipate completing the wells differently or the well differently as in Low Rider? Thank you.

McAndrew Rudisill

Hi, Steve. On the -- why we decided to go to Easy Rider first, it really was actually driven by a permitting timeline decision. We received the permits up there to move ahead and made the decision to go there first. We have the permits in hand on wells in the South and that's why it's moving down to the Emerald Pronghorn after we complete all those Easy Rider wells.

And on the frac design for Easy Rider, we actually think it's pretty similar to the Low Rider area, some of the well results directly offsetting the DSUs up in Easy Rider are more successfully fracked in a similar way to what we're doing in Low Rider. So, we are going to employ the same technique using the same (inaudible) hopefully achieving the same results in Easy Rider.

Steve Berman – Canaccord Genuity

Would you assume slightly lower cost up there, given it's a bit shallower?

McAndrew Rudisill

I'd say just a little bit. We are continuing to use that $10 million estimate in our internal modeling. And I believe -- I definitely rely on this. But we modeled a lower type curve on this well until we get them drilled and see what they look like.

Ryan Smith

Right. We model the 450,000 barrel EUR type curve on every focus area that we have other than Low Rider. And all you know obvious wells to drill from other operators in those areas show just a significantly higher curve.

Steve Berman – Canaccord Genuity

Great. Thanks, guys.

McAndrew Rudisill

Thanks, Steve.

Operator

Thank you. The next question is from Ryan Oatman of SunTrust. Please go ahead.

Ryan Oatman – SunTrust

Hi, good morning.

McAndrew Rudisill

Hey, Ryan.

Ryan Oatman – SunTrust

You said, production guidance needs to come up on the capital spending side. It sounds like there are two moving parts, but lower oil costs and shorter drill times can allow you maybe to drill more wells within a given timeframe. How do we think about potential movement in CapEx if and when production guidance is raised as well?

McAndrew Rudisill

Right now, we are keeping CapEx the same, and we are keeping our projected growth in that well count the same, obviously because of our drilling times coming down. There probably will be some change to that in the backend of this year. But I'd like to see the rate at which we drill in the second and the third quarters of this year when we have, in theory, better weather to deal with than what we have seen in the fourth and the first quarters. And then, we can make the more accurate estimation in the third or the fourth quarter as to what the back half of the year CapEx is going to look like. But as of right now, we feel very comfortable with the budget where it is and also our ability to finance that budget with our borrowing base and cash on hand.

Ryan Oatman – SunTrust

Okay, very good. And then, two quick modeling ones for me here, it did look like oil differentials were a little wide in 4Q, but you have also mentioned the dedicated pipeline. What's a good number for us to think about on the oil and the amount at the gas side in terms of differential dynamics?

McAndrew Rudisill

Ryan, the fourth quarter differentials were very wide. They widened out in November and December, and then they tightened up very quickly in January. I think for our modeling purposes, we are using $10 differential over the course of the entire year. And I think the variance on that $10 you can probably use $2 or $3. We've not been hedging our differential. We are just hedging our accrued markets.

Ryan Oatman – SunTrust

Okay. That is very helpful. And then, moving into the Three Forks development, can you just describe your comforts with that reservoir, based on what you have seen from these two wells, how easily drilled and fracked versus say that the Bakkens nearby? And then what you see in terms of your geoscience works across your acreage from the Three Forks interval relative to the Bakken?

McAndrew Rudisill

We drilled the upper Three Forks on the Excalibur 4 and the Caper 3. I think it's well understood across the basin that the Three Forks is -- all three of the Three Forks are thinner individually than the Middle Bakken. Hence, the slightly lower projected EURs than what you see on Middle Bakken wells. We are intentionally very careful in the way that we DSU these upper Three Forks well. But it's a pretty similar technique to what we have been using on all the Middle Bakken well. So, we stay to a very tight tolerance.

And then, the way that they fracked, we actually fracked them in a really similar way to the way we fracked the Middle Bakken wells. And second Three Forks well, the Caper 3 really do not have any technical problems at all, and you see the result is slightly better than the Excalibur 4, which is why we continue to encourage with what's going on in the Three Forks in this area.

Ryan Oatman – SunTrust

Very good. I'll hop back into queue. Thanks.

McAndrew Rudisill

Right.

Operator

Thank you. The next question is from Blaise Angelico of Howard Weil. Please go ahead.

Blaise Angelico - Howard Weil

Just real quick on acreage, you guys have pretty significantly grown the footprint over the past year. I am curious kind of what's the appetite for additional acreage adds? And how would you describe the market availability to add your (indiscernible) position and also pricing considerations?

McAndrew Rudisill

Blaise, we are actively adding to our acreage surrounding where we currently have positions and continue to surround the Low Rider area in Richland County and in our Emerald Pronghorn sand as well as Lewis & Clark along the trend that we have been following. But acreage prices have definitely moved up in the Low Rider area, pretty substantially over the course of the last couple of months. It is not easy to find open acreage positions, but we are actively looking for those acreage prices for the South that stays relatively the same. But as we started to see more results in Southern McKenzie County, we started to see some movement in acreage prices, and particularly you have got public data markers on REITS and M&A transactions that have occurred that you can point to as to what acreage is striding for in the area now.

So, we are definitely actively looking and working on acreage adds in the area, but I think it's going to be coming like we did all over the course of last year, we are focused on smaller blocks versus bigger chunks and just adding to the continuity of our position.

Blaise Angelico - Howard Weil

Got you. Thanks, guys.

Operator

The next question is from Curtis Trimble of Global Hunter. Please go ahead.

Curtis Trimble – Global Hunter

Yes. Good morning, everyone.

McAndrew Rudisill

Hi, Curt.

Curtis Trimble – Global Hunter

It looks like you have been -- spend a little bit of money on gas lift and ESP expansion. Can you talk about maybe a colorful response for those two efforts in relation to do simple rod lift and maybe expectations for production adds going forward or efficiency adds going forward?

McAndrew Rudisill

Curtis, we did spend a little bit of money on that in Q4 and we continue to spend money on that. Let me just talk to this point for a minute because I think it's an important one. So, this area that we are working in, in McKenzie County really just does not have very much infrastructure at all. The power grid really could not handle what we were doing. And each of our individual wells, we've got generators, we've got compressors. They each require individual tank batteries.

We are going to centralize all of this compression, all of this power use in the second and third quarter of this year. But as these wells performing and continue grow in production, we have to install all of these individual systems on all of these individual wells. So, we are effectively using diesel power to run a lot of these individual wells. And that added to our cost in Q4 and definitely added to the cost in the beginning of Q1 as well.

The most important thing for us to drive that cost down is to get all these little individual systems off these wells and get it to the central location once the weather is good enough for us to do that kind of construction and lay the necessary lines. The results have been very strong from putting the ESPs and gas lifts where we can on the wells, and we are going to continue doing that along the wells that will be drilled in the area. Hence, we are designing a system that can handle a distributed gas lift across the entire area.

Curtis Trimble – Global Hunter

Okay. And I if I remember correctly, at the Analyst Day you alluded to maybe some access to expanding electrical grid or something of that nature, maybe towards end of year; any idea maybe what the benefit of that would be in terms of per unit LOE or something of that nature vis-à-vis diesel consumption now?

McAndrew Rudisill

If you just think about it in terms of every barrel of oil that we are producing right now, we are burning diesel fuel to produce once we get that on to electricity, the cost is going to be drastically lower. What we need is a substation to be built in Low Rider, the local electrical utility is committed to do that, and the plan is to have that in by the end of this year.

So, that's definitely going to be a large contributor in addition to centralized compression facility, so that we don't have to constantly keep delaying with the compressor to each of the individual well side and can manage it from central location. Those two things are going to be a big driver pushing our LOE down this year.

Curtis Trimble – Global Hunter

Got you. If you can give me a quick update on saltwater disposal and (indiscernible) pipeline on that, and maybe timing for more pipeline volumes and their potential impact on LOE there?

McAndrew Rudisill

Yeah. The plan similar to the gas lift plan is to have saltwater infrastructure installed once the weather gets warmer, so that we can reduce the truck volume in the area. That in turn will help move the cost down. So, we've got a lot of pipeline systems to get put in over the course of second quarter, third quarter of this year. And that's at the top of our list of things to do.

Curtis Trimble – Global Hunter

I very much appreciate it.

Operator

The next question is from Paul Grigel of Macquarie. Please go ahead.

Paul Grigel – Macquarie

Good morning. Just following up on some of the infrastructure questions here, I assume most of that spending has been planned for in the 2014 CapEx plan, is that correct?

McAndrew Rudisill

Yes, it has.

Paul Grigel – Macquarie

Okay. And in regards to the fourth rig, you have mentioned taking up to the back half of the year. What point in time would that decision be made to go forward with that addition?

McAndrew Rudisill

Well, that's really a permitting-based decision. So, the NDIC is -- we have a lot of permanent spending right now and we are waiting for some of these permits to come through. There are also some federal lands that we are rating owned permits on. Once we receive those, then we will be able to know exactly when that fourth rig comes on. What we anticipate is mid to late third quarter type of event.

Paul Grigel – Macquarie

Great, thanks. And then, just following up a little bit more on more current weather conditions, for road conditions as we kind of get into the stops, still a little bit warmer up there. Have you seen anything over the last couple of weeks in terms of road restrictions?

McAndrew Rudisill

Nothing that's been affecting us specifically right now; I do anticipate as we get into the spring that could be an issue. There really has not been a lot of snow. It's just been extremely cold. So, you make it a little bit, we call it reduced [soil] (ph) conditions just because very little snow being on the ground. The main thing that impacted us in January and February was it was between negative 40 degrees and negative 20 degrees for 60 straight days, and everything just freezes under that. So, a little bit of snow could be a good thing for us.

Paul Grigel – Macquarie

Great, thank you.

Operator

The next question is from Ron Mills of Johnson Rice. Please go ahead.

Ron Mills – Johnson Rice

Just one follow-up, whether it's in the Bakken or the Three Forks, especially as you move to the Southern part of McKenzie around Low Rider, what do you think industry activity looks like, especially now that Liberty bought (indiscernible) offsetting you and other players moving into that area, any sense from your sharing information with companies that you're going to start to see development move southward through McKenzie County towards your acreage as well?

Ryan Smith

Well, Ron, I'll add a couple points to that. There are quite a few operators currently drilling wells in Southern McKenzie right now. They drilled some very good wells recently both in the Three Forks and the Middle Bakken, and we've been tracking it closely.

Directly to your question, regarding Liberty, I don't know what their plans are specifically, but I do know that they did a very good job in Central McKenzie County, around the area where Low Rider was in drilling wells and fracking in a pretty somewhat managed in the way that we're fracking our wells. And I'd anticipate they'll employ the same type of fracking to the South. We're looking forward to having them as a neighbor in the area. It should prove up more acreage.

Ron Mills – Johnson Rice

Okay. And then on the Three Forks Center, in Low Rider you're talking about 550,000 barrels, which is really been driving most of your guidance. If we look at the 18.2 net wells, how many do you think you may target the Three Forks with and what kind of type curve would you suggest on your Three Forks wells versus the 550 in the Low Rider area?

McAndrew Rudisill

Okay. I think our initial Three Forks well curves, we're thinking 500,000 barrel EUR type curve at the offset. So, I'd like to see a couple more wells before we start moving that number around. And then there was a second part of your question?

Ron Mills – Johnson Rice

Just of the 18.2 net wells you're going to drill, just curious, how many of those are going to be in Three Forks? You've already drilled two now?

McAndrew Rudisill

I think it's approximately 20% right now. And let's say, that's subject to shift higher.

Ron Mills – Johnson Rice

And then, you're still drilling one-off wells on these units for lease maintenance as opposed to -- had developments?

McAndrew Rudisill

Most of the wells that we are drilling are wells, the HBP units.

Ron Mills – Johnson Rice

Okay.

McAndrew Rudisill

I believe in the Caper unit, we are pad drilling to test density.

Ron Mills – Johnson Rice

Perfect. All right, thank you, guys.

Operator

The next question is from Steve Berman of Canaccord Genuity. Please go ahead.

Steve Berman – Canaccord Genuity

McAndrew, one follow-up, any update on timing in terms of the Excalibur Three Forks well in terms of going in and trying to retrieve that perforating gun?

McAndrew Rudisill

We're still waiting on the pressures to drop, to get the tool out, because 60% of it, for everyone on the call, their 60% of the stage is on that well we fracked, because we have to gun in the hole there. Hence, once the pressures are down, we can give the time to put a work over rig on that, we'll probably check it out in the late second quarter or early third quarter.

Steve Berman – Canaccord Genuity

All right, great. Thank you.

McAndrew Rudisill

Okay.

Operator

We have no further questions in queue at this time. I'd like to turn the call back over to management for any closing remarks.

McAndrew Rudisill

Thank you all for joining us on the call this morning. And thank you for your continued interest in Emerald Oil. We'll talk to you next quarter. Bye.

Ryan Smith

Thank you, bye.

Operator

Thank you. Ladies and gentlemen, this does conclude today's teleconference. You may disconnect your lines at this time. And thank you for your participation.

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Emerald Oil (EOX): Q4 EPS of -$0.17 misses by $0.15.