Northern Oil and Gas Inc (NOG) 2010 Q2 法說會逐字稿

Good day, ladies and gentlemen and welcome to the Northern Oil and Gas second quarter earnings release conference call.

(Operator Instructions).

I would now like to introduce your host for today's call, Mr. Michael Reger, CEO, and Mr. Ryan Gilbertson, President of Northern Oil and Gas. Gentlemen, you may begin.

Good morning, ladies and gentlemen. My name is Michael Reger. I'm the Chairman, and Chief Executive Officer of Northern Oil and Gas. Ryan Gilbertson, our President is also here on the call with me today. We're excited to welcome you to the first earnings call in our Company's history for second quarter 2010 earnings call for Northern Oil. Before we begin this morning's call, you should be aware that certain statements made during this call may contain forward-looking statements that are based on upon management's expectations, estimates, projections and assumptions that involve certain risk and uncertainties.

We encourage to you review the various risk factors relating to our business which are available in our annual report on Form 10-K for the fiscal year ended December 31, 2009, and other reports we have filed with the SEC. These forward-looking statements relate to our future plans, objectives, expectations, and intentions. Our actual results could differ materially from those contemplated by these statements, partially as a result of these various assumptions relied on, in making such statements.

For those of you joining us to learn about Northern Oil and Gas for the first time, I would like to take a moment to explain our operational strategy in the Bakken and Three Forks play. As a non-operator, we participate in wells on a heads-up basis in proposition to our leasehold interests and drilling unit. Any time a well is permitted, all parties controlling leasehold interests within the drilling unit, are automatically permitted in the well. As such, Northern Oil and Gas' leasehold interests are included in any well drilled within the drilling units containing our leasehold interests.

As an example, if we control 160 acres in a 640 acre drilling unit, we would own 25% of any well drilled in that unit, and participate heads-up with a 25% working interest. When a well is drilled in the unit, we then pay our 25% share of all expenses, and receive 25% of all crude oil and natural gas sold from any well. We do not farm out our interest, or dilute our working interest in any way. We participate per our proportionate interest, without the infrastructure and overhead costs of the larger operators. We believe capital is most efficiently deployed through this strategy, due to the substantial discount for which non-operating leasehold interests can be obtained. With that background in mind, I would now like to now turn the call over to Northern Oil's President, Ryan Gilbertson, to review our financial results for the quarter.

Thanks, Mike. Again, this is Ryan Gilbertson, the President of Northern Oil and Gas. Today we reported our financial results for the quarter ended June 30. During the quarter, we had net income of approximately $6.1 million or $0.12 per share on total revenues of approximately $16.3 million. Second quarter production volumes increased 38% from the first quarter of 2010, exceeding our previous guidance of 20% to 30% for quarter-over-quarter production increases. Revenues from the sale of crude oil and natural gas, including hedge settlements, were approximately $12 million for the second quarter, which represents a 46% increase compared to the first quarter of 2010, and 426% increase compared to the second quarter of 2009.

Total revenue, including the mark-to-market value of our hedge instruments for the second quarter was $16.2 million, which represents a 125% increased compared to the first quarter of 2010, and a 613% increase compared to the second quarter of 2009. Our average realized price for crude oil was just under $71.00 per barrel during the quarter, which included a $1.83 per barrel gain, due to the settlement of crude oil derivative contracts, which compares to an average of $68.70 per barrel in the first quarter of 2010, which included approximately $1.50 per barrel loss due to the settlement of crude oil derivative contracts, an average of $52.36 per barrel realized price in the second quarter of 2009, including a $2.85 per barrel loss due to the settlement of crude oil derivative contracts.

Our production volumes for the quarter were a record 172,663 barrels of oil equivalent. This production represents a 38% increase compared to the first quarter of 2010, and the 235% production increase compared to the second quarter of 2009. This increase represented our tenth consecutive quarterly increase in production. Second quarter production consisted of 96% crude oil and approximately 4% associated natural gas. We exited the quarter with production volumes of approximately 2,700 barrels per day. During the quarter production was added from just under four net wells, and we've maintained a 100% drilling success rate in the Williston Basin, Bakken, and Three Forks trend since the Company's inception.

Our reported production expenses for the quarter were $561,000, which is approximately $3.30 per barrel, compared to $3.15 per barrel for the first quarter of 2010, and $2.41 per barrel in the second quarter of 2009. Completion expense was $2.6 million, approximately $15.00 per barrel, identical on a per barrel basis to the first quarter of 2010, and compared to $10.54 per barrel in the second quarter of 2009. Cash G&A expenses for the quarter were $718,000, representing a 20% decrease compared to the first quarter of 2010. Our reported net income from the quarter was approximately $6.1 million or $0.12 per fully diluted share, compared to net income of approximately $0.04 per share in the first quarter of 2010, and net income of approximately $0.01 per share for the second quarter of 2009.

Our net income for the quarter, excluding unrealized market-to-market hedging gains of approximately $3.5 million or $0.07 per diluted share, compared to the net income in the first quarter, excluding unrealized market-to-market hedging losses of $0.05 per share. Adjusted EBITDA, as defined for the quarter, was approximately $9.7 million or $0.19 per diluted share, which represents a 51% increase over adjusted EBITDA of $0.14 per share for the first quarter of 2010.

To update everyone on drilling, we're currently participating in the drilling or completing of an additional 63 Bakken and Three Fork wells, and one Red River well for aggregate of 7.25 net wells currently drilling or on the way to completion. As of today, August 9th, we've spud approximately 13.85 net wells in 2010, and we reaffirm our previously announced guidance to spud approximately 18 net wells through 2010. And we do expect to increase third quarter production volumes 30% to 35% over second quarter 2010, which is an increase of our previous guidance of 20% to 30% on the quarter-over-quarter gain. And we do continue to increase our hedging activities during quarter, as crude oil prices have increased. As of July 31, we have entered into crude oil swap contracts through 2010, production volumes of approximately 315,000 for the remainder of 2010, representing approximately 70% of our 2000 production -- our 2010 production hedged at a level of $80.36, 372,000 barrels for calendar year 2011 at approximately the same price, and 141,000 barrels for 2012. And I will pass the call back over to Mike Reger to conclude our comments, before we move to the question and answer section.

Our strong production growth has been a result of continued improvement in well results, increased core acreage addition, robust drilling activities, and growing efficiencies in this premiere oil resource play. We continue to be impressed by the expanding size and scope of the Bakken Three Fork trend, as well as the evolution in completion techniques. We would like to thank all the operators with whom we have been fortunate to work with, for all of their efforts in advancing the collective success of all participants in this exciting and high-return oil play. We remain well-capitalized and positioned to execute on our strategy of acquiring high quality non-operative interests and developing our substantial core Bakken position. Northern Oil would like to reaffirm it's focus on the Williston Basin, Bakken, Three Forks play, as we continue to exploit our leasing advantage, and turn our high quality acreage to production. This is concludes the overview of our quarterly financial results, and we'll now entertain questions from our covering analysts. Thank you very much.

Our first question or comment comes from Wunderlich -- our first question or comment comes from Wunderlich, Mr. Neal Dingmann. Your line is open.

Good morning, guys, solid quarter, and good color. Say, first question, you continue to add, obviously a very sizeable amount of acreage each quarter it seems like, wonder if is that due to top-leasing or as you go forward, how do you see adding some of this acreage?

Thank you, Neal, and thanks for joining.. The way we have always looked at leasing is we allocate the dollars to where we feel the most efficiencies are. To this point, it hasn't necessarily been in significant amounts of top-leasing, but rather in smaller, organic acquisitions of both leasehold and AFE interest in well. It's where we deployed most our capital thus far this year, and it's where we continue to see the opportunities. If you look at some recent market transactions, they have come at a significant multiple to what our average basis is for the year. And we believe the acres we're acquiring, are of the highest quality and short fuses on the drilling, with an average cost -- acquisition cost of around $1,000 an acre. It probably most clearly defines the edge in the non-operator strategy. Where that edge is going to exist going forward, it's tough to say. We're not adverse to larger acquisitions, but we'll continue to monitor exactly where we think that edge is, and deploy the dollars there.

Okay. And next question I had as far as you mentioned an example, Mike about sort of the interest that you all have in these wells around 25%. I noticed on one well you were up to almost a 46% interest. Is there an ideal percentage, working interest you would like to have in a well, or does that just vary sort of well-by-well? Play-by-play?

No, there really isn't an ideal working interest. We participate directly proportionate to the number of acres we have in each section. So whether we have one acre or 320 acres, we would participate for whatever interest we receive in that unit. Across the wells that we're drilling right now, there is approximately 63 wells that we're participating in. And our average working interest is just over 10% and that ranges from anywhere from -- just a few percent up to about to 45% to 50%.

Okay, and two more if I could. Next on CapEx, just wondering what that around for the quarter? Kind of how the maintenance CapEx plays out, and then how you see, I guess, what kind of control you have in CapEx, or if you kind of have looked at that going forward?

Yes, this is Ryan, again. The CapEx for the first half of the year was about $54 million, about equally divided between drilling and acreage. Our CapEx drilling for the year is approximately $85 million to $90 million. We have a little bit of variance in there, depending on when certain wells are going to spud. Our average CapEx per well has still been under $5 million. We're able to accomplish that due to our high concentration of acreage in the east Nesson part of the play. The fact that we're drilling a number of wells with Slawson Exploration and EOG, they've typically had lower well costs primarily due to the shorter laterals. CapEx for the balance -- the second half of the year is about an equal number, approximately $55 million to $60 million. And again, that is going to be subject to some variance, depending on the opportunities that we see out there, from the acreage acquisition side.

Okay. And then last question, well you continue to mentioned with Slawson to partner, just to concentrate in the Bakken, or will you kind of have worked your ways towards the Montana area as well?

Well, our belief is that the distinction in prices for non-operated interest is very slow to go away, especially after a new area has been delineated within to the productive zone. We're not really interested in really being pioneers. We're not really interested necessarily in striking out with a -- into a new tact, into area that may or may not be proven. Everything that we see out in Montana continues to look very exciting. Our position is very small out there. Of our approximately 100 -- of approximately 116,000 acres of four delineated Bakken, only about 5,000 of that is into the Montana side. So we really haven't struck out there firmly yet, but as the play continues to move in that direction, Northern Oil is going to be there. And we just don't believe that the discount for acreage prices at this stage of the play, merits a large capital allocation into Montana. And if it does, we'll be there.

Great color. Thanks, guys. I'll get back into queue.

Our next question or comment from Canaccord Adam, Mr. Derrick Whitfield. Your line is open.

Good morning, guys, and congrats on a solid quarter. We continue to hear other operators talk about service tightness in the basin. Could you guys broadly comment on what you are experiencing with your larger operators, and what is your expectations are for the second half?

Sure. This is Ryan. Derrick, the service question is a common one out there. We certainly are seeing some tightness on the completion side, and we have grown to expect a new normal of 90 days, spud to sales. That number could grow, and it's possible in some cases, that it's higher. Whether it pushes through 100 days, it's hard to say. We are confident that, in general, the new completion assets being deployed to the Bakken should loosen that with time. But for the foreseeable future, the next quarter or two, 90 days is probably going to be the spud to sales, that we'll live with for the balance of the year.

Got it. Then of your 7.2 net wells drilling or awaiting completion, how many of those are awaiting completion?

Approximately two of those have been drilled to total depth, and are awaiting completion, and the balance are turning as we speak.

Got it. Then maybe touching on your strategy lease acquisition strategy, could you add some more colors to how much more additional opportunity you see in the market using your organic leasing approach?

Absolutely. Derrick, what is continuing to surprise us is the availability of non-operative interests. There are areas that other operators have commented on are very tight. The leasing game is coming to an end, but for the non-operated pieces we target, we still see a robust amount of activity. We think there are many, many more quarters of acreage growth available to us, given the nature of the interests we target. And we think that the value we're able to create by buying these less sought after interests continue to grow. So we still think there is a plethora of opportunity out there in the Williston Basin Bakken play. We look forward to continuing to exploit, what we believe is our leasing advantage on the ground.

Great. And then a final question, and I will hop back in queue. Could you guys offer some color on what you are seeing with AFE's by area and comment on the spread, if any between actuals and the AFEs?

Yes, Derrick, this is Ryan again. In southern Mountrail County, the core of our Windsor development program in and around the lake there, where we participate primarily with EOG and Slawson, we're seeing AFE costs $4.2 million to $5.2 million. We're generally seeing those well costs come in as low as $3.5 million, as high as $4.9 to $5 million. So we're coming in consistently, a reasonable amount under AFE. As we move out of the west Nesson part of the play, and into Williams and McKenzie, we see those costs creep up primarily due to the longer length in laterals.

And the range in AFE's that we see out there is approximately 5.2 to 7.5, and most of those are coming in on the high side with AFE range. So there is a distinct difference in drill and complete costs, and therefore S&D costs based on where you are in the play. We're fortunate enough to have over two-thirds of our position, east of the Nesson Anticline, in what we think is some of the best -- some of the best rocks out there. So we continue to see efficiencies on both fronts. We continue to see AFE costs come down, and operators continue to become more efficient. As we said in your press release, we're very thankful to be working with many of the greatest operators we work wit,h and we continue to see these well results get better and costs come down.

Thanks for the color, guys.

Our next question or comment from Howard Weil, is Mr. Peter Kissel. Your line is open, sir.

(Inaudible) for the call today. Quick question, just based on where the wells and basin rig count has gone, I believe we are currently around 134 rigs. Where do you that that 18 net wells for 2010 could head towards? It seems a little low at there point. Is that more you guys being conservative, or kind of what are your thoughts for the remainder of the year?

Thank, Pete. This is Ryan again. As we look out the next couple of months, there is always going to be variance inactivity. Certainly the rig count is substantial. The question that we have in forecasting that 18 net wells, is where do those assets get deployed to. We continue to see the east Nesson part of the play be developed, and those rigs move to the west. Could that number grow? Yes. Is from a greater possibility of it increasing versus decreasing? Yes. But 18 is the number that we have got good visibility on. A non-operator we like to stick with the runway and time frame that we -- in which we have got a good visibility and we still feel that will 18 is a good number for 2010 well spuds.

At this point for 2011, is it just too early to call?

It is too early for us, given the size and scope of this play, and where it continues to expand. It's very hard for us to make a definitive call on 2011. The play continues to get bigger, continues to impress us. We continue to see more assets deployed to the play. The one thing we can tell you, is that 2011 will contain a higher amount of drilling activity than 2010, and that higher amount should be materially higher.

Okay, thanks. Just one reminder, I guess, do you have any near term leasehold expiration issues? Or is that pretty well held up for a significant amount of time?

This is Ryan between. The lease expiration question for us is another advantage we think of the non-operator model is, we're able to target very selected leases that have term, come with drilling schedules, that were very rarely subject to lease expirations that catch us by surprise. Our average lease expiration right now is early 2013, and we don't face any material expirations until the third quarter of 2012 in our core position. One thing that we do focus on very tightly is leasing acres that come with the drilling program in the delineated core. Our Williston Basin Bakken position is materially larger that the 115,700 acres that we represent. That 115,700 acres is what we believe has been delineated, and will be developed within the timeframe of the leases. So that is a solid number you can work off of, and that is what we're targeting over the next few years.

Okay, great. That is very helpful and one last question and I will jump back into queue. When you look to juggle your cash availability and borrowing base, combined with the drilling and leasehold CapEx, looking into 2011 and beyond, what is your optimal hedge level? And kind of what are you targeting to be, come, say December of this year going into 2011?

Yes, thank you.The optimal hedge level for us going out about a year is 50%. Going out about two years, approximately 25%. Those numbers may be able to decrease in the future. Right now, we believe in taking a fairly aggressive tact on hedging, given our capital needs over the years. For the balance of this year, we're about 70% hedged in our remaining production. So it makes a lot of sense for us from our productive, given that 2011 will be such an impactful year. We're not trying to necessarily call the price of oil here, we're making sure that we're protecting our cash flows to the extent, that we're not forced to do anything in the capital markets that we don't want to. We have always been very well-capitalized, and we intend to stay that way. As you know, we ended quarter with $70 million in cash and an undrawn credit facility, where we believe we have got significant excess capital to continue to, not only expand your position, but to meet our drilling obligations with a leverage ratio appropriate for a non-operator.

Our next question or comment from C.K Cooper, Joel Musante. Your line is open.

Hi, Mike, hi, Ryan.

Hi Joel, thanks for joining.

I just had a few questions, a couple of them have already been answered. But who are your most active operators on your leases right now? Has that changed at all, or is it still EOG and Slawson?

Right now it hasn't changed this, again, this is Ryan. Approximately 50% of our activity is going to be contained within a few names, which would be EOG, Slawson, [Pass], and Continental. That is where we're focused right now. As we continue to see more of that activity move to the west, that focus may shift, and we'll pick up some additional operators that are more active in the west Nesson side of the play, such as Oasis and Brigham. So we continue to see a nice dispersion amongst operators. We get a look at completions in different areas, and we continue to be impressed by the ingenuity and evolution of the operator's different techniques.

Okay, with respect of AFEs, have you guys opted to participate in all of them, or some that were too costly, and you decided to opt out?

We have, Joel. We have elected to participate in every well that we were presented with. And the reason for that is that we really make the decision when we lease the acres. And what is critical in differentiating Northern from the other operator players, is that we're not forced to go out and pick up a larger contiguous block. We're able to come in, and we're buying acres at a substantial discount that have been substantially derisked. So we literally make the election to participate when we buy an acre. We generally know who will drill it, and when it will be drilled. So I wouldn't be surprised that in the future, we not elect to any wells.

And just in your last operational update, you talked about the Big Sky prospect. Can you just cover that ,and just add a little color on that from what you put in your press release? And just update us on if there are any new developments there?

Sure. Well the Big Sky prospect, and for those who you who aren't familiar with it, it's our small block of acreage on the southwest side of the old Elm Coulee field in Richland County, Montana. It's a small position for Northern. It's a few thousand acres in a joint venture and a AMI with Slawson. We're planning our second well out there, the Scoundrel well, which we'll spud in the third quarter or early fourth quarter. And it's a great example of the continuing evolution of the play.

One thing that we mentioned out there, that it's a different structure, Slawson drilled into the upper shale, or just the shale at that point. The Middle Bakken has pinched out at that particular piece of the Elm Coulee field, and the geologic hypothesis is that, the drilling into the upper remaining upper shale could produce a well that could be drilled very economically, cheaply and produce at a good rate, and that is exactly what we got with the Vandal. So it's a great example of the ingenuity of an operator pushing the play, and it really shows how the Bakken is still in it's infancy. We'll continue to see that technology call come into the money. And were going to continue to see new areas of play become productive, because of the science dollars being deployed by the operators. And we look forward to more successes and the Big Sky project and more extensions to the play.

How extensive is that area out there? Could you potentially add a significant acreage position? Or is it kind of limited to a structural boundary?

That particular area that we have targeted is about a 5 or 6 township area, in which our main focus is with Slawson. So it's not a large geographic area, in that particular instance, But if the upper shale exists, it may exist in many other areas as well. This just happens to be the only one we have targeted, and seen success in. So again, as a non-operator, we don't want to shoot out there and pioneer, necessarily, a new play. We'll participate for some small interest as we see the play continue to develop. It's anybody's guess how that particular technique plays out over time.

Okay. That is all I had. Thanks a lot. Good job.

Thanks, Joel.

Your next question or comment from FIG Partners is Mr. Josh Silverstein. Your line is open, sir.

Hi, good morning, guys.

Good morning, Josh, thanks for coming.

Hi, there. I was curious about the growth rate you have put out with the 30% to 30% to 35% for the third quarter there. It seemed, I guess with the roughly 1,900 barrels a day of the average production you guys have for the second quarter, and with the exit rate of 2,700 barrels a day that, you might be a little bit conservative in there for your third quarter. I was just curious if that was just due to some timing related issues with wells coming on sooner than expected, or if there were some wells you expect might be delayed into the fourth quarter, as frac crews are less available?

The production guidance is always subject to depletion delays. And that has probably been our largest provider of variance quarter-over-quarter. The fact that our production is still relatively young and still is relatively sort of lumpy or chunky in nature, in that we have a lot of IP-type wells. If you have got a well producing for 18 days in the month as opposed to 28, and it's a 30% to 40% working interest well for Northern, that could have a significant effect. So we still do have some variance. As more of our production matures, we'll be able to hone in on a much more stable number, and looking at drilling activity, more accurately predict what we look like quarter-over-quarter. but we're still building in a little bit of a cushion for completion delays that will probably pick up a little as we get into the fourth quarter, and operators rush to get wells completed before the winter.

Got you. That was my next question. I was curious, I know EOG and Slawson had to wait for the completion activity or this past winter just because it could increase the cost of oil up to $100,000. And I am curious with frac crews tight, and cost continuance arise, that they are actually not going to be doing it this Wilmington or speeding it up to try to get everything done by let's say, November or early December.

Well, the winter frac question is a question that we have as well, and we haven't really received clarity on what the plans would be from the operators on that. We certainly did see significant delays for the winter last year. The cost to complete a well from our data, is actually much higher than $100,000 per well increase in the winter. It could be multiple hundreds of thousands. The other issue you run into in the winter, that you have a problem with completion, it's going to be a much bigger problem, if it's 20 below zero than if it's 70 degrees. So it s going to cost more to fix.

So the average cost to complete in the winter is probably substantially more than $100,000. The question will be answered, I guess this winter, now that we're seeing a much flatter oil strip. Last year, we were turning oil on into $6.00, $7.00 one-year [contango]. So theoretically speaking, it didn't really hurt you to delay completions, that you were saving money and able to hedge out on a higher price. With the flatter strip, we may see a greater amount of activity through the winter, but at this point we would just be speculating. We do think there will be a rush to get wells completed into November. How much of that has a material effect on our production, we really don't know.

Okay. And then ust the last question for me, and I think you guys touched on this previously, that you have about $70 million on cash on your balance sheet right now, and then the undrawn $100 million credit facility. Are you guys expecting your average well cost to increase next year, along with a higher working interest pick up as well from the 15% up to to, let's say a 25% working interest? Or are you guys going to looking to more aggressively acquire some additional acreage next year?

We'll continue to acquire, as long as the opportunities are there and the prices are right and accretive to us. We do generally expect well costs to be higher next year. We expect more west Nesson activity, we expect more longer laterals. So we do think that that well cost for us on average, when we look into 2011, should push through the $5 million mark. By exactly how much, it's hard to say until we put together the exact drilling schedule. But we do think that it will increase, and we'll continue to expand our acreage position where appropriate, and where it's the most efficient.

Great. Thanks, guys.

Thanks, Josh.

Our next question or comment from Dougherty & Company is Mr. Peter Mann. Your line is open, sir.

Hi guys, I just have one follow-up question. Looking at your hedging, you talk about being hedged at right around $80.00 for the year, and in Q2 here you had a released price of just shy of $71.00, which is maybe a little bit lighter than we might have expected. Would you mind giving us a little color the timing of those contracts, and how that might unfold through the remainder of the year?

Thanks, Peter. The hedging schedule that we lay out here is laid out on a per year basis. However, the settlements of hedges generally, our older hedges are at lower levels. So as we go through time, the actual settled part of our derivative contracts will increase. So we should see that change slightly over time. If you look at our settled price in the quarter, we continue see deducts of around $7.50, as to where we expect them, and model them to be in the future. So the larger percentage that our hedged volumes make up of our actual production, the closer you will see that relationship tighten. In other words, average hedge price to realized sale. The effect on the P&L can be noisy because of the some of the longer term contracts, are moving around quite a bit. And a lot of our hedge volumes are out longer. We probably benefited probably a little bit disproportionately this quarter, because of the flattening of the contango. We tried to move a lot of our hedges out further on the curve, in anticipation of that. So we shouldn't probably benefit from that as much in the future, but the hedging settlement should be fairly straightforward to read from this point on.

Perfect. Sounds great, guys. Great quarter.

Thank you, Peter.

Our next question or comment comes from the Company Southcoast. Mr. Marshall Carver, your line is open.

Yes, good morning, and good quarter. Just a quick question on growth rates. I know you really beat second quarter numbers, and third quarter you increased guidance. Do you think for the fourth quarter and through 2011, would you still suggest the 20% to 30% quarterly sequential growth rate? Is that a good number to use?

Well, for the third quarter, we expect to increase 30% to 35% and obviously with the guide up. Going out to fourth quarter and throughout 2011, we still feel comfortable with the 20% to 30%. As we have got a shorter runway, and we're able to look out one quarter, we're able to dial it in a little tighter, given the quality of the wells we continue to see, and given the amount of production still awaiting completion, we feel comfortable guiding up for third quarter. Fourth quarter and 2011, we're going to stick with the 20% to 30% sequential growth rate. And we believe that is sustainable for us at at a minimum through 2011. And what we'll try to do is provide some clarity on sort of a one quarter out runway, as we obtain that clarity.

Okay. Thank you. A couple more questions. So you said about half -- you spent about $27 million acreage in the first half of this year, would you guess the second half second half would be about the same? Or when we're trying to forecast where you will end the year, in terms of total CapEx spent? Go ahead.

Okay, sure. Thanks, Marshall. With regard to the CapEx, it's hard for us to provide acreage CapEx on the second part. If it's related strictly to drilling, it's easier for us to do. But when it comes to the acreage, we want to take the opportunities as there there. We have always been, we think, a very efficient is deployer of capital. And we want to -- rather than setting, sort of acreage goals, we believe it's better for us to take what the market gives. If we wanted to take this thing to 200,000 acres at the end of the year, certainly we could do that. That may not be the best strategy. There may be 30,000 acres that would be better to buy and more efficient use of the capital. So we're always going to look at it that way, and as such, I'm going to have to defer on what the acreage CapEx is going to be. As we go out for the balance of the year, we're going take the opportunities that are there, be they big or small.

Okay. Sounds good. One final question, on the second quarter production came in so much above guidance. Was there any timing, of wells that came in a lot sooner than you expected, that led to that beat? Or was it primarily just production per well coming in better than expected?

Thanks, Marshall, again it's Ryan. I think the answer to that is that it was primarily in the quality of the production. We have seen these wells, especially east of the Nesson, continue to hold up better than expected, 60 to 90 day rates for us continue to be impressive, and continue to exceed our expectations. So we're seeing production stay in there, and decline at probably a shorter rate than when we've expected. And we've have continued to see IPs come in bigger. We're still substantially in reality, based on how we looked at the beginning of the year backed up from fracing. So with 7.25 net wells basically drilling and completing ,you can see the potential increases we've got, still sitting behind pipes. So the main driver in the quarter increase is the quality of the wells, and we continue to see that across the play. These wells get better, they get cheaper. The Bakken is still at a very young stage, and I think we'll continue to see increasing and impressive result and lower costs.

And you think very little of the Q2 beat was well-timing?

Very little of it. Certainly we're going to have fluctuations quarter-over-quarter based on timing. We weren't disadvantaged in the quarter by timing. We may have been slightly advantaged, but the increase, I think, was driven primarily by better results.

Okay. Thank you very much.

Thank you. That was our last question in the queue. I would like to thank everyone for participating today's second quarter earnings release call. This concludes the program. You may now disconnect. Everyone have a wonderful day.