Northern Oil and Gas Inc (NOG) 2013 Q2 法說會逐字稿

The Northern Oil & Gas, Inc. Good day and welcome to the Northern Oil & Gas, Inc. second quarter 2013 earnings call. Today's conference is being recorded. At this time I would now like to turn the conference over to Mr. Michael Reger. Please go ahead.

Thank you, Mary. Good morning, ladies and gentlemen this is Mike. We are happy to welcome you to the second quarter 2013 earnings call for Northern Oil & Gas. With me today is Tom Stoelk our CFO who will discuss our financial highlights from the second quarter.

Before we begin this mornings call, you should be aware that certain statements made during the call may contain forward-looking statements based upon management's expectations, estimates, projections and assumptions, and involve certain risks and uncertainties. We encourage you to 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, 2012 and other reports we have filed with the SEC. These forward-looking statements relate to future plans objectives, expectations and intentions.

Our actual results could differ materially from those contemplated by these statements partially as a result of the various assumptions relied upon in making such statements. During this conference call we will also make references to certain non-GAAP financial measures. Reconciliations of these non-GAAP financial measures to the applicable GAAP measures can be found in the earnings release that we put out last night.

As we mentioned in our earnings release last night, Northern' s second quarter 2013 production was approximately 1 million barrels of oil equivalent or 10,900 barrels of oil per day. We added 83 gross,5.7 net wells to production during the second quarter which was below our expectations. The primary reason was wet weather and road restrictions that extended through the end of June resulting in an increase of our spud to sale cycle time to approximately 120 days.

Pad drilling also played a part in the increase spud to sales timing. However, the level of drilling activity in the Basin was stronger during the second quarter primarily due to pad drilling efficiencies. Our backlog of wells either drilling or awaiting completion expanded to 218 gross and 17.4 net wells as of June 30. InJuly, more net wells added to production than we did in the entire second quarter by completed 62 gross, 6.4net.

In addition, we spud another 5.7 net wells in July which kept our in process backlog as of July 31 at a robust 218, 16.7 net wells. This gives us confidence not only in the resumption of sequential production growthin the third quarter, but also in our revised 4.3 million barrels of oil equivalent production estimate for the entire year.

Acreage acquisitions continue to be strong as we were able to add approximately 4500 acres at just over $1000 per acre in the second quarter, bringing our total acreage count in the Bakken to 182,400 net acres. With the majority being held by production.

In North Dakota, 71% of our acreage is held which expands our in fill drilling inventory especially as our operating partners continue to test the boundaries of down spacing in the Bakken Three Forks and especially the lower benches of the Three Forks. As most of you know, we completed a $200 million tack on offering to our existing bonds during the second quarter.

The offering priced at a premium to par to yield 6.75%. The deal is priced on May 8 which is the day the high yield index dipped below 5% for the first time. This tack on allowed us to pay off our revolving credit facility in full.

The revolver currently has a $400 million borrowing base which is undrawn at this time,giving Northern strong liquidity to develop our asset base and be opportunistic with additional acreage and packages that fit well within our business model.

Our ability to continue to acquire acreage and develop our extensive drilling inventory, all while improving liquidity position without issuing equity, places us in a great position to continue executing on our business plan. We will remain disciplined with our effective and efficient non operator strategy. The Williston basin is maturing nicely with ample service availability, infrastructure, and takeaway capacity.

We are pleased to have such a large core acreage position with leading operating partners in this premier oil resource play. With that, I'm going to turn the call over to Tom Stoelk, our CFO, to discuss the financial highlights from the second quarter.

Thanks, Mike. During the second quarter, we reported GAAP net income of $25 million or $0.39 per diluted share. Excluding the effects of a non cash gain on derivative instruments we reported adjusted net income of $14.6 million, or $0.23 per diluted share.

Adjusted EBITDA for the second quarter was $58.2 million, bringing total adjusted EBITDA for the first half of 2013 to $121.7 million, which was a 24% increase compared to the first half of 2012. In the second quarter of 2013 oil, natural gas and NGL sales increased 13% as compared to the second quarter of 2012.

That was driven by a 5% increase in production and aided by a 9% increase in realized price on a BOE basis after taking into account the effective sale of derivatives. As Mike mentioned earlier, weather, road restrictions, and increased spud to sales timing for wells drilling on pads, impacted second quarter production.

Average realized price including all cash derivative settlements during the second quarter 2013 was $79.80 per BOE, compared to $73.19 per BOE in the second quarter of 2012.

The higher average realized price in the second quarter of 2013 as compared to the same period in 2012 was driven by higher average oil prices and a lower oil price differential. Oil price differential during the second quarter of 2013 was $5.32 per barrel, ascompared to a $13.72 per barrel differential in the second quarter of 2012. During the second quarter of 2013 we had non cash mark-to-market derivative gain of $17 million and that compared to a $49.8 million non cash gain in the second quarter of 2012.

Production expenses were $10.4 million in the second quarter of 2013, compared to $7.3 million in the second quarter of 2012. On a per unit basis production expenses increased to $10.49 per BOE in the second quarter of 2013, compared to $7.70 per BOE in the second quarter of 2012. This 36% increase was driven by higher water hauling and disposal and work over expenses.

Over the past 12 months, we have had significant net well additions in areas that have high levels of water production and a less developed water hauling and disposal infrastructure. In addition, during the second quarter of 2013, we experienced unusually high level of work over activities on wells shut in as a result of completion activities on nearby pads. The operators used this team time to do work over operations on the shut in properties.

A lot of our shut ins were located in the peninsula area of Mountrail County and we saw lots of completion activity. A working interest on wells in this area generally exceed 20%, compared to our company-wide average working interest of 8.5%. As a result, we had approximately six net wells shut in for a portion of the second quarter in the Mountrail County area alone.

Our production taxes totalled $7.6 million in the second quarter of 2013, that compares to $6.7 million in the second quarter of 2012. As a percentage of oil and gas revenues production taxes rates were flat at 9.5% in the second quarters of both 2012 and 2013. General and administrative expense was $3.9 million for the second quarter of 2013, that compares to $4.4 million for the second quarter of 2012. On a per unit basis general and administrative costs during the second quarter of 2013 was $3.95 per BOE and that is down 15% versus the prior quarter.

The decrease in aggregate dollars between the second quarter of 2013 versus the second quarter of 2012 was primarily due to decreased compensation costs. Depletion, depreciation, and amortization accretions, or DD&A, compared to $26.6 million in the second quarter of 2013, compared to $25.6 million in the second quarter of 2012. Depletion expense, which is the largest component of DD&A, averaged $26.66 per BOE in the second quarter of 2013, compared to $26.93 per BOE in the second quarter of 2012.

The provision for income taxes was $14.6 million in the second quarter of 2013, compared to $28.8 million in the second quarter of 2012. The effective tax rate in the second quarter of 2013 was 36.9%, compared to an effective tax rate of 39.8% in 2012. The decrease in effective tax rates in 2013 reflects a decrease in the corporate income tax rate in North Dakota.

The effect of this rate change was to lower our deferred state tax expense by approximately $500,000 in the second quarter of 2013 to reflect the impact on our previously reported and deferred tax liabilities. The decrease in state tax rates is expected to lower our effective income tax rate to something closer to 38.2% during the second half of 2013.

During the send quarter of 2013 capital spending totaled $101.5 million which places our first half capital spending at $201.9 million. Our total capital expending for the first half of the year is broken down as follows;drilling and completion costs were $182.2 million,$11.5 million was spent on acreage and related activities, and $8.2 million on other capital expenditure activities.

As we mentioned in the earnings release during the first six months of 2013, we placed 15.3 net wells in production and we currently estimate we will add 36 total net wells into production during 2013. Assuming our remaining drilling and completion costs per net well, are in the $8.8 million range, which is the estimated average AFD cost on wells in process at June 30, we estimate we will incur approximately $140 million of additional drilling and development costs in the second half of 2013.

At this time we are not revising our annual spending estimates for acreage related activities and other capital expenditure activities that are $20 million and $30 million respectively.

To summarize, we are estimating that our full year 2013 drilling and completion spending on an estimated 36 completed wells will be approximately $322 million, at an average cost of approximately $8.9 million per net well.

In addition we expect to spend another $50 million on acreage and other capital expenditures. Keep in mind that our actual CapEx spending will be impacted by expenditure levels on a backlog of wells in process at the end the year. We entered 2013 with a backlog of approximately 12.4 net wells in process and at June 30 this number increased to 17.4 net wells.

We continue to layer in hedges opportunistically as the market warrants to increase predictability of our cash flow and help maintain a strong financial position. Currently we have hedged 11,000 barrels of oil per day for the remainder of 2013. Approximately 54% of the 2013 hedging is done with costless collars with average floor of $90 per barrel and average ceiling price of $104 per barrel.

In 2014 we have hedged approximately 10,900 barrels of oil per day. The majority of the 2014 hedges are in crude oil swaps at an average price of approximately $90.50 per barrel.

In 2015, we have hedged approximately 4,400 barrels of oil per day. The majority of the 2015 hedges are crude oil swaps at an average price of $89.00 per barrel. As Mike mentioned earlier, our revolving credit facility is undrawn, and we have $400 million of borrowing base availability with debt annualized EBITDA of just 2.1 times. We believe we have ample liquidity to continue to develop our asset base.

At this time I would like to turn the call back over to the operator. Mary, if you could provide some instructions for the Q&A.

Thank you. (Operator Instructions). We will take our first question from Scott Hanold, with RBC.

Mike, if we step back and look at it, seems like production has been hanging around the 11,000 barrel a day average for the last four quarters. Certainly it sounds like it is probably a bit of a frustration for you guys too with weather and pad drilling. Can you give us a sense if we are starting to break out of that? I know it sounds like July you have had a number of completions. Can you give us a little color on where some of those are at? And if you got any sense of what current production might be post some of those completions, it would be great.

Thanks, Scott. I would say that in the first half, as expected, we had the typical first quarter weather. We did experience extended road restrictions which usually come off in mid May that were extended through about July 1. Some road restrictions even extended through about the 8th of July. We did expect our first half production to be relatively flat and then we expected sequential production growth to resume in the second half. Part of that was pre pad drilling. Part of that would be better weather in the second half, typically.

The two main drivers, as both Tom and I mentioned earlier in the script, for production growth would be that at the very beginning of the third quarter here, in the month of July, completion activity was robust. In addition, a lot of the wells that were shut in, especially in southern Mountrail, came back on. The wells that contribute to our production in southern Mountrail, for the most part were shut in for portions of the second quarter, are all now back on. Plus we had more net wells completed in July than we did in all of the second quarter. So, we fully expect that to resume sequential production growth.

As you know with another 218 wells currently drilling, or completing, plus completing about 62 wells in July alone, that puts us probably over 1500 producing wells. So it very difficult to estimate exactly what our production is on a given basis at any given time. We just have a look back once each month ends. We have about a 45 day window where we end up seeing what the month production really looked like. It is hard for us to give a number right now but we do believe that sequential production growth has resumed here especially given the robust you completion activity in July.

I appreciate that. And certainly I understand the weather is kind of challenging and just wanted to get sort of a feel if we are going to see a breakout. Good to see the well counts creep up. I guess the point I was making is that your net well count has increased over the last year by a fair amount and just the production hasn't broken out. If I look at some of those like southern Mountrail wells that were is shut in that were brought online, and I'm sorry if he missed this, but did you give the net count that it was to you all, and did you know what roughly production, just from that group of wells, was?

Well, we said in the script that we had about six net wells in Mountrail alone and probably lost production is what you are getting at and I would place it at about 150 barrels of oil equivalent for the quarter in our total average, Scott.

Okay. And then as a follow-up question, too, on CapEx and Tom you went through a lot of numbers in the CapEx but it sounded like it came down to $372 million is planned completion and acquisition and other type activity that gets you well below your full year run rate or the full year -- the full year budget of $420 million to $440 million. Is that where you think you are going to shake out this year? Is there was anything else that we need to think about layering on there in the second half of the year?

No, I mean unless we have some acquisition activity. Currently at a 36 estimated we peg it at about $8.9 million on average. You it add the numbers up right, roughly about $372 million. The only thing I added the very last sentence when I was going through the CapEx was that a little bit of it depends on the pace of development and where our wells in process, or our back log backlog is. We came into the year with about 12.4, we estimate it will go down from our existing levels to maybe 17.4. Not exactly sure whether it will be 12, 14, what will be in process. So we will incur some capital costs for wells that we won't complete in 2013 that will be completed in 2014. So I was basically trying to tip a little bit of keep that a little bit in mind. So watch our wells our backlog a little bit.

Okay. So, just so I understand that,if you have if there is a net change of roughly, let's call it five, wells in backlog from the beginning of the year to the end of the year, I could associate whatever the drilling cost is on those five wells and it to the 372?Is that how I should think of it?

Yes, that is how you should think of it. The only thing I would add to that is that you can assume that if they are all at the same percentage completion. For example you might have wells coming into the year that are only 20% complete. You might end up the year with wells that are 80% complete. So as a general rule of thumb what you were just describing you could do but there is variability depending on the composition of that backlog.

Okay. So probably the full year CapEx number probably shakes out around $400 million then, give or take?

I think it will actually be a little bit lower than that. Based on the percentage completion of the composition really in 630. So I think it is lower than that.

Scott, we are assuming that the DNC, list this is Brandon, that the DNC list at the beginning of the year and end of the year are approximately equivalent. That is now you got to the original math of 372 and I think we are comfortable with that.

Understood. Well cost averaging this year, 8.8-8.9, a little higher than you were targeting, especially toward the end of the year. Can you give us a little bit of color on what you are seeing there?

This is Mike. I think what we have been looking at here, especially at the beginning of the year, are substantial percentage of the net wells that we have been drilling and have added to production have been in Mountrail and McKenzie so you have a little bit deeper rocks there so a little higher than what we expected. I think industry wide and we are watching our operating partners as closely as you are. We are generally feeling a trend down but we like to report what AFE estimates are as we receive them and then we monitor over or under runs on those AFE's from actual. But we are pretty comfortable in that 8.8 to 8.9 range right now and like all of our operating partners, hopeful that continues to move down from some of the levels we were seeing in 2012.

Okay. Thanks, guys.

Thanks, Scott.

And we will take our next question from Ryan Oatman with SunTrust.

Hi, good morning, guys.

Good morning.

Tom, wanted to ask you quickly on the operating expense I saw it tick up a little bit this quarter. Wanted to see if you had any color around why that was and what we should expect for the rest of the year?

I think that this quarter obviously we got a couple of factors we mentioned them in the script. One was the water hauling and disposal charges and I gave a little bit of color on that as well as the work over expenses. Let me talk about the work over expenses first.

A lot of those were incurred in Mountrail where our working interest averages are two or three times normal what they are in other areas of the Company. I think what that did was it caused an abnormally high percentage of working interest expenses as comprised of our total LOEs. I would probably peg that number in the general range of about $0.80 to $0.90 added that I think is unusually high compared to what I would term the normal level of work over expenses. So I do think that you will see our LOEs second half trend lower.

The water hauling is a little bit different situation. It is located in some of the Northern Counties of northern North Dakota where we have a higher working interest percentage. This those areas they are developing infrastructure that should lower the cost but it is a work in process and while I think that over the long-term those costs will trend lower, I think, over the immediate term it going to cause our LOEs to remain a little bit higher. If you recall at the beginning of the year we pegged an estimate I believe of around $8.50 per barrel of oil equivalent. Right now I'm probably thinking more in the mid nines with respect to the production expenses per BOE, if that is helpful.

That is, very much so. And then a couple of strategy one's, Mike. We have seen another operator recently make an acquisition and they acquired a significant non-op position. Have you been talking with that operator and, if you want to speak more broadly, where do you see the opportunities to add to your existing position?

I think that right now there are only a handful of non-op packages available in the field. We obviously look at all of them. Northern has typically acted more as a clearing house for specific acreage involved with specific well proposals and ASEs. That is how we have been organically growing our acreage position and that is going to come at more of a wholesale type price than some of the marketed packages. There are a handful of packages there. We are looking at all of them but there is nothing specifically that we are looking at. I know the one you are referring to and it is interesting but it is nothing that we are currently focused on.

Sure. And then one final one for me. Detail oriented, so might need to follow up after the call. Can you remind me if you recall what your working interest is in the Lilly Bridge west and east pads?Looked like good results from another operator recently.

Why don't we take that one off line and we can walk through specific wells. That is not something we want to get into on the call. We have 1500 wells our there. If you want to tack to any specific field or area we would have to get into that. I would say if you want some color on where some of the wells we have added are, and where the higher working interests are, it's going to be typically in the southern Mountrail area with ELG and (inaudible) . That's where, subsequent to the end of the quarter we had a lot of completion activity and is also where a lot of the wells were shut in, but then also reworked, but then also brought back on, in July. That it probably the color you really need, but happy to talk about any well or field off line.

That is perfect. I appreciate it. Thank you.

Thank you.

We will take our next question from Jared Lewis, with Northland Securities.

Good morning guys.

Good morning.

I wonder if you could give a little color from the geography on the wells that came on in say the past 12 months versus the wells completed in July and where you're going and if you are seeing any difference in the well performance being reflected in the production?

Here is the answer to that. And it really gets to the net wells that were added in 2012 as compare to the net wells that we are adding here in 2013. A couple of factors important to note. One, in 2012 the rigs in the field, specifically North Dakota, were noticeably absent in Mountrail County and east of the Nesson anticline line where northern substantial core acreage position. Really the rigs were out working west of the Nesson anticline, north and south et cetera. So the net wells that we added in 2012 didn't have the same potency, if you will, of the wells we were adding in 2009, 2010 and 2011.

As we entered 2013 the rigs very noticeably moved back into the core. Then the other bit of data that I would say is that in 2012 we farmed into a handful of wells in Divide County that really didn't add to production like our typical net well would. So, there were two events that were happening in 2012 from a net well add standpoint in relation to the production that would come with those wells. We farmed into some acreage, we farmed into some wells in Divide County which that is not a recurring event.

It was a small opportunity that we took advantage of and those net wells that we added in Divide County in 2012 didn't add the production like our typical net well does. And then again rigs were noticeably absent in the core during 2012. So as we entered into 2013 here, the net wells that we are adding I would say that in our net well list, our drilling and completion list, at the end of the first quarter, at the end of the second quarter, and then at the end of July, you could see a noticeable and pretty heavy percentage to Mountrail County, McKenzie County and anticline.

We believe our 2013 net well adds will resemble more of the 2010 and 2011 net well adds. And then 2012 we're looking at as a unique year given than we added some where in the neighborhood of about five to six net wells in Divide County that just didn't really contribute as much as our typical well does. And then the rigs were noticeably absent from the core.

But the rigs are now noticeably present in the core, especially as it relates to our best acreage where we have the higher working interest, the rigs have been very active since the end of 2012 and into the beginning of 2013. That is some important color that you should know and we think that the 2013 net well adds will be as potent, or more, than the net wells that we added in 2010 and 2011. Not sure if that is clear or not but just wanted to give you some color on that.

No, no, that is very helpful. That is good color. Appreciate it. Real quick final on just the land in North Dakota held by production. It has been steady around the 7% range. What do you see with that remaining acreage that is not currently held by production?

What we did is the data points we have given you in the past, there are specific categories that acreage falls into. Developed, held by production,held by operations, and then in the past we've always added the permitted. Our permitted list is becoming so vast that it is hard for us to really account for that. So really that 71% number is just developed, held by production, or held by operations. So that number does not include permitted which as you can imagine with the volume of well proposals we receive even on a daily basis here at Northern, that number is big. But we going to stick with from now on purely just the held by production data from developed held by production and held by operations.

Perfect. Very helpful. Thank you.

Thank you.

And we will take our next question from Marshall Carver, with Heikkinen Energy Advisors.

Thank you, that's Heikkinen Energy Advisors. A couple of questions just to make sure I have my numbers right. The LOE averaging $9.50, is that for the back half of the year or for the full year? Where do you think it will be in the back half of the year?

I think it will be about $9.50. I should have clarified that, I apologize.

No problem. And EOG seems like they are drilling some particularly great wells this year. What percentage of your wells are with EOG right now?I know you used to give the percentage of wells with different operators. Do you have that number handy?

I think if you look at our public power point presentation we have typically given a percentage of total net wells that we are exposed to with EOG. That is probably in the 8% range right now of our total net wells Company wide that are exposed to EOG. As we continue to add new units with EOG that acreage position we hold with EOG will remain somewhat stable as far as from in field drilling standpoint. EOG is a very innovative operator and we are monitoring what they are doing, and what Whiting's doing, and Continental is doing, and others are doing, from a sand volume standpoint et cetera. We are excited to see innovation continue.

Is this year's program probably more than that 8% or still about 8% with EOG?

I would say it is about the same.

Okay. The expirations the next few quarters, how many acres do you think you might lose to exploration say between now year end? Seems like you are adding acreage but also losing some. I imagine you are losing the lesser quality acres versus the ones you are gaining. How many acres are exposed to expiration between now and the year end, and over the next year?

I have the numbers here in front of me,In Q3 we have about 5,000 acres that are exposed to expiration that could potentially expire if they are not held by operations, and then subsequently by production or developed. Of that, about 3,800 of that 5,000 are in Richland County in our area of mutual interest with Slawson.

That doesn't give us much concern at all. Slawson is one of our most efficient and effective partners and we are very comfortable with their drilling schedule out there. They've got a rig actively working in our Big Sky AMI. They will hit the units that we certainly want to hold.

We own this acreage jointly with Slawson in the AMI so it is not as if our acreage is expiring and theirs isn't. We acquired the acreage together. Slawson is driving the bus out there and doing a great job. Of the 5,000 that could expire in the third quarter, 3,800 is in Richland County. And then in Q4 we have about 2,000 that could potentially expire Company wide that could potentially expire.

So very limited expirations from here on out. The only expiration pressure is coming from Richland County and the Slawson AMI.

Thank you. One final question. You mentioned six net wells in Mountrail. Was that the number of wells currently in backlog that are in Mountrail? I just didn't get what that was in reference to, the six net wells.

What Tom referred to in the script was we had six net wells that at some point during the second quarter had been shut in due to work over, or had been shut in due to pads being completed adjacent to those units.

Okay. Got you.

We have a significant portion of ournet well count in southern Mountrail, on that peninsula. When Slawson brings in the brack crews,they will be shutting in a lot of our wells there.

Okay. All right. Thank you.

And we will take the next question from Jason Wangler, with Wunderlich Securities.

Good morning, guys. You talked about a pad drilling and it seems like the whole base is really shifting that way. Do you have sense for your inventory or even your going forward? The break down on a percentage basis of what you are seeing on the pad drilling side?

I would say that currently 80% of our drilling activity is on a pad with at least two wells planned. As you know, most of the wells are at least four but I would say, just to give you a good data point, 80% are on pads with at least two wells planned.

That is helpful, Mike, thanks. And then just from the liquidity perspective. Obviously you have the line and it's undrawn. Curious when the next re-determination is there and what your thoughts are going into that?

The next scheduled re-determination is October 1. Plus going into that is we will take look, it is typical for us based on the build of our reserve value to request borrowing base increases. We'll take a hard look at thattime. I think we are in good shape with respect to it and finalizing reserves for that. So we will take a hard look at it. Don't necessarily need the liquidity but might be something we ask for even if though we don't need it.

Agreed. That is kind of why I was asking. Appreciate the color, guys, thank you.

Thank you.

We will take our last question from Curtis Trimble, with Global Hunter.

Thank you very much. Good morning, everyone. I was hoping maybe to chat a little bit about AFE flows and maybe get a little characteristic of what is kicking out of your model. In terms of AFE's and why it is kicking out in terms of real complete cost or projected LOE, et cetera.

Thanks, Curtis. Going through the data here, on July 31st we had about 218 wells that had come in that were on our DNC list, excuse me. So 16.7 net, so that's an average working interest of about 7.6%. The total spuds in July were 62, so about 2 a day spud. I'm trying to give you as much color as I can see here. Our AFE activity and the volume that we are seeing is still robust. The beauty of pad drilling efficiencies is we will get in some cases on the same pad we will get 4 AFE's in the same envelope. So that continues to be robust.

And they range in amounts really over the last three months. AFE's come in the door have averaged somewhere between a range of 6.9 million and 9.9 million depending on the location as to where they are at. McKenzie typically running at the higher end of that range.

Sure, just because of depth?

Yes.

In terms of one's that don't meet your economic criteria, can you tell me what component of the AFE generally is restrictive?Whether it is just completion cost or some other component?

It's total. I'm not sure it's restrictive. We go through our economic analysis on it we are having our engineering department take a look at the IRR so it is looking at offsetting production and using analogy and other factors like that. But the majority of the AFE's that we non consent are really driven by too high of costs based on what we estimate the estimated EURs are on it. There isn't really a component that I could point to and say well, we think the completion cost because of higher fracturing or stimulation, or the completion methods are really driving it. We kind of look at it in total, and then take a look at our estimated EURs and just and IRR or ROE on it.

Outstanding. I appreciate it.

And that does conclude our question and answer session. I would now like to turn the conference back over to Mr. Michael Reger. Please go ahead.

Thanks, Mary. Thank you, everybody for your participation in this call and interest in our Company. Mary with give you the replay information and we look forward to seeing you all soon, and sharing our results with you next quarter. Have a good day.

That does conclude our conference. Thank you for your participation.