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Emerald Oil Inc. (NYSEMKT:EOX)

Q3 2013 Earnings Call

November 6, 2013 10:00 AM ET

Executives

Ryan Smith – VP, Capital Markets and Strategy

McAndrew Rudisill – President and CEO

Analysts

Ronald Mills – Johnson Rice & Co. LLC

Steve Berman – Canaccord Genuity, Inc.

Ryan Oatman – SunTrust Robinson Humphrey

Jared Lewis – Northland Securities, Inc.

Jason Wangler – Wunderlich Securities

Curtis Trimble – Global Hunter Securities

Operator

Greetings and welcome to the Emerald Oil Inc. Third Quarter 2013 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.

It is now my pleasure to introduce your host Mr. Ryan Smith, Vice President Capital Markets and Strategy. Thank you, Mr. Smith. You may now begin.

Ryan Smith

Thanks you, Jiffy. Good morning. This is Ryan Smith, Vice President of Capital Markets and Strategy. Welcome to Emerald Oil’s third quarter 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 third quarter ended September 30, 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 and adjusted cash flow which are non-GAAP financial measures. 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. Good morning to everyone. We will begin with some general comments and then we will open the call for questions. We are on track to deliver our 12 completed net well guidance for 2013. The wells we drilled to-date are performing at or above our type curve expectations. The recent Excalibur 5-25-36H well is performing above our 550 MBOE EUR type curve guidance with an initial IP of 1,842 BOE per day which is the second strongest IP rate to-date in Emerald’s Low Rider area.

Both the recent Hot Rod wells are tracking with 550 MBOE EUR type curve despite the delay in lift installation due to gas line service connection. To circum navigate this issue in the future we have moved high-volume electric submersible pumps. The Excalibur well 4-25-36H is our first upper Three Forks well in our Low Rider project area. The well has fracked and is currently awaiting drill out and flow back.

We are anticipating good well cuts from the Three Forks in the area based on recent results from nearby Three Forks wells. Based on emerging positive Three Forks test we are very encouraged about the Three Forks in our newly acquired Williston Kodiak acreage to the South and East of Low Rider.

The Middle Bakken Shale is also present in most of our acreage. The Middle Bakken Shale is considered to be a source in reservoir and would add additional pay. In addition to the Bakken the Bakken Shale and the Three Forks formations in Low Rider we have conventional Red River formation production in our Southern acreage that has been producing a little decline for years.

With Red River is actively being targeted by other operators in the Williston Basin. The Red River is an emerging play below the Three Forks that we believe will benefit from horizontal drilling and modern completion techniques.

We are going to continue to permit in space to a seven well formation in each drilling spacing unit but I expect that the potential number of locations per unit may rise for Emerald in 2014 as we drill and complete more wells in McKenzie County, North Dakota.

Since the beginning of the year we’ve continued adding acreage to our Low Rider operating area in McKenzie County, North Dakota. This effort correlated with the September announcement of the long-term leasing campaign that added 34,000 net operated acres to our Williston leasehold position. These new leases not only continue the expansion of our core Low Rider area but added three new operated focus areas.

Easy Rider in the West Nesson Area; in Williams County, North Dakota; Emerald Pronghorn in Stark and Buildings Counties, North Dakota and Emerald Lewis & Clark in McKenzie County, North Dakota south of Low Rider. The leasing program added 138 additional operating drilling locations which provides Emerald with the total of 313 drilling locations in the Williston Basin.

In September of 2013 we sold substantially all of our non-operated properties or approximately 27,000 net non-operating acres for approximately 111 million in cash. We have used and intend to use the proceeds to fund the portion of our 2013 and 2014 capital budgets. Accounting for close and pending acquisitions and divestitures we now have approximately 66,000 net acres in the Williston Basin and approximately 60,000 net acres or 91% being operable.

During the third quarter we produced an average of 1,877 BOE per day which produced total oil and natural gas sales of 17.3 million and 10.1 million of adjusted EBITDA. During the fourth quarter of 2013 we expect average production to increase to approximately 2,300 BOE per day. We are comfortable with the current consensus forecast which averaged total near 2013 production of approximately 1,600 BOE per day that we are reaffirming our previous guidance at 2013 at 2,400 BOE per day.

We are also initiating 2014 quarterly production guidance to supplement our previously announced 2014 average annual production guidance of approximately 3,300 BOE per day. Over the course of 2014 we are forecasting to produce approximately 2,600 BOE per day in Q1 of 2014, 2,950 BOE per day in Q2 of 2014, 3,700 BOE per day in Q3 of 2014 and 3,900 BOE per day in 4Q of 2014. We plan on exiting 2014 producing approximately 4,000 BOE per day.

This is an expected 106% average production rate increase year-over-year and a 67% year-over-year increase in expected exit rate. This guidance includes two rigs running in the first quarter with the third rig starting in April of 2014. Three rigs will then run continuously for the balance of the year.

We contemplate adding a fourth rig in the later part of the year but this is not included in the guidance. Our focus on the remainder of 2013 and 2014 is to drill and complete more wells to grow production, optimized current well production through enhanced fluid systems, lower cost through more efficient drilling and completions and complete internal field infrastructure development to connect with our partners’ oil pipeline.

I will now turn the call over the Ryan to review our financial plans.

Ryan Smith

Thanks McAndrew. Pro-forma for the most recent public and private offerings plus cash on hand at quarter end we ended third quarter 2013 with approximately $200 million in cash and nothing drawn in our revolving credit facility. In August we completed the semi-annual borrowing base redetermination of our revolving credit facility and as a result, we entered into an amendment with Wells Fargo, which increased our borrowing base to $75 million.

We believe that our cash on hand combined with cash flow from operations, proceeds from our non-operated asset sales and availability under our credit facility will adequately refund our continuous two rigs drilling program for the remainder of 2013 and are currently planned three rig drilling program for 2014.

We’re maintaining our previously stated 2013 capital budget for well development of $127 million and are still forecasting to drill 12 net operated wells in 2013 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 $20 million in 2013 to acquire operated acreage in the core of the Williston Basin. Our 2014 capital budget for well development is approximately $182 million to drill complete 18 net operated wells of the total capital amount dedicated for 2014 approximately $122 million will go towards funding and continuous two rig program our Low Rider operating area while approximately $60 million will fund the addition of the third rig which will rotate between our Easy Rider area, Williams County, Williston County and our Pronghorn sand area and billing from Stark Counties.

We have set our 2014 land budget at approximately $25 million to continue to deploy our operated acreage continuous to our core focus areas. Our entire capital budget continues to be focused exclusively on the Williston Basin. During the third quarter our average sales price for crude oil was $97.50 per barrel which was a differential discount of about $8.34 per barrel relative to WTI over the same time period.

We are hedged with swaps with $92 to $94 per barrel and our credit facility with Wells Fargo allows us to hedge a portion of our existing production and we are new to maximum allowed. We plan to continue adding hedges as our production grows.

At this time, I would like to open the call for questions. And I will turn the call over to our moderator.

Question-and-Answer Session

Operator

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

Ronald Mills – Johnson Rice & Co. LLC

Good morning McAndrew, Ryan. The Hot Rod and Excalibur wells you have in the press release particularly the Hot Red wells you highlighted I guess lack of gas lift on those. Is that the cause of the lower 30 day rate and as you are now in selling the ESPs what do you think that’s going to do and just going forward how do you plan on handling the artificial lift in terms of type and timing?

McAndrew Rudisill

Well on the Hot Rod wells specifically they are connected for gas sales we don’t have gas buyback on these wells right now due to pressures in the area so we decided to install the multiple pumps. We believe these pumps are going to improve the production on those wells and going forward to avoid this issue which is really a gas buyback issue in the area we are going to install ESPs on some of our future wells where we can put in gas lift.

Ronald Mills – Johnson Rice & Co. LLC

And then in terms of it sounds like you are just now putting the wells on ESP. Do you expect once you put these wells on ESP those rigs will lift a little bit and then from a timing standpoint when do you expect them to install ESPs from day one?

McAndrew Rudisill

We’ve actually just been through ESP installation process on a couple of wells a kind of positive effect on the wells’ performance relative to get the gas lift. And the ESPs are going to pull on the wells harder. So the answer is yes it seems to improve the performance of the wells after ESPs are installed. I would highlight long-term as the gas pressures build in the areas we put more wells on stream the long-term plan is to have most of the wells on gas lift once the compression and gas is available.

Ronald Mills – Johnson Rice & Co. LLC

Okay, great. And then you highlighted different formations including your first Three Fork test but also the Bakken and Shelton and the Red River given your three rig program for next year is there any thoughts of testing those different zones next year or is that something that’s happening by industry participants I am just trying to figure out where that fits into your capital program?

McAndrew Rudisill

We don’t have any Red River or Bakken wells specifically budgeted our plan for next year in our drill schedule. What would I will say is our plan in the Low Rider area is relatively valuable. So after we’ve done more work and we’ll drill more Three Forks wells in the area and we have more data on Bakken Shale and Red River in the area. Having definitely on the forefront of our technical team’s mind about what to do about these formations both in Low Rider and to the South Low Rider.

Ronald Mills – Johnson Rice & Co. LLC

Okay. I’ll just jump in then right back in queue. Thanks.

McAndrew Rudisill

Thanks.

Operator

Thank you. The next question is coming from the line of Steve Berman with Canaccord Genuity. Please proceed with your question.

Steve Berman – Canaccord Genuity, Inc.

Good morning gentlemen. McAndrew, can you talk about the two Hot Rod wells and the Excalibur in terms of how they stacked up relative to your 10 million or below drilling complete cost?

McAndrew Rudisill

Yeah Steve we’ve been trending below the $10 million number on the last couple of wells we’ve drilled. It’s actually probably funding culture to the low 9 we still think it’s conservative to use the $10 million number across the entire field because we are still going to be moving a rig around over the course of 2014. But I do structurally think you’ll start to see our absolute low cost come down in the next couple of quarters if this is what we’ve seen on all the last couple of wells that we’ve drilled.

Steve Berman – Canaccord Genuity, Inc.

And what about the Excalibur Three Forks well in terms of expected cost a little bit deeper is that changing expectations there and when do you think that full completion will be done?

McAndrew Rudisill

Well it’s ready to be contracted just need drill (Inaudible) so we should have that data in the first quarter of 2014 on the fourth quarter call and the cost on that well is actually come in inline to other Middle Bakken wells so we’re in the low nine.

Steve Berman – Canaccord Genuity, Inc.

Excellent, that’s it from me for now, thanks.

McAndrew Rudisill

All right, thank you.

Operator

Thank you. The next question is coming from the line of Ryan Oatman with SunTrust. Please proceed with your question.

Ryan Oatman – SunTrust Robinson Humphrey

Hi, good morning.

McAndrew Rudisill

Hey, Ryan.

Ryan Oatman – SunTrust Robinson Humphrey

I just wanted to talk a little bit about the type curve, the 550 in BOE type curve, can you remind us what the averages are for that the 30, 60 and 90 day rates that you guys are assuming for that curve and if you have that handy?

McAndrew Rudisill

Yeah, I don’t think we have that right in front of us that is something that Ryan can get back to you on after the call.

Ryan Oatman – SunTrust Robinson Humphrey

Sure, my point being as I look at these wells it may look quite strong in terms of your 30, 60 and 90 day rates, at what point do you think you probably have enough in terms of these first operated wells here to take a look at that 550 curve and or the 2014 guidance?

McAndrew Rudisill

Okay. Let me sort of back to your first question and then I will answer your second one. If you take a look at page six on the presentation on our website, it’s a good delineation of the curve well results in they are averaged 30, 60 and 90 day rates. I’d highlight that most of the wells on that page are greater than the 550 curve to signal into your second question.

One of the reasons why we continue to see the 550 curve in the Low Rider area is because all of the DSUs in the area are not yet drilled and we want to make sure that as we drill out these DSUs all of the results are similar and then secondarily we think you just need a lot more data points i.e. more days online of production in order to take the type curve forecast up for the Low Rider area.

It’s just prudent for us to wait and we think that number is 120 to 150 days on these wells to start thinking about that. I’d also keep in mind that because we are now drilling in Richland and Easy Rider and the Pronghorn sand formations we viewed a lower type curve in each of those areas to forecast our production guidance for next year and that’s the function of new areas for Emerald although multiple operators are drilling in that long producing wells in each of those areas. We are conservative about how we forecasted that type curve as well.

So, I think next year after we have more data in the Low Rider area that’s when we can start changing type curve expectations a bit.

Ryan Oatman – SunTrust Robinson Humphrey

Okay, that makes sense. And when we’ve seen industry talk about new completion designs whether it’s a (Inaudible) and multiple proof cluster for stage, are you guys in contact with that industry peer that’s looking at that and is there anything that you are looking at doing differently from a well completion design standpoint in lieu of these results?

McAndrew Rudisill

Ryan, actually Emerald has been a technology leader in this particular area in McKenzie County and how we call about completing our well and the results that we’ve generated. So, we definitely are using multiple curves per stage right now. We are delivering very high profit and concentrations to each of the individual stages using our slickwater frac design.

We are not using cemented line right now because the results that we are giving are very good and better in some cases to well do have cemented liners. We are actively evaluating and watching the wells of cemented liners around it one of the things that we just have to focus on is very high IP rates are interesting but we are focused on that 30, 60, 90 day rate and what that curve looks like over a longer period of time.

So I think we need to get a little more data before we draw a definitive conclusion that cemented liner is the answer. There is a different recipe in each different area of the Basin that optimizes well performance.

Ryan Oatman – SunTrust Robinson Humphrey

Got you, but you are definitely using multiple per stage that’s interesting. I will get back in the queue, appreciate it.

Operator

Thank you. The next question is coming from the line of Jared Lewis with Northland Securities. Please proceed with your question.

Jared Lewis – Northland Securities, Inc.

Good morning guys.

McAndrew Rudisill

Hi, Jared.

Jared Lewis – Northland Securities, Inc.

Just kind of a following up right on what Ryan was asking, as you move into your other areas in the acreage with this third rig, what do you see or how do you see the frac designs, are you going to use the same thing using a Low Rider or are you going to adjust that or what’s your thought there?

McAndrew Rudisill

So Easy Rider geologically is very similar to the Low Rider area just left to (Inaudible) there is good fraction in there we’re planning using a similar well design and frac style on Easy Rider area and Richman County it’s a bit shallower than where we’re going McKenzie County we’ll probably modify the profit mixture that we’re using in Richman County but we’ll continue with this similar type of well design with the same focus on GS hearing.

And then in the Pronghorn sand formation it’s obviously a different formation than the Bakken and the Three Fork and we’re going to complete it in similar way to have the other operators in the area to do it. They’ll continue to be between 1,000 feet lateral just to practice on to change a bit.

Jared Lewis – Northland Securities, Inc.

Excellent, and just on the acreage, what are just kind of seeing out there in the market right now as far as packages and cost and what idea?

McAndrew Rudisill

There is not whole out there it is what we’re seeing the price for acres in the Williston Basin as continue to trend up and we don’t see that changing in fact we probably see it accelerating in the future to the upside.

Jared Lewis – Northland Securities, Inc.

Okay, great I’ll jump back in. Thanks.

McAndrew Rudisill

Thanks.

Operator

Thank you. Our next question is coming from the of Jason Wangler with Wunderlich Securities. Please proceed with your question.

Jason Wangler – Wunderlich Securities

Good morning guys. Just curious as we get in the ‘14 with the two rig program what your thoughts are as far as may be delineating the Low Rider more moving Southeast, West what are the plans as far as is that next year?

McAndrew Rudisill

Yeah, Jason our general plan is to put one well in each of the drilling spacing unit so that we hold it. We’re currently executing to that plan and we’re marching South with the two rig Low Rider program and then the third rig will execute on the same exact program in Easy Rider originally drilling one well per DSU. So in the later part of the next year there may be some infield in the Low Rider Area to test Three Forks but beyond that we’re focused on – the acres that we operate.

Jason Wangler – Wunderlich Securities

Okay. So the will kind of you are continuing your push out I guess by section as we move throughout the year?

McAndrew Rudisill

That’s right.

Jason Wangler – Wunderlich Securities

Okay, perfect. Thank you.

Operator

Thank you. The next question is coming from the line of Curtis Trimble with Global Hunter Securities. Please proceed with your question.

Curtis Trimble – Global Hunter Securities

Thank you. Good morning everyone. Looking at the areas where you put the third rig to work just trying to get a little bit more of an idea of how you risking put up the potential there vis-à-vis the Low Rider Area?

Ryan Smith

Hey, Curtis this is Ryan. McAndrew mentioned earlier just starting in our Low Rider area, we forecast internally into the state of 550,000 barrel EUR in that area and then risk it appropriately in our Easy Rider Area and Williams County our Richland County acreage in our Pronghorn acreage. We’re putting a 450,000 EUR type curve on those areas.

If you refer our presentation we have significant surrounding well control with bristles that probably lead to higher than the 450 type curve but as McAndrew spoke earlier we haven’t done in there and drill our own wells so until we do that and get a data set we feel that’s kind of the responsible to serve that number to use going forward.

Curtis Trimble – Global Hunter Securities

Do you (view) on the cost side conservative that you can see what you’re probably see as far and we can see it’s using comes in lower will be the right way to treat that?

McAndrew Rudisill

Yeah Curtis, this is McAndrew, in Richland I think the well cost will be lower and Easy Rider I think that will be similar to Low Rider because they’re very similar wells and in the prong on slightly lower than Low Rider and probably higher than Richland.

Curtis Trimble – Global Hunter Securities

In terms of the progression of one will see information from these wells again just starting in North walk way South so maybe on a quarterly basis we’ll see one new well from each of the additional areas?

McAndrew Rudisill

Well not until the third rig starts in April. So we won’t start seeing results until the middle of the summer on that third rig addition. But you’ll start seeing acres seeing results on capital Low Rider in the second quarter of next year.

Curtis Trimble – Global Hunter Securities

Perfect, appreciate it.

McAndrew Rudisill

Thanks.

Operator

Thank you. Our next question is a follow up question coming from the line of Ron Mills of Johnson Rice. Please proceed with your question.

Ronald Mills – Johnson Rice & Co. LLC

You mentioned on the spacing earlier as seven wells per DSU is that plan still allowing for four Bakken and three, Three Forks if I remember that correctly?

McAndrew Rudisill

That’s right but we feel the pad location so that we can down space further if required and then we’ll have to revolve permits to that. As you’ve seen from multiple other operators in the area people down spacing to much a higher degree than seven wells for drilling spacing unit right now and we’re actively evaluating that.

Our focus right now is just to make sure everything get the information out of that and then we set up to down space in the future.

Ronald Mills – Johnson Rice & Co. LLC

And how does that also really in not just in terms of down spacing but also as industry continues to test multiple ventures of the Three Forks given the location of your acreage how do you think your position is as industry is placing the multiple ventures or what are thoughts on that?

McAndrew Rudisill

We know that we have multiple ventures of Three Forks in our acreage as I mentioned the Red River formation below the Three Forks as well as the Bakken Shale so these are all (Inaudible) benches from McKenzie County. My sense is that you are going to continuing to see down spacing increase in this particular area of McKenzie County and then it should become a question of density per DSU as to how many wells as you can put in each of the zones the Three Forks, Middle Bakken and Bakken Shale and Red River.

Ronald Mills – Johnson Rice & Co. LLC

Okay. When?

McAndrew Rudisill

I think we will be a pioneer with this over the course of 2014 we just indicate everything as we did.

Ronald Mills – Johnson Rice & Co. LLC

Pardon my ignorance that when you talk about the Bakken Shale where is that located in the straight column and what kind of information is out there on well control or data?

McAndrew Rudisill

Yeah it’s below Middle Bakken above the upper Three Forks. And it’s been referred to by other operators in the areas hidden bench.

Ronald Mills – Johnson Rice & Co. LLC

Okay.

McAndrew Rudisill

In that Central McKenzie area.

Ronald Mills – Johnson Rice & Co. LLC

And is that fairly localized?

McAndrew Rudisill

It is and it changes in depth in the area in and varies a bit more than Middle Bakken but we’ve seen in both the Northern part and Southern part of our acreage.

Ronald Mills – Johnson Rice & Co. LLC

All right, great. Thank you.

McAndrew Rudisill

Thank you.

Operator

Thank you. It appears there are no further questions at this time. I would now like to turn the floor back over to Mr. Smith for any concluding comments.

Ryan Smith

Thanks, Jiffy. Thank you all for joining us on the call this morning and thank you for your continuing interest in Emerald Oil. Have a good day.

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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