Northern Oil and Gas Inc (NOG) 2011 Q3 法說會逐字稿

Good day, and welcome to the Northern Oil & Gas Inc. Third Quarter 2011 Earnings Release Conference Call. Today's conference is being recorded.

At this time, I would like to turn things over to Mr. Michael Reger. Please go ahead, sir.

Thank you. Good morning. My name is Mike Reger, I'm the Chairman and CEO of Northern Oil & Gas. I'm here with Ryan Gilbertson, our President. We are excited to welcome you to the 2011 Third Quarter Earnings Call for Northern Oil & Gas.

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 upon Management's expectations, estimates, projections and assumptions that involve certain risks and uncertainties. We encourage you to review the various risk factors relating to our Business, which are available on our annual report on Form 10-K, for the fiscal year ended December 31st, 2010, and 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 the various assumptions relied upon in making such statements.

For those of you who are joining us to learn about Northern Oil & 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 with a working interest on a heads-up basis in proportion to our leasehold interest in each drilling unit. Any time a well is permitted, all parties controlling leasehold interests within the drilling unit are automatically offered the opportunity to participate as a working interest partner. As such, Northern Oil's leasehold interests are included in any well drilled within drilling units containing our leasehold interest.

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 the well, less our royalty burden to the mineral owner. We do not farm out our interests or dilute our interests in any way. We participate for our proportionate working interest without the infrastructure and the overhead costs of our operating partners. We believe capital is most efficiently deployed through this strategy due to the substantial discount for which non-operating leasehold interests can be obtained.

I would like now to hand over the call to Ryan Gilbertson, to go through the third quarter financial results. Go ahead, Ryan.

Thanks, Mike. Oil and gas sales for the third quarter of 2011 were approximately $42.7 million, which represents a 180% increase from the third quarter of 2010, and a 23% revenue increase from the second quarter of 2011.

Production volumes in the third quarter were a quarterly record of 528,000 barrels of oil equivalent, which represents a 111% increase compared to the third quarter of 2010, and a 32% increase compared to the second quarter of 2011. These production results were within the range of our previously issued guidance for the quarter.

Average daily production in the third quarter of 2011 was approximately 5,900 BOE per day based on the 90 day producing quarter. September 2011 daily production averaged approximately 7,000 barrels per day.

Third quarter 2011 production consisted of approximately 93% crude oil and 7% associated natural gas and other liquids. It's important to note that the shift of increase in natural gas production for Northern doesn't have anything to do with a shift in focus. It's actually a positive. It means we are capturing more of the natural gas that was previously been flared off, associated with these wells. And as we see additional field level infrastructure continue to be built up, we expect to continue to capture more of this gas that was previously flared.

During the third quarter of 2011, Northern Oil added production from 88 gross or 5.7 net wells. During the nine months ending September 30th , Northern Oil added production from 216 gross, 17.4 net wells. Northern Oil is currently participating in a Company record 201 gross, 22.8 net, Bakken or Three Forks wells that are drilling, awaiting completion or completing, as of November 4th .

During the third quarter, Northern Oil spud approximately nine net wells. From October 1st , 2011 through November 4th , Northern Oil has spud an additional five net wells, bringing the cumulative net wells spud in 2011 to 31 through November 4th, 2011. We reaffirm that we expect to spud at least 40 net wells in calendar year 2011.

During the three months ended September 30th , Northern Oil realized an $81.53 average price per barrel of crude oil, after taking into account the effect of settled oil derivatives, compared to $69.64 per barrel after the effect of settled derivatives during the three moths ended September 30th, 2010.

During the nine months ended September 30th, 2011, we realized a $79.22 average price per barrel of crude oil after the effect of settled derivatives, compared to $69.85 under the same metrics for the nine months ended September 30th, 2010.

Production expenses for the third quarter were $6.57 per BOE,compared to $4.19 perBOE in the third quarter of 2010, and $5.94 for BOE for the second quarter of 2011. The increase in production expense is primarily due to exposure to new operators and development areas, mature wells utilizing artificial lift, and the general aging of our production.

Depletion expense for the third quarter 2011 was $10.7 million or $20.34 per BOE, compared to $8.3 million or $20.83 per BOE for the second quarter of 2011. The decrease in depletion expense per BOE is primarily due to the increase in our crude reserves relative to acreage and well development costs related to estimates of our proved reserves.

General and administrative expense, net of share-based compensation, for the third quarter of 2011 was $1.9 million compared to $1.2 million in the second quarter of 2011.

Share-based compensation for the third quarter 2011 was $2.2 million, compared to $1.5 million in the second quarter of 2011.

Adjusted EBITDA for the third quarter of 2011 was just under $32 million or $0.51 per fully diluted share, which represents a 150% increase over adjusted EBITDA of $12.8 million or $0.24 per diluted share for the third quarter 2010, and a 40% increase compared to the second quarter of 2011. Northern Oil defines adjusted EBITDA as net income before interest expense, income taxes, depreciation, depletion and amortization, accretion of abandonment liability, pre-tax on realized gains and losses on the mark-to-market of derivative instruments, and non-cash expenses relating to share-based payments recognized under our Accounting Standards Qualification topic 718.

Net income, excluding realized mark-to-market hedging gains or losses, and adjusted EBITDA are both non-GAAP measures. Reconciliations of these measures to the most directly comparable GAAP financial measures are included in our Company and financial tables found later in this release.

We believe the use of these non-GAAP measures provides useful information to investors to gain an overall understanding of our financial performance. Specifically, Management believes that non-GAAP results included herein provide useful information to both Management and investors by excluding certain expenses in unrealized commodity gains and losses which Management believes are not indicative of Northern Oil's cooperating results. In addition, these non-GAAP financial measures are used by Northern Oil's Management for budgeting and forecasting, as well as subsequently measuring Northern Oil's performance. And Management believes that we are providing investors with financial measures that most closely align to its internal measurement processes.

As of September 30th, 2011, Northern Oil had a total volume of open commodity swaps consisting of just over 1.2 million barrels of oil at a weighted average price of $89.29, settling between October 2011 and December 2012.

In addition to the swaps, as of September 30th , Northern Oil had 108,000 barrels of crude oil collared between $85.00 and $101.75, settling the balance of 2011. Subsequent to the quarter ended September 30th , we entered into two additional costless collars. As of November 7th, we have just over one million barrels secured through the use of costless collars settled in WTI NYMEX pricing with an $85.00 floor, and caps ranging from $101.75 to $95.25.

During the third quarter of 2011, we acquired leasehold interests, covering an aggregate of 6,300 net mineral acres, for an average of $1,880 per net acre, for aggregate cost of approximately $11.8 million. As of September 30th , we control more than 158,000 net acres in the Williston Basin Bakken and Three Forks play. As of November 4th , Northern Oil has approximately 50,000 (sic- see Press Release) net acres either developed or under the bit, which represents approximately 37% of out total Bakken and Three Forks position as of September 30th .

We currently expect to increase production volumes by approximately 25% to 35% in the fourth quarter of 2011 over the third quarter of 2011,assuming typical weather scenarios in the Williston Basin in November and December. This expectation is based on robust recent completion activity, and the higher average working interest per completed well that Northern Oil expects to see in the fourth quarter compared to the third quarter of 2011, as well as our record backlog of over 20 wells drilling or completing.

With that, I will turn it over to Mike Reger for a final comment before the questions-and-answers.

Thanks, Ryan. With approximately 37% of our Bakken and Three Forks' positions developed or under the bit, we are moving ahead at an excellent base. We believe our expertise in specialty and non-operated interests continues to yield excellent results, and we continue to add meaningful acreage, production and cash flow. We wish to recognize the substantial contributions in advancing this play made by our operating partners. And remain extremely excited about the continued evolution of oil exploration and the production in the Williston Basin.

With that, we will now turn it over to the question-and-answer session with our covering analysts.

Thank you. (Operator Instructions.) And we'll take our first question from Peter Kissel of Howard Weil.

Yes, guys, how are you? Good morning. My question is -- it primarily relates to MLPs. And in the past, you discussed the potential of an MLP being a good way to return some assets back to the shareholders, essentially. And I'm just curious to see where the MLP process stands, if that's still something you are looking at? And thoughts you have would be helpful.

Thanks, Pete. This is Ryan Gilbertson speaking. Our commitment to the Williston Basin and the Bakken and Three Forks play only will leave us in a position of excess cash flow, without question. And we have explored a number of different ways to return this excess capital to shareholders, and all things remaining equal, we believe that a side-by-side MLP strategy is the best way to accomplish this. So we are currently running out the exploration of how that would set up. And this is something we expect to address, more specifically, in the first quarter of 2012, as we have clarity on our production for the year. But the bottom line is we have always believed in returning capital -- excess capital to shareholders in the most efficient way. And we think that, given what we see in the marketplace right now, a side-by-side MLP with Northern acting as a general partner would be the most efficient way to accomplish that objective.

Got you. Thanks. Maybe just one quick follow-up on that. With Rich Weber joining the Board earlier this year, how instrumental and active has his influence been on pushing more towards the MLP sooner rather than later?

Thanks for that. We havemade a couple of, we think, very strong additions to the Board with the addition of Rich Weber, the former head of Atlas, as well as Cy Jamison, who ran the Bureau of Land Management under the Bush Administration. Both strong additions to the Board. Rich, specifically, has been a big help in guiding us through a learning process of how an MLP would most efficiently work within our Company and our asset base, and then certainly been a big driver in our understanding and continued exploration of that.

Thank you for mentioning that, because we are very happy to have Rich and Cy join the Board. Both strong additions that bring a great amount of experience and wealth -- as well as our addition of Tom Stoelk, announced today as CFO. Tom's history with Superior Well Services, Great Lakes Energy and Range Resources is also a wide range of experience that we are happy to have here on board with us at Northern Oil. So thanks for those questions, and absolutely, you are right, Rich has been a big driver in our learning in advancing this process.

Great. Thanks, Ryan. Thanks, guys.

Thank you, Pete.

Thank you, Pete.

And we'll take our next question from John Freeman, Raymond James.

Hey, guys. On the LOE, we had another big increase this quarter. And I know last quarter you all talked about it maybe increasing another 10%, 15% from that second quarter level. And now that we are sort of at that level where I think you all had indicated it would probably start to plateau, I'm wondering if the thoughts have changed at all, in terms of LOE going a little bit higher from here?

Yes, thanks for the question, John. This is Ryan speaking. The one comment that we have seen related to LOE, that's been mentioned in calls by many of our operating partners, has been increased cost for saltwater disposal. And there's a number of steps being taken to remediate that issue, as far as hooking up pipelines to dispose of saltwater and really lower that. Some of our peers have mentioned that saltwater is -- the saltwater disposal is making up close to 50% of their lease operating expense.

Our lease operating expense right now, being concentrated primarily to the east of the Nesson anticline has still remained lower, and in many cases, significantly lower than our peers. As far as where we see that continue to grow to, I do think we are getting close to an inflection point, or at least a temporary plateau. But as we see a general aging of the population, we will probably see LOE continue to creep up over the next two or three quarters. And the main driver of that will be what the operating partner is able to accomplish, with regards to saltwater disposal. And, again, we believe that economics and the flow of capital will take care of that. We have seen differentials tighten as an offset. But we do believe that in the future, there will be more efficient ways to dispose of saltwater and that should help to remediate that to some extent.

But to answer your question, I think we could see LOE creep up at a similar rate for the next two or three quarters, probably before plateauing, all things remaining equal from what we see right now.

Okay. One more question from me. The mix of you all's wells, historically or at least recently, has been, between Slawson, EOG and Continental, has made up about 60% of your gross wells. And based on the wells that you all outlined in your release, just the next wells thatare either currently being drilled or awaiting a completion, it looks like those three become about a 30% or so of your mix. And I'm wondering how that impacts your average well cost. And how this change in the mix of the higher working interest wells being with different operators and how that compares to the $6.5 million a wellguidance you gave last quarter.

Well, the driver, primarily, in well costs for us is not necessarily the differentiation in operators, but more the differentiation in geography. As we move to more drilling west of the Nesson anticline, in Williams and McKenzie Counties, these wells are typically expensive. Number one, because they're almost always going to be long lateral, versus some of the shorter laterals we see in the Mountrail county -- or one section in a [40] acre unit. The 1280s are going to be more expensive and it's a deeper part of the basin. We generally see those wells to the west being a little bit more expensive. It's not that the operators we see to the west are necessarily significantly less efficient. It's just the type of wells they have to drill, given that geography.

So we will see well costs continue to creep up. We think that our average this year is probably going to be about 10% --7% to 10% lower than what we expect to see in 2012. So we should push through $7 million as an average well cost in 2012, as we continue to drill to the west. But a lot of that will be determined by increasing or decreasing efficiencies as we get through the next couple of quarters and what the winter does to us.

Great. I appreciate the info, guys.

Yes, fair assessment. Thank you for the question, John.

And we will take our next question from Scott Hanold, RBC Capital Markets.

Good morning.

Good morning, Scott.

Just to clarify on one of the questions; you indicated that you think LOE cost is going to increase over the next couple of quarters at a similar pace. Quarter-over-quarter, it looks like it was up about $0.85 to $0.90. Is that what you are saying, you expect that type of an increase in both the 4Q and the 1Q? I wanted to clarify that, first.

Yes, to clarify, I think you can see LOE grow by that or slightly less amount. I think LOE growing by $0.60 to $0.90 a quarter is probably a reasonable assumption.

Okay. Thanks for that clarification. And in terms of some of the flared gas that you all have come online and I know other operators indicated they are going to be working to get more on; how much visibility do you have when you set your guidance on how much of that flared gas could get connected? Because it sounds like early 2012, by early 2012, there will be a lot of it being brought on.

To be honest with you, we don't have a great deal of clarity on that. We know that as a general trend, we are seeing a significantly more and more wells hooked up to gas. And as we see more wells in clusters, we see greater field level infrastructure being put into place. So we don't have a high degree of empirical certainty as to what those numbers will be. But we are very confident in the trend -- that it continues in the right direction.

Okay. So when you are looking at the fourth quarter guidance that you all put out -- and the crux of the question is how -- do you tend to be a little bit more conservative with the flared gas contribution, if I can call it that?

I think that's a correct assessment.

Okay. And finally, just one other question. it looks like you continue to pick up nice little chunks of acreage at some pretty good pricing each quarter. What is your view on the ability to keep knocking out several thousand acres a quarter at pricing around $2,000 an acre?Do you see 2012 setting up similar to what we saw in 2011? Or will the strategy have to shift a little bit?

Scott, this is Mike. We haven't seen any material change in our ability to acquire acreage. We continue to see opportunities every day. We have a very unique niche in what we do and how we acquire both new acreage and non-operated interests from other operators. We don't see that changing any time in the next few quarters.

Do you see any in particular -- in any certain counties, like with the strong well results coming from Whiting, any more competition in certain areas or less competition in other areas that you could talk about?

The competition is generally fairly strong in the Basin regardless of area. We just will continue to see the types of opportunities that we have always seen. Which is -- now more and more operators divesting their non-operated interest to us, as well as the acreage we are acquiring organically on the ground through our brokerage team. So we don't see any general area becoming more and more aggressive, from a competition standpoint. We will continue to see the opportunities that we have always seen.

I appreciate that. Thanks.

Thank you, Scott.

And moving on, we will go to Marshall Carver, CapitalOne SouthCoast.

Yes, good morning. A couple of questions. The -- so you added a few thousand acres. It looks like that net position grew about 3,000 acres. So the implication is that about 3,000 acres expired. What counties were those lease expirations in? Do you have those details?

It was a balance of a lot of counties. I would say the majority, again, is going to be in southern Dunn county to the east. We lost some acreage down there. But on a quarter-over-quarter basis, we continued to net add acreage.

Right. Okay. Good. When do you expect to give 2012 guidance? And do you have any feel for your capital budget there? Or when do you plan to announce that?

Yes, hi, Marshall, this is Ryan speaking. We expect to announce that prior to the end of the year. We are waiting to finalize a couple of different initiatives that will help us gain some clarity into 2012 drilling. I can tell you that we do expect to drill, at a bare minimum, as many net wells as we spud in 2011. So the number of net well spuds in 2012 will be at least 40. And if I had to put a range on that, I would probably say that our well spuds in 2012 will be between 40 and 52.

And our capital budget, on a wide range, is probably around $310 million, plus or minus, call it 10%. But we will hone in on those numbers over the next month and come up with a number we are very confident in. We have always been very confident in our net well numbers, and what we have initially put out at the beginning of the year has typically increased proportionate with rig count. So the real key is what happens to rig count and what happens to acceleration of development in the Basin. And where do we end up finding the ultimate boundaries of the field, which we still haven't seen.

So if you look at generally where we have moved in guidance from the start of the year to the end of the year, it's generally been in correlation with rig counts. So as soon as we have some final clarity on what it looks like for 2012, we will be able to hone in on that.

And that will be a drilling and completions budget, not including acreage, correct? Hello?

Sorry, Marshall, could you repeat that question?

Would that be -- $310 million, that would be for drilling and completions and acreage would, potentially, be on top of that?

Yes, that's correct. Acreage would be upside of that. We've always looked at the acreage as something that we will pursue as it's available.

Right.

We have never really set a budget. We send to gravitate towards the $20 million a quarter number, it sort of feels like the size of the opportunity. But we won't push the opportunity in quarters where we don't see as many opportunities. And if we do see additional opportunities, we're not afraid to exceed that number, given our capital position in any given quarter.

Okay. Thank you. One last question, if I could. Do you have a feel for how many net wells you expect to go online in the fourth quarter?

Well, Marshall, one thing that -- one thing that we do know is that in the month of October, we added approximately five net wells. So we are ahead of -- we spud approximately five net wells, so we are a little ahead of pace from what we typically see in a quarter. Completion activity right now is fairly robust because the weather is remaining really good in the Basin. So we're actually pulling these numbers together right now to see where we are, if you give us one second.

Yes, Marshall, this is Ryan. We added production from 5.7 net wells in the third quarter. And we would expect to add production from at least as many wells in the fourth quarter. And that number probably has a little bit of upside to it. So I would say between six and seven net wells is the number we would expect to add from our drilling and completing list right now to production in the fourth quarter.

Okay. Thank you.

And we'll take our next question from Marty Beskow of Northland Capital Markets.

Good morning.

Good morning, Marty.

For the third quarter, it looks as if though the average working interest for the wells that were completed was around 6.5%, versus, historically, I think you were closer to 10%. Were there any operators or wells that you thought that were going to be completed that ended up not getting completed until October or sometime later?

Yes, Marty, that's a good observation. The average working interest, like you said, of the wells that were added was just over 6%. Now, if you look at our drilling and completing list, the average working interest on there is about 11%. What that's telling you is that our higher working interest wells happened to be pushed back from the drilling and completing list, as opposed to what got completed. Just for the luck of the draw on the way the third quarter ended up sorting itself out. What that means is with a similar number of gross wells being completed in the fourth quarter, the number of net wells will be reasonably higher. Given that what we added in the quarter of 6% is lower than the 11% average of the wells we have currently drilling. So, again, just the luck of the draw in the way the wells ended up falling into the quarter.

Okay. And as far as acquiring acreage, how has that changed over time? Are there any certain areas where you are acquiring more acreage from now -- from certain operators than you were in the past?

The acreage acquisition for us is primarily driven by the areas seeing the most activity. Our strategy of acquiring acres in the areas where we see the most activity, where the most rigs are, tends to draw us to the areas that have been very clearly delineated as in the play and where the new rigs are headed towards. So with that being said, we have seen our areas of acquisition push out farther to the west, just to the north and just to the south of the river in Williams and McKenzie. We have seen some fantastic wells out there.

We are very fortunate to participate with Whiting in the Tarpon Federal well, which is a new record for the Bakken; 7,000-barrel BOEIP. And we have got a reasonable acreage position within fairly close proximity to that well. So you will generally see us continue to push out into areas where we see the most activity, given the fact that we are looking for those shorter fuse type of lease acquisition opportunities.

So as far as operators, it's across the board. The usual suspects that you will see drilling wells out to the west. But that's where the opportunity for us will reside, both to the west, as we push out towards the Montana border and then to the south. I think that we're fairly excited about the Whiting, Lewis and Clark area. Whiting has a very substantial, excellent position down there. And we have been acquiring acreage that we continue to find down there. As well as what we have seen from OXY. OXY has been a great addition to the Basin. They are becoming very aggressive and tuned in on this stuff with their acquisition of Anschutz. And we are happy to participate in additional wells and acquire additional acreage, primarily in Dunn county, in their area of activity.

That's a couple I would mention. But generally, where you see the rigs going, is where we will be following close behind.

Okay. And do you have any guidance for us for G&A expense for fourth quarter and looking into 2012?

G&A expense, fourth quarter, should be similar to the third quarter of 2011. We generally think that 2012 G&A guidance, on a whole year basis, will increase by about 15% to 20%. Part of that is due to increasing headcount here. We have added, as you can see, a couple of key people that help us go forward, both on the back office side, as well as the land side. So I think a rule of thumb is we should see G&A increase 15% to 20% on a total year basis for 2012. And quarter-over-quarter here, Q3 to Q4, should be fairly similar.

And what is your current headcount now and how does that compare over the last few quarters?

Our headcount here now is 18, and that's up from, I think, 11 at the start of the year. So we have been adding some assets here on the land side, on the back office side, accounting side, as well as in the executive level, with the addition of Tom Stoelk. We are backfilling in our capabilities here and moving some more of the activities that we had outsourced, in house, and just a natural function of growing. We really built the Company, at this point, at headcount of 18 to 20, I think we have it built to scale. I think you won't see significant increase in headcount, really from here on out. I think we sort of staffed up to the next level of growth that we'll see, as we get into 2012.

Okay. And one last question. Have you done any share buybacks as of today?

We have not executed any buybacks under our plan in the third quarter. We remain prepared and financially able to buy back stock,if we determine it's the appropriate use of capital versus the additional acquisition of acreage. And we will continue to deploy our capital to where we think the best opportunities are.

Thanks, Mike.

And our next question comes from Marcus Talbert, Canaccord Genuity.

Hi, guys. Good morning.

Good morning, Marcus.

I was just wondering, you touched on the number of wells expected to be hooked up -- or that at least the gas hooked up to the lines next year, and there's been some very positive commentary from some of the other operators in the trend. Given your partnership with Slawson in several areas here, do you have any read through, in terms of how many wells he may have hooked up to gas or his plans for building out that infrastructure as we move forward?

Yes, thanks, Marcus. This is Mike. The entire peninsula there in southern Mountrail county, where we have focused our activity with Slawson, has been 100% hooked up by Whiting as the infrastructure partner. That was a joint venture that was done between Slawson and Whiting about a year and a half ago. And now wells that are coming on, especially these new big wells that we've seen, as we have now almost fully developed with -- from a one well per unit basis, that peninsula. Each new well coming on now is immediately hooked up to gas. So it's meaningful and material to us.

Okay. Great. And you touched briefly on the Tarpon well there. I don't know the exact math on it, but I thought you might have had around 800 net barrels to your interest. Do you have any color on where you might have exited October at, given this ramp and acceleration in some of the higher working interest wells that were spud here recently?

Yes, Marcus, we are not positive on where we have exited October. It's such a volatile number, with such a high number of wells on the drilling and completing list. As you can look at, just for example, at the Tarpon, you are right in calculating that well at 7,000 BOE, multiply that by our working interest, and you can see just the swing of two or three days on that is meaningful to our exit rate. And so we don't have October exit rate available to us yet. But once we are able to come out and update 2012 guidance and CapEx, which we'll do before the end of the year, we will be able to add some more of those numbers in there as well.

Okay. Good and you will -- I'm sure you will come out with a lease number, in terms of a ballpark for next year, as well. There's been a couple of the larger operators in the trend that have looked about possibly scaling back activity. There are any areas in the play right now where you feel you could be more effective, in terms of leasing? Or at least in terms of the magnitude of the size of acres that you are leasing?

Well, like I said earlier, and this is Ryan, we continue to follow the activity. And some of the announcements that you have seen, specifically of operators cutting back rigs in the play, really are those -- from those operators that have drilled through a majority of their inventory. And they are starting to convert to the down spacing mode, which is a different set of economics, given that the acreage is already held by production. So we are focusing on the areas where the development is continuing to happen and that first pass of activity and, that, again, leads us to the west and leads us to the south, in where we see the best opportunities. So, again, the scaleback in rigs by some of the larger players, it's worth looking at what their operable inventory has been reduced to. That will be the primary driver of how they are allocating rigs versus other plays.

Okay. Great. Appreciate it guys.

Thank you.

And we'll go now to Joel Musante. Oh, I apologize. It looks like he dropped out of our queue.

We'll move next to Josh Silverstein, EnereCap Partners.

Good morning, guys. I was curious, given the weather issues that the Basin saw last year, if you are seeing your operators prepare differently going into the winter time; if they are trying to speed up some of their completion activity or if it's still status quo, as it was last year?

Thanks, Josh. This is Ryan. Definitely we see an increase in completion activity as we approach the cold weather season here. But every year, the operators get better and more efficient at this, the infrastructure gets built up. There are certain things that will just be a given in the winter, which is that completions will be more expensive, and they will be more sporadic. The thing that we hope to see this winter is the mitigation of some of the production-related issues that we saw last winter. And that hopefully will be accomplished by more field level infrastructure.

As in the past, we typically try to -- we typically see an acceleration of completion activity during the months of October, November, and into December, when the snow flies, primarily to save money and we hope that we will see this year. Again, the Williston Basin will be subject to fluctuations in weather on both the completion and the production side. It's a matter of what the infrastructure investments have been able to accomplish this year and how bad the winter is. And that will remain to be seen.

Got you, that's helpful. And then a follow-up on one of the working interest questions before. I think in one of your last updates, you were supposed to have a 76% working interest well, the Prob well with Slawson. I was curious if that was taken off the table? Or if it was flowing and what the well rate might be on that?

Thanks, Josh, this is Mike. We didn't lose any acreage on that working interest decrease. We just -- there's a repair in. There's a water repair in-right with that land. So we decreased our working interest in that to 50%, just because we didn't want to be held in suspense on that production.

Got you. That's it for me.

Thanks, Josh.

And we'll take our next question now from Phillip Jungworth with BMO Capital Markets.

Good morning, guys. Looking at the number of net wells you expect to spud in the fourth quarter, and then comparing that to the number of wells expected to be online, implies about another eight or so net well increase in wells waiting on completion. What do you think you can start to see this number -- or number decline, wells waiting on completion?

Yes, thanks. This is Ryan speaking. The increase in the D&C list is really a function of increasing drilling, in other words, we are drilling more wells at a faster pace. We are seeing the position continue to be developed faster and faster. So we look at the backlog accumulated in that list really as a positive thing, from the standpoint that we have got more wells spudding more rapidly than are being completed. So really when you start to see that mitigate is -- as we come around to the back side of crossing over that 50% threshold and held by production acreage -- but as long as we see that number continue to build, we think it is a positive thing.

So I think it will certainly stay the same throughout the next two quarters coming into the winter. We will probably see it decline, to some extent, in the second quarter of 2012, as we see the warm weather again return to the Basin. And if the drilling activity continues to be as robust as it is now, again, we will see it start to build as we come into next winter. So some of it will be driven by seasonal issues. But we look at it as a positive, definitely.

Okay. So you think this is a normalized rate then, of wells waiting on completion, given the broader rig count in the Basin?

Yes, I think that we may see it dip down a little bit. It's also driven this direction by a certain number of very high working interest wells that are on that list. So some of it is a quarterly anomaly. But I think you can see that number drop back down to about 20, and see that inventory of 18 to 20 net wells waiting on completion consistently be there.

Okay. And then do you have a -- an updated exit rate forecast for production?

We still believe our exit rate will approximate 10,000 barrels a day, consistent with our previous guidance, all things remaining equal through the end of the year.

Okay. Great. Thanks guys.

Thank you very much.

And our final question will come from Jason Wangler of SunTrust.

Good morning, guys. Just curious -- thanks for the fourth quarter update for guidance. Do you still see the exit rate being 10,000 barrels a day?

Yes, we do. All things remaining equal, we still expect to exit the year at 10,000.

On your revolver, when is your next redetermination?

Our next redetermination will happen in conjunction with the end of the year. Again, we've always kept that revolver within the range of capital that we think we will use. I want to be clear that we've always felt we had the ability to raise the borrowing base significantly from where we are at. But given what we are expecting to utilize under the facility, we haven't done that. So what we'll do is announce that redetermination, again, in conjunction with our operational update and with our 2012 CapEx budget, before the end of the year.

Perfect. That's all I had. Thank you.

Thank you.

At this time, I would like to turn things back over to Management for any closing or additional remarks.

I apologize. It looks like we have one more question. Oh, that caller has dropped out of the queue. I apologize. Go ahead.

Thank you. That concludes our third quarter 2011 conference call. We appreciate everybody joining us on the call today. And thanks again for a good quarter.

And once again, ladies and gentlemen, that concludes our conference. Thank you all for your participation.