Emerald Oil's (EOX) CEO McAndrew Rudisill on Q1 2014 Results - Earnings Call Transcript

May. 6.14 | About: Emerald Oil, (EOX)

Emerald Oil Inc. (NYSEMKT:EOX)

Q1 2014 Earnings Conference Call

May 6, 2014 9:00 AM ET

Executives

Ryan Smith – VP, Capital Markets and Strategy

McAndrew Rudisill – CEO and President

Analysts

Ron Mills – Johnson Rice & Co

Steve Berman – Canaccord Genuity

Ryan Oatman – SunTrust Robinson Humphrey

Jason Wangler – Wunderlich Securities

Operator

Greetings, and welcome to the Emerald Oil First Quarter 2014 Financial and Operational Results Conference Call. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. (Operator Instructions) As a reminder, this conference is being recorded.

I would now like to turn the conference over to your host, Ryan Smith. Thank you, sir. Please go ahead.

Ryan Smith

Good morning. This is Ryan Smith, Vice President of the Capital Markets and Strategy. Welcome to Emerald Oil’s First Quarter 2014 Earnings Conference Call. Yesterday afternoon we issued a press release and also the Form 10-Q to report our financial and operational results for the quarter-ended March 31, 2014.

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 include, 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’ll 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 up the call for questions. We produced an average 2,511 BOE per day in the first quarter of 2014, which produced total oil and natural gas sales of $19.1 million and $9 million of adjusted EBITDA.

This is in line with our previously announced first quarter production guidance revision due to extremely cold weather in North Dakota. Our operations team did an exceptional job in March of Q1 to bring this amount of production online during the back half of the quarter.

Operating conditions during the second quarter have been good and allowed us to continue operating at a rapid pace in McKenzie and Williams Counties in North Dakota.

Because of better well performance in Low Rider, increased drilling efficiencies and the recent addition of a second frac spread, we increased our production guidance for the remainder of the year to an average of 3,700 BOE per day, and an exit of 4,900 BOE per day. Details for the quarterly guidance can be found on yesterday’s earnings release.

We increased both our type curve estimates for the Low Rider area to 600 MBOE and lowered our well costs assumptions to $9.5 million per well. We increased our downspacing assumptions to Low Rider to 12 wells per drilling spacing unit, eight Middle Bakken wells and four Three Forks wells. We also increased both the type curve estimates for Easy Rider to 550 MBOE and increased the downspacing assumptions to eight wells for drilling spacing unit, five Middle Bakken and Three Forks wells.

In conjunction with the increased drilling efficiencies, we increased our 2014 CapEx to $250 million for drilling and completion and $150 million for leasehold acquisition. The land budget is fully allocated to acquiring operated acreage that is contiguous to our core focus areas and increasing the working interest in existing units already operated by Emerald. To-date, we have spent $56 million in D&C and $88 million of the land budget.

In 2015, we are planning to spend approximately $350 million to $375 million on drilling and completion CapEx, which will result in the drilling of approximately 38 net wells. Due to the recent 2% [Technical Difficulty] we are funded to operate the four rig program into the first half of 2015. We expect the borrowing base to continue to grow with our production in reserves and plan on accessing this low cost borrowing base capital beginning in the fourth quarter of this year.

Accounting for closed acquisitions, we now have approximately 91,000 net acres in the Williston Basin, with approximately 68,000 net acres or 75% being operable. Our plan is simple; focus on drilling, production growth and cost control for the remainder of 2014.

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

Ryan Smith

Thanks, McAndrew. We ended the first quarter of 2014 with approximately $196 million in cash and nothing drawn on our revolving credit facility. We recently completed a semi-annual borrowing base redetermination of our revolving credit facility, which resulted in an increase to $100 million along with the syndication of the facility and the bringing in of two additional banks.

We believe that our cash on hand combined with cash flow from operations and availability into our credit facility, will adequately fund our drilling program for the remainder of 2014 and into 2015, which includes the addition of fourth drilling rig in the third quarter of this year.

We have increased our previously stated 2014 capital budget for well development of $182 million to $250 million, which will result in drilling and completion of approximately 25.5 net operated wells, at or below, our newly estimated cost of $9.5 million per well. Approximately $56 million of the well development budget has been spent year-to-date.

We are also increasing our 2014 land budget estimate, net of cash received in acreage trades of spending approximately $125 million increased to $150 million, approximately $88 million of the land budget has been spent year-to-date. Our entire capital budget continues to be focused exclusively on the Williston Basin.

Revenues for the first quarter-ended March 31 were $19.1 million. The first quarter 2014 revenue represented a 10% increase over fourth quarter of 2013. Production expenses for the quarter-ended March 31, 2014 were $2.6 million, resulting in a quarterly per unit basis of $11.59 per BOE, which represents a 33% decrease. The decreased expense is primarily due to the completion of replacing our diesel compression and generation equipment with natural gas powered equipment along with continued careful monitoring of weather-related effects on surface equipment, as we and other industry players continue to successfully develop and de-risk Central and Southern McKenzie County, we anticipate further cost efficiencies.

During the first quarter, our average sales price for crude oil was $86.15 per barrel and we are currently hedged at the maximum allowed under our newly admitted credit agreement. Approximately 3,400 barrels of oil per day at an average slot price of $96.13 per barrel. We plan to continue adding hedges once our scheduled October 2014 redetermination is completed.

At this time, I’d like to open the call for questions. I’ll turn the call over to our moderator.

Question-and-Answer Session

Operator

Thank you. (Operator Instructions) And our first question comes from the line of Ron Mills with Johnson Rice. Please proceed with your question.

Ron Mills – Johnson Rice & Co

Good morning guys.

McAndrew Rudisill

Hi, good morning.

Ron Mills – Johnson Rice & Co

Hi. The well performance at Low Rider has been outperforming, so that you are there. I’m glad to see. A couple of things. So, you talked about both there and at Easy Rider, what’s leading to the increased downspacing opportunities, and especially at Easy Rider, given that you’re recently starting up activity there, how did you arrive at the tighter spacing and the higher EUR for Easy Rider?

McAndrew Rudisill

Ron, there has been quite a few wells drilled in that part of Williams County over the course of the last couple of months, which we’ve been watching carefully. And based on those well results by our set operators, it gives us confidence that we can use that 550 MBOE type curves in the Easy Rider areas, as well as change our downspacing assumptions around that area.

Ron Mills – Johnson Rice & Co

And the EUR, they’re just going from 450 to 550?

McAndrew Rudisill

That’s right. Yes.

Ron Mills – Johnson Rice & Co

Okay. And the fourth rig, you talked about being on bought by late third quarter. Is there any more color in terms of when you expect it to get there and what the plans are? I guess I’m trying to look at the next year’s program with the 38 wells. What should think of in terms of timing of completions to try to start to triangulate a 2015 production number to go with that CapEx budget?

McAndrew Rudisill

Okay. On the fourth rig, I think to be conservative let’s think about it starting in the late third quarter, as we receive some permits earlier, then obviously we’ll start it whenever we get those permits, but the primary area where we want to focus that fourth rig is: number one, in Richland County, Montana; and then number two, South of Low Rider, just further development of the Low Rider acreages as you head south into McKenzie County to accelerate the HBP of those DSUs.

We would anticipate being able to drill one net well with that rig this year, but the timing of the completion would probably either be in late December of this year or in the early part of the first quarter of next year. And then we anticipate running the fourth rig over the entirety of next year.

Ron Mills – Johnson Rice & Co

Okay. All right, and then on the LOE front, I know, Ryan, you had talked earlier about I think plus or minus $11 number for the full year with improvements through of the year, given where you have started in the first quarter, I mean you look well on your way to achieve that. Is there further opportunities to improve on that LOE side?

Ryan Smith

Ron, there is. We just recently connected a couple of our drilling spacing units to electricity and took them off natural gas fire power. So that’s right there is going to be primary driver to push LOE further down is electrifying the balance of Low Rider as well as electrifying the southern part of Low Rider as we continue to expand. So it’s dropping the energy costs of the development and the continued production of the area, and we’ve completed most of the switch from diesel to natural gas. And the next phase of this is going to be moving from natural gas fired generation to just straight electrical power at each of the wells.

The other thing that’s going to impact us positively is once we get centralized gas compression built, which is scheduled – the construction is starting right now, and it should be built over the course of the summer, the equipment has been ordered. Once that’s in place and we’re able to centrally distribute the gas to re-circulate into all the wells, it’s going to further drop the LOE, rather than having a piece of compression equipment in each of the well sites.

Ron Mills – Johnson Rice & Co

Great. And then lastly, the second frac spread you added, I think it worked through the backlog due to some of the delayed completions from weather. What’s the plan with that second frac spread? Once you get through the backlog, do you plan on going back to one frac spread, or how should we think about that?

Ryan Smith

We’re going to intermittently move between one and two frac spreads from this point going forward. And it’s really just going to be dependent upon: number one, how many wells we have drilled into the backlog that we create with the drilling rigs; and then number two, is the availability of that second spread to be on call, we don’t want them sitting around a not frac. And so it’s really just a sequencing operation between when we drill the wells and how quickly we can use the second spread. As of right now, we’re continuing to use two.

Ron Mills – Johnson Rice & Co

Okay. Let me let someone else jump in. I’ll jump back in line. Thanks.

Operator

Thank you. And our next question comes from the line of Steve Berman with Canaccord Genuity. Please proceed with your question.

Steve Berman – Canaccord Genuity

Thanks. Good morning guys. Looking to next year, the 38 net wells. McAndrew at this point, can you give us an idea of, let’s say, pad drilling versus HBP drilling on those 38 wells? So maybe any thoughts or breakdown by area where that well will be drilled?

McAndrew Rudisill

Yes, Steve. I’ll break it down. The Low Rider area, we already are pad drilling now. So we pad drilled a couple of the DSUs already, and we’re setting up all the future DSUs for pad drilling operations. So at a minimum, we’ll drill four wells for drilling spacing unit when we move into a new unit. And then on some, we’re drilling six of seven wells right out of the gate.

So on two rigs, I’d run pad drilling. And then on rig three and rig four, you should run an HBP drilling scenario in your model.

Steve Berman – Canaccord Genuity

All right. And just based on the 91,000 acres by the end of next year, how much of that do you think will be HBP-ied?

McAndrew Rudisill

At the end of next year. We think it’s achievable and a 100% of that is going to be HBP.

Steve Berman – Canaccord Genuity

Okay. And then backing up to 2014, the new 25.5 operated well camp. Can you give us sort of a breakdown by quarter for the rest of this year? How do you see that going?

Ryan Smith

Hi Steve, it’s Ryan. Obviously it’s going to be more back-loaded with a third rig just starting. I don’t have an exact number in front of you now, but the net well count and the production ramp, you will start seeing that our first well from the third rig and Easy Rider will come on line likely, let’s just call it June. So you’ll start seeing that ramp combined starting in June just going forward with the remainder of the year.

Steve Berman – Canaccord Genuity

And where does the third rig go after that first Easy Rider well?

Ryan Smith

The first Easy Rider well that have already been drilled. We’re just waiting on completion there. And it’s going down to the Pronghorn to start drilling there.

Steve Berman – Canaccord Genuity

And when does the drilling start or has it started already?

Ryan Smith

It’s already – it’s being rigged up right now to start.

Steve Berman – Canaccord Genuity

Got it. Okay, thanks guys.

Ryan Smith

Thank you.

Operator

And our next question comes from the line of Ryan Oatman with SunTrust. Please go ahead with your question

Ryan Oatman – SunTrust Robinson Humphrey

Hi, good morning, McAndrew and Ryan.

McAndrew Rudisill

Hello.

Ryan Oatman – SunTrust Robinson Humphrey

One of your peers mentioned that the pipeline market was strengthening, and as such, it’s seeing price differentials relative to NYMEX improve subsequent to quarter-end. Can you comment qualitatively on what you’re seeing from a price differential standpoint and a broader marketing standpoint? And perhaps more specifically to what we should model in for discount to NYMEX moving forward?

McAndrew Rudisill

I am going to address the modeling question first, and then we’ll talk about the macro. So we’re continuing to use a $10 differential in our model for the course of this year. And the differential in the Bakken really – it’s shown a seasonality to it. It’s tended to tighten in the early part of the summer and then you’ve seen that widening effect as you head into the fall and then to the winter.

And that variance around that $10 number has continued to hold it about $5. So we think $10 is the right number used for modeling purposes for now. And we’re obviously always trying to improve on that, but we don’t have a whole lot of control on that, because it has to do with the total off-take for the entire basin.

On differentials as a whole, we are – our differential is directly related to what’s happening around the in-bridge facilities in Alexander because of the pipeline facility that we have which directly connects into that platform [ph]. So we have an option from there to put it on either rail or put it on pipe and we move barrels between those two. But our sense from a macro perspective is that there is more pipeline capacity being built and brought online in the basin. And you’ll start to see that in the back half of this year which should improve the pipeline differential market.

And there continues to be adequate rail capacity to move it out. So when it really comes down to is what’s – is how much crude is in storage at [indiscernible], how much crude is in storage in the Midwest and then what the crude markets on the East and the West Coast look like, and then the cost of transport for crude between both of those markets. And we make that decision on a monthly basis right now.

So you’ve seen a tightening recently in the differential market, and we think that will continue over the course of this summer, as you see more pipeline capacity get built in the basin, you should structurally just start to see the differentials come in a bit.

Ryan Oatman – SunTrust Robinson Humphrey

Okay, that’s helpful. And then I also wanted to kind of touch base on the spacing assumptions as well, moving to eight Bakken wells in Low Rider. Just wanted to see, kind of what gives you confidence that that’s the right development scheme moving forward and any sort of tests that you guys have around a point around downspacing in the next coming months?

McAndrew Rudisill

What gave us that confidence was we have actually fully downspaced two of our DSUs. Now we’re in the process of downspacing another three. So Caper has been downspaced with six wells, as well as the Excalibur units. And we’ve seen little to no communication on the wells, most of them are spaced at 700-foot spacing. Some of the most recent wells that we’ve drilled on both the Caper and the Excalibur locations have actually ended up being some of the best wells that we’ve ever drilled.

And that’s probably a result of both just the experience that we’ve generated from drilling all these wells in Low Rider, as well as making gradual modifications to our frac design. But I think what the most encouraging point is that we’ve noted from looking at all the data is that you’re seeing very little communication we think that the downspacing can definitely be increased, but on Middle Bakken density and on upper Three Forks density in those units.

So going forward, I mentioned it earlier, but as we move to the south, our plan is to drill three or four wells out of the gate back drilling as we move both with the rigs in Low Rider, and then we’ll increase the density of the drilling spacing units that are already producing in the Low Rider area with the two rigs that are running now.

Ryan Oatman – SunTrust Robinson Humphrey

Got you. And help me here with the 700-foot spacing, what does that correspond to within terms of wells per unit?

McAndrew Rudisill

That’s how we get to – we think that we can drill 12 per unit. So we’re set up two drilling pads per unit right now and then we can downspace further to eight Middle Bakken wells and then four upper Three Forks wells.

Ryan Oatman – SunTrust Robinson Humphrey

Okay. Very good. Thanks for the help. I’ll hop back in the queue.

Operator

Thank you. (Operator Instructions) Our next question comes from the line of Jason Wangler with Wunderlich Securities. Please proceed with your question.

Jason Wangler – Wunderlich Securities

Good morning guys. Just curious on the land budget. You spent about, call it half of it already in what the plans are for the remainder of the year, is it just built onto where you’re currently at or maybe even increasing the working interest or where do you see that playing out?

McAndrew Rudisill

Well, our number one goal is to increase working interest in units that we are currently drilling. So we’ve got an active leasing campaign in units where we’re going to be drilling and where we are drilling to acquire those working interests. So capital is focused on that. And then we’re focusing capital on acreage and adjacent units, next to units where we’ve created control, so that we can create more operable units around those, which will further leverage all the field infrastructure that we’ve already developed.

So we just continue to consolidate in and around the areas where we already developed, and that’s where all that capital is going into.

Jason Wangler – Wunderlich Securities

Sure. And then maybe just got to stick in with the land stuff, as far as the non-operated is obviously becoming less and less of a position. I mean is there a plan to continue to trade that acreage? Is there a monetization potential there, or just where you’re heads are out as far as the non-operations position?

McAndrew Rudisill

It’s a good question. I think what we’ve seen in general in the basin is the value of the non-operated properties has continued to rise, because of the increased density drilling that you’re starting to see across the entire basin. But since right now it’s in our best interest to hold onto this acreage and use it to either trade to consolidate working interest in operated units and we’re always open to monetizing pieces of it when and if we can if we like valuations, but at the same time there is a lot of good data that comes out of it, and as you mentioned it’s certainly each part of our portfolio.

So it’s got a pretty high value in our minds right now because a lot of that non-op is directly adjacent to where our operated wells are today and we’re using it to core-op into operated pieces.

Jason Wangler – Wunderlich Securities

That’s helpful. I appreciate it.

McAndrew Rudisill

Yes.

Operator

Thank you. And our next question comes from the line of Ron Mills with Johnson Rice. Please proceed with your question.

Ron Mills – Johnson Rice & Co

McAndrew, just on the first quarter production. It seems like despite the weather, your oil volumes going to be held in there relative to expectations. And then at least your original guidance and the impact to come in within your revised guidance was more on the gas side. Any more color there in terms of, is that still related to ONEOK and what’s the expectations for using that gas impact going forward?

McAndrew Rudisill

Ron, this is so cold up there that it was really hard for them to – for ONEOK to get any trenches dug to get any gas connected in that first quarter. So you’re spot on that our oil volumes were in line with what we were talking about. We just couldn’t get the gas sold because of just literally physically impossible for us to get it connected and we’re working on that right now, now that the weather is good. It’s a lot easier to get all those gas lines laid and get those wells connected. So I think that you’re going to see that improve over the course of this year.

Ron Mills – Johnson Rice & Co

Okay. And then I know you’ve been using slickwater. Are you planning on touching any other completion methods? More people are trying cement-liners. What’s your view on that as you move to your 2014 program?

McAndrew Rudisill

Slickwater is working really well, and I think you’re starting to see other people around us in the basin migrate towards slickwater fracs. So we’re going to stick with slickwater. We’re going to continue to modify how we deliver the profit and then we’re definitely evaluating whether or not we should be using cemented liners. I think the jury is still out. We need some more data to analyze that and to make the decision. It’s not a very big cost decision and it technically it’s not very difficult to do, but we’re getting good well results with what we’re doing already. And I’m reluctant to change what’s working until we see a lot more data on the cemented water, which I think will have here over the course of the next couple of months.

Ron Mills – Johnson Rice & Co

Okay, great. Thank you.

Operator

Thank you. This concludes our question-and-answer session. I would now like to turn the floor back over for any closing remarks.

McAndrew Rudisill

Thank you all for joining us on the call, and thank you for your continued interest in Emerald Oil.

Operator

This concludes today’s teleconference. You may disconnect your lines at this time, and thank you for your participation.

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Emerald Oil (EOX): Q1 EPS of $0.04 beats by $0.03. Revenue of $18.27M (+145.2% Y/Y) misses by $1.07M. Shares +0.15%.