Northern Oil and Gas Management Discusses Q2 2013 Results - Earnings Call Transcript

Aug. 9.13 | About: Northern Oil (NOG)

Northern Oil and Gas (NYSEMKT:NOG)

Q2 2013 Earnings Call

August 09, 2013 10:00 am ET

Executives

Michael L. Reger - Co-Founder, Chairman and Chief Executive Officer

Thomas W. Stoelk - Chief Financial Officer and Principal Accounting Officer

Brandon R. Elliott - Executive Vice President of Corporate Development and Strategy

Analysts

Scott Hanold - RBC Capital Markets, LLC, Research Division

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

Jared Lewis - Northland Capital Markets, Research Division

Marshall Carver

Jason A. Wangler - Wunderlich Securities Inc., Research Division

Curtis Ryan Trimble - Global Hunter Securities, LLC, Research Division

Operator

Good day, and welcome to the Northern Oil and 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.

Michael L. Reger

Thank you, Mary. Good morning, ladies and gentlemen. This is Mike. We're happy to welcome you to the Second Quarter 2013 Earnings Call for Northern Oil and Gas. With me today is Tom Stoelk, our Chief Financial Officer, who will discuss our financial highlights from the second quarter.

Before we begin this morning's call, you should be aware that certain statements made during the 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 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 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.

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 sales cycle time to approximately 120 days. Pad drilling also played a part in the increased spud to sales timing. However, the level of drilling activity in the basin was stronger in the second quarter, primarily due to pad drilling efficiencies.

Our backlog of wells, either drilling or waiting completion, expanded to 218 gross, 17.4 net wells as of June 30. In July, more net wells were added to production that we did in the entire second quarter by completing 62 gross, 6.4 net. 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 growth in the third quarter, but also in our revised 4.3 million barrels of oil equivalent production estimates for the entire year.

Acreage acquisitions continued to be strong as we were able to add approximately 4,500 acres at just over $1,000 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 infill drilling inventory, especially as our operating partners continue to touch 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 price at a premium to par yields 6.75%. The deal is priced on May 8, which is the day the high yields index dipped below 5% for the first time. This tack-on allowed us to pay our offer 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 acreage -- to continue to acquire acreage and develop our extensive drilling inventory, all alone improving our 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 division with leading operating partners in this premier oil resource play.

With that, I'm going to turn the call over to Tom Stoelk, our Chief Financial Officer, to discuss the financial highlights from the second quarter.

Thomas W. Stoelk

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 noncash 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 because of 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 production and aided by a 9% increase in realized price in a Boe basis after taking into account the effective settled derivatives. As Mike mentioned earlier, weather, road restrictions, an increased spud to sales timing for wells drilling on pads impacted second quarter production.

Our 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 as compared to a $13.72 per barrel differential in the second quarter of 2012.

During the second quarter of 2013, we had noncash mark-to-market derivative gain of $17 million and that compared to a $49.8 million noncash 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 and that compares to $7.70 per Boe in the second quarter of 2012. This 36% increase was driven by higher water hauling and disposal and workover 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 levels of workover activities on wells shut in as a result of completion activities on nearby pads. The operator uses time to do workover operations on the shut-in properties. A lot of our shut-ins were located in the Peninsula area of Mountrail County, which are lots of completion activity. Our 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 6 net wells shut in for a portion of the second quarter in the Mountrail County area alone.

Our production taxes totaled $7.6 million in the second quarter of 2013. That compares to $6.67 million in the second quarter of 2012. As a percentage of oil and gas revenues, production tax rates were flat at 9.5% in the second quarters of both 2012 and 2013.

General 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 administrative costs during the second quarter of 2013 was $3.95 per Boe and that's down 15% versus the prior quarter. The decrease in aggregate dollars between the second quarter of '13 versus the second quarter of 2012 was primarily due to decreased compensation costs.

Depletion, depreciation, amortization and accretion, or DD&A, was $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. That compares to a $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 the 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 $0.5 million in the second quarter of 2013 to reflect the impact on our previously reported deferred tax liabilities. The decrease in state tax rates is expected to lower our effect against income tax rate to something closer to 38.2% during the second half of 2013.

During the second quarter of 2013, capital spending totaled $101.5 million, which places our first half capital spending at $201.9 million. Our total capital spending 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 another capital expenditure activities.

As we mentioned in our earnings release, during the first 6 months of 2013, we placed 15.3 net wells in the production and we currently estimate that we will add 36 total net wells in the production during 2013. Assuming our remaining drilling and completion costs per net well in the $8.8 million range, which is the estimated average AFE costs on the wells in process at June 30, we estimate we'll incur approximately $140 million of additional drilling and development costs in the second half of 2013.

At this time, we're 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 costs of approximately $8.9 million per net well. In addition, we expect to spend another $15 million on acreage and other capital expenditures. Keep in mind that our actual CapEx spending will be impacted by expenditure levels on a back level wells in process at the end of the year.

We entered 2013 with a backlog of approximately 12.4 net wells in process and at June 30, this number had increased to 17.4 net wells. We continue to layer and hedge this opportunistically as the market warrants to increase the 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 this 2013 hedging is done with costless collars with an average floor of $90 per barrel and an 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'd hedge approximately 4,400 barrels of oil per day. The majority of the 2015 hedges are crude oil swaps at an average price of $89 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 2.1x, we believe we have ample liquidity to continue to develop our asset base.

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

Question-and-Answer Session

Operator

[Operator Instructions] We'll take our first question from Scott Hanold with RBC.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Mike, so I mean, if we step back and look at it, it seems like production has been kind of hanging around this 11,000 barrel-a-day average for the last 4 quarters. Certainly, it sounds like it's probably a bit of a press release for you guys to -- with weather and pad drilling, and can you give us a sense of -- if you're starting to break out of that? I know it sounds like, July, you had a number of completions, can you give us a little color on where some of those are added? And if you got any sense of what were current production might be post in wells completion, that would be great.

Michael L. Reger

Scott, I would say that in the first half, as expected, we had our 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 to 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 would be pad drilling, part of that would be better weather in the second half, typically. The 2 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. So the wells that contribute to our production in Southern Mountrail, for the most part were shut-in proportions 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, and as you know, with another 218 wells currently drilling or completing plus completing about 62 wells in July alone, that puts us over 1,500 producing wells. So it's 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've got about a 45-day window where we end up seeing what the month production really looked like. So it's hard for us to give a number right now, but we do believe that the sequential production growth has resumed here, especially given the robust completion activity in July.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Yes, no, I appreciate that and certainly, I understand the weather is kind of challenging. And I just wanted to get sort of a feel if you're going to see a break out, and that's good to see those well comps creep up. I guess, the point I was kind of making is that your net well comp has increased over the last year by a fair amount and just the production hasn't broken out, so if I look at some of those like Southern Mountrail wells that were shut in, that were brought online -- I mean, I'm sorry, if I missed this, but did you give your net count that it was to you all and did you know what roughly production just from that group of wells was?

Thomas W. Stoelk

Well, we said in the script that we had about 6 net wells in Mountrail alone. And high-loss production is kind of what you're getting at, and I'd place it at about 150 barrels of oil equivalent for the quarter kind of in our total average, Scott.

Scott Hanold - RBC Capital Markets, LLC, Research Division

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

Thomas W. Stoelk

No. I mean, unless we have some acquisition activity -- I mean, currently, at 36 estimated, we pegged it at about $8.9 million kind of on average. You did add the numbers up right roughly, about $372 million. The only thing I added at the very last sentence when I was kind of going through the CapEx, was that a little bit of it depends on the pace of development and kind of where are wells and process or our backlog is. We came into the year with about 12.4, we estimate that it will go down from our existing levels, so maybe 17.4, not exactly sure whether it'll be 12, 14, kind of what will be in process, so we will incur some capital costs for wells that we won't complete in 2013 that'll 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 when you're...

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay. So -- just so I understand that if you have -- if there's a net change of roughly, let's call it 5 wells in backlog from the beginning of the year until the end of the year, I could associate whatever the drilling costs is on those 5 wells and add it to the $372 million, is that how we should think of it?

Thomas W. Stoelk

Yes, that's how you should think of that. The only thing I would add to that is that, you can assume that if they're 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, which you were just describing, you could do, but there is some variability, depending on the composition of that backlog.

Scott Hanold - RBC Capital Markets, LLC, Research Division

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

Thomas W. Stoelk

No, I think it will actually be a little bit lower than that. We based on the percentage completion of the composition really at 6 30. So I think it's lower than that.

Brandon R. Elliott

Yes, Scott, we're assuming that the D&C list -- this is Brandon -- that the D&C list at the beginning of the year, at the end of the year are approximately equivalent. So that's how you got your original math of $372 million, and I think we're comfortable with that.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Understood, okay. And then one last one, well cost averaging this year $8.8 million, $8.9 million, that's a little bit higher than I think the low to mid-8s that you're targeting especially towards the end of the year, can you give us a little bit of color on what you're seeing there?

Michael L. Reger

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

Operator

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

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

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

Thomas W. Stoelk

Yes, I think that this quarter, obviously, we got a couple of factors. We mentioned them in the script. One was kind of the water hauling and disposal charges, and I gave a little bit of color on that, as well as the workover expenses. Let me talk about the workover expenses first. A lot of those were incurred in Mountrail, where our working interest averages are 2x, 3x what 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 probably peg that number in 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 workover expenses. So I do think that you'll 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 in North Dakota where we have a higher working interest percentage. In those areas, they're developing infrastructure that should lower the cost, but it's kind of a work in process, and while I think that over the long term, those costs will trend lower and I think over the immediate term, it's going to cost our LOEs to remain a little bit higher. If you'll recall at the beginning of the year, we kind of pegged an estimate I believe of around $8.50 per barrel of oil equivalent. Right now, I'm probably thinking more in the mid-9s with respect to the production expenses per Boe, if that's helpful.

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

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

Michael L. Reger

I think that right now, there are only a handful of non-op packages that are 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 work well proposals and AFEs. So that's how we've been organically growing our acreage position. And that's, obviously, going to come at a different price, more of the wholesale type price than some of these marketed packages. There are a handful of packages out there. We're looking at all of them, but there's nothing specifically that we're looking at. I know the one you're referring to and it's interesting, but it's nothing that we're currently focused on.

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

Sure, and then one final one for me, detail oriented, so I may need to follow up back to the call, but can you just remind me if you recall what your working interest is in the Lillibridge, West and East pads? Looks like some pretty good results from another operator recently.

Michael L. Reger

Yes, why don't we take that one offline, and we can walk through specific wells. That's not something, I think, we want to get into on the call because we've got 1,500 wells out there. If you want to talk about any specific field or area, you have to get into that. But we've got -- I would say that, if you want some color on where some of the wells we've got are, where the higher working interests are, it's going to be typically in that Southern Mountrail area with EOG and Slawson and that's where, in the quarter, we had a lot of completion activity. Or subsequent to the end of the quarter, we had a lot of completion activity, and it's also where a lot of our wells were shut in, but then also reworked, but then also brought back on in July. So that's probably the color you really need, but happy to talk about any specific well or field offline.

Operator

And we'll take our next question from Jared Lewis with Northland Securities.

Jared Lewis - Northland Capital Markets, Research Division

I wonder if maybe you could give a little color on the -- maybe the geography, if there was a difference from the wells that have -- came on, say, past 12 months versus where you're seeing the wells that were completed in July and where you're going and if there's any -- you're seeing any difference in the well performance that might be being reflected in the production?

Michael L. Reger

Right. Well, here's the answer to that. And it really kind of gets to the net wells that were added in 2012 as compared to the net wells that we're adding here in 2013. So couple of factors that are 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 where Northern -- where the substantial core acreage position. Really, the rigs were out working west of the Nesson anticline, north and south, et cetera. And so, the net wells that we added in 2012 didn't have the same potency, if you will, of the wells we are adding in 2009, '10 and '11. As we entered 2013, the rigs very noticeably moved back into the core. And then the other bit of data that I would say is that in 2012, we farmed in to a handful of wells in Divide County that really didn't add to production like our typical net well would. So there were 2 events that were happening in 2012 from a net well add standpoint in relation to the production that it would come with those wells is that, we farmed in some acreage and we farmed in some wells in Divide County, which -- that's 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 to production like our typical net well does. And then, again, the rigs were noticeably absent in the core during 2012. So as we've entered into 2013 here, the net wells that we're adding -- I would say that our net well lists, our drilling and completion lists, 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 the Anticline. So we believe our 2013 net well adds will be more -- they would resemble more of the 2010 and 2011 net well adds, and then 2012, we're looking at it as kind of a unique year, given that we added somewhere in the neighborhood of about 5 to 6 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. And 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. So -- now that's some important color that you should know, and we think that the 2013 net well adds will be as potent or more than the adds that we had added, the net wells that we added in 2010 and 2011. So I'm not sure if that's clear enough, but I just wanted to give you some color on that.

Jared Lewis - Northland Capital Markets, Research Division

No, no, that's very helpful. That's good color. I appreciate it. And then just real quick final on the -- just the land in North Dakota held by production, it's being kind of steady around the 7% range. Do you see that -- I mean, I guess, what do you see with that, that kind of the remaining acreage that's not currently held by production?

Michael L. Reger

You know what we did -- the data points that we've given you in the past, we've added -- there are specific categories that, that acreage falls into. It's developed, it's held by production, held by operations and then in the past, we always added our permitted. Our permitted list is becoming so vast that it's 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 that we're receiving on a daily basis here at Northern, that number is big, but we're going to stick with, from now on, purely just to held by production data from developed, held by production and held by operations.

Operator

We'll take our next question from Marshall Carver with Heikkinen Energy Advisors.

Marshall Carver

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

Thomas W. Stoelk

I think it's going to be about $9.50, I should clarify that and follow that.

Marshall Carver

Okay, no problem. And EOG seems like they're 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?

Michael L. Reger

I think if you look at our presentation that we -- our public PowerPoint presentation, we've typically given a percentage of total net wells that were exposed to with EOG, and that's probably in the 8% range right now of our total net wells that are company-wide that are exposed to EOG. And as we continue to add new units with EOG, that entire -- that acreage position we hold at EOG, that will remain somewhat stable as far as from infill drilling standpoint. EOG, as you know, is a very innovative operator and we're monitoring some of the things that they're doing and why they're doing, Continental is doing and others are doing from a stand volume, standpoint, et cetera. So we're excited to see innovation continue.

Marshall Carver

Do you think -- is this year's program probably more than that 8%? Or is it still about 8% with EOG?

Michael L. Reger

I would say that's about the same.

Marshall Carver

Okay. The explorations in next few quarters, how many acres do you think you might lose to explorations, say, between now and year end? It seems like you're adding acreage, but you're also losing some -- I imagine you're losing the lesser quality acres so versus the ones you're getting, but could you help -- how many acres are exposed to exploration between now and year end and over the next year?

Michael L. Reger

Right. I would say that in Q3 and Q4 -- I have the numbers here in front of me. We've got about -- in Q3, we've got about 5,000 acres that are exposed to exploration that could potentially expire if they're 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 areas with mutual interest with Slawson. So that doesn't give us much concern at all. I think we have Slawson as one of our most efficient and effective partners that we're very comfortable with their drilling schedule out there. They got a rig actively working in our Big Sky AMI. So they'll hit the units that we certainly want to hold. We owned the acreage jointly with Slawson and the AMI. So it's not as if our acreage is expiring and theirs isn't. We acquired this acreage together. So Slawson's driving the bus out there. They're doing a great job. So -- but 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 in a -- company-wide that could potentially expire. So very limited expiration from here on out. The only expiration pressure we're going to have is coming from Richland County and the Slawson AMI.

Marshall Carver

And one final question. You mentioned 6 net wells in Mountrail, what is -- was that the number of wells currently in backlog there in Mountrail? I didn't -- I just didn't get what that was in reference to, the 6 net wells?

Michael L. Reger

What Tom referred to in his script was, we have 6 net wells that at some point, during the second quarter, had been shut in due to work over or have been shut in due to pads being completed adjacent to those units. And that, as you know, we have a significant portion of our net well count in Southern Mountrail, on that peninsula. And so, when Slawson brings in the frac crews, they're going to be shutting in a lot of our wells there.

Operator

And we'll take our next question from Jason Wangler with Wunderlich Securities.

Jason A. Wangler - Wunderlich Securities Inc., Research Division

Just curious as far as you talked about the pad drilling and it seems like the whole base is shifting that way, do you have a sense for your inventory or even your going forward kind of a breakdown, I guess, on a percentage basis of what you're seeing on the pad drilling side?

Michael L. Reger

Yes, I would say that currently, about 80% of our drilling activity is on a pad with at least 2 wells planned. And as you know, most of the wells are at least 4, but I would say that just to give you a good data point, 80% are on pads with at least 2 wells planned.

Jason A. Wangler - Wunderlich Securities Inc., Research Division

Okay. That's helpful, Mike. And then just from the liquidity perspective, obviously, you got the line on it undrawn, just curious when the next redetermination is there and what your thoughts are going with that?

Thomas W. Stoelk

The next scheduled redetermination is October 1 plus going in to that is -- we'll take a look, it's difficult for us based on the bill of our reserved value to request borrowing base increases so, we'll take a hard look at that really at that time. I think we're in good shape with respect to it and finalizing reserves for that, so we'll take a hard look at it. But don't necessarily need the liquidity, but it might be something that we ask for even though we don't need it.

Operator

And we'll take our last question from Curtis Trimble with Global Hunter.

Curtis Ryan Trimble - Global Hunter Securities, LLC, Research Division

I was hoping maybe to chat little bit about kind of AFE flows and maybe get a little bit of characteristics of what's kicking out of your model in terms of AFEs, and maybe why it's kicking out in terms of drill, complete costs or too far field of projected LOE, et cetera?

Michael L. Reger

Curtis, we're going through our data here. The wells at the end of July, on July 31, we had about 218 wells that had come in, that were on our D&C list, and the -- so 16.7 net of that at an average working interest of about 7.6%. The total spuds in July were 62 so about 2 a day spud. I'm just trying to give you as much color as I can see here, but our AFE activity in the volume that we're seeing are -- it's still robust and the beauty of pad drilling efficiency is we'll get, in some cases on the same pad, we'll get 4 AFEs in the same envelope. So it continues to be robust.

Thomas W. Stoelk

And they range in the amounts, really, over the last 3 months, AFEs that we come in the door of average somewhere between kind of a range of $6.9 million and $9.9 million, depending on the location. As to whether at McKenzie, typically, running at the higher end of that range.

Curtis Ryan Trimble - Global Hunter Securities, LLC, Research Division

Sure, just because of depth?

Thomas W. Stoelk

Yes.

Curtis Ryan Trimble - Global Hunter Securities, LLC, Research Division

In terms of ones that don't need your economic criteria, can you tell me what component of the AFE generally is restrictive, whether it's just the completion costs or some other component?

Thomas W. Stoelk

It's usually just -- it's total. I'm not sure it's restrictive when we go through our economic analysis on it we're having in it. Our engineering department take a look at the IRRs. So it's looking at offsetting production and using analogy and other factors like that. But the majority, I think, of the AFEs that we non-consent are really driven by 2 higher cost, based on what we estimate the EURs are on it. So it isn't -- there isn't really a component that I could point to and say, well we think the completion costs 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 the IRR or rate of return on it.

Operator

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.

Michael L. Reger

Thanks, Mary. Thank you, everybody, for your participation in this call and your interest in our company. Mary will 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.

Operator

And that does conclude our conference. Thank you for your participation.

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