WAYZATA Aug 7, 2015 (Thomson StreetEvents) -- Edited Transcript of Northern Oil and Gas Inc earnings conference call or presentation Thursday, August 6, 2015 at 3:00:00pm GMT TEXT version of Transcript ================================================================================ Corporate Participants ================================================================================ * Mike Reger Northern Oil & Gas, Inc. - Chairman, CEO * Brandon Elliott Northern Oil & Gas, Inc. - EVP Corporate Development & Strategy * Tom Stoelk Northern Oil & Gas, Inc. - CFO ================================================================================ Conference Call Participants ================================================================================ * Scott Hanold RBC Capital Markets - Analyst * Neal Dingmann SunTrust Robinson Humphrey - Analyst * Sameer Uplenchwar GMP Securities - Analyst * Adam Leight RBC Capital Markets - Analyst * Phillips Johnston Capital One Southcoast, Inc. - Analyst ================================================================================ Presentation -------------------------------------------------------------------------------- Operator [1] -------------------------------------------------------------------------------- Good day, ladies and gentlemen and welcome to the Northern Oil and Gas second-quarter 2015 conference call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session and instructions will follow at that time. (Operator Instructions). As a reminder, this conference call is being record. I would now like to introduce your host for todays conference Brandon Elliott, Executive Vice President of Corporate Development and Strategy. Please go ahead. -------------------------------------------------------------------------------- Brandon Elliott, Northern Oil & Gas, Inc. - EVP Corporate Development & Strategy [2] -------------------------------------------------------------------------------- Thanks Ashley. Good morning everyone. This is Brandon. We are happy to welcome you to Northerns second-quarter 2015 earnings call. I will read our Safe Harbor language and then turn the call over to Mike Reger, our Chairman and Chief Executive Officer for his opening comments; and then to Tom Stoelk, our Chief Financial Officer will walk you through the financial results for the quarter. Please be advised that our remarks today, including the answers to your questions, may include forward-looking statements within the meaning of the Private Securities Litigation Reform Act. These forward-looking statements are subject to risks and uncertainties that could cause actual results to be materially different from the expectations contemplated by these forward-looking statements. Those risks include, among others, matters that we have described in our earnings release as well as in our filings with the SEC, including our Annual Report on Form 10-K and our Quarterly Reports on Form 10-Q. We disclaim any obligation to update these forward-looking statements. During this conference call, we will also make references to certain non-GAAP financial measures, including adjusted net income and adjusted EBITDA. Reconciliations of these measures to the closest GAAP measures can be found in the earnings release that we issued last night. With the disclosures out of the way, I will turn the call over to Mike. -------------------------------------------------------------------------------- Mike Reger, Northern Oil & Gas, Inc. - Chairman, CEO [3] -------------------------------------------------------------------------------- Thanks Brandon. Good morning and thanks for joining our call today. Today I'll start off with how the years is played out so far for Northern, how this is setting us up for the remainder of the year and then I will share a few thoughts on how we're thinking about 2016. So far 2015 is playing out according to plan. Our guidance remains intact and approximately 80% of our expected oil production in 2015 is hedged to roughly $90 per barrel. So we have mitigated most of the cash flow volatility in 2015 that would come with a lower commodity price environment. As a result of strong completion activity and higher well productivity in the first half of the year, our production is running slightly higher than we originally anticipated. Specifically second-quarter production came in above our forecast as per well productivity of the new well additions increase due to our operating partners high grading their drilling activity in the core to play. Capital expenditures have been trending basically in line with our expectations. Year-to-date capital expenditures have been roughly $78 million of our $140 million budget. Based on our expectations for net well additions in the second half of the year, we continue to believe that we are on course to meet this CapEx guidance. Operationally we have added 13.5 net wells the production so far this year. While in a normal year, we would expect 40% of net well additions to come in the first half of the year we are expecting the opposite effect this year with 60% of our estimated 20 net well additions completed in the first half of the year. As of June 30, we had 10.8 net wells in process on our drilling and completion list and we expect to add approximately 6.5 of those net wells to production in the remainder of the year and some of our operators are delaying completion until late in the year or until early 2016. Now turning to liquidity. Tom will be providing additional color, but suffice to say we will have -- we have been steadfast in our focus to preserve and even enhance liquidity when the opportunity presents itself. In May as oil prices improved and the capital markets opened, we lost a $200 million senior unsecured bond offering which we priced close to par at [95]. This allowed us to pay down our bank facility giving us a liquidity position at the end of the quarter of approximately $370 million. In addition to the bond offering, we were able to layer in new hedges. During the second quarter, we took advantage of the brief increase in oil prices to lock in a portion of our production in the back half of 2016 with $65 WTI swaps. As a reminder we have almost 2 million barrels of oil hedged for the remainder of this year at approximately $90 per barrel which again is approximately 80% of our anticipated oil production for the second half. And in another 900,000 barrels of oil hedged in the first half of 2016 also at $90 per barrel. That gives us nearly 3 million barrels of oil hedged at $90 for the next four quarters. Moving forward, we will remain disciplined and continue to look at our business to the lengths of the capital efficiency and liquidity. The actions we took in the second quarter combined with our enviable hedged position for the remainder of 2015 and 2016 set us up well the whether the current commodity price environment. As the largest non-operator in the Williston Basin, it is important to recognize that Northern's business model allows us to focus our attention and capital only on those wells that meet or exceed our internal rate of return thresholds. For every well proposal we receive, we essentially run our economics on the three-year WTI oil strip, which would naturally be consistent with the pricing of hedges we could lock in simultaneously. In the first half of the year, we elected to participate and approximately 72% of the well proposals we received up from approximately 25% in November and December of 2014. There were two main reasons driving the increase in consented well proposals -- lower drilling costs and bigger wells. Our average drilling complete cost on the well proposals that we elected to in the second quarter was $7.3 million down from an average of $9.2 million in 2014. The remaining rigs in the field are situated in the core of the play where we have over 10 years of drilling inventory and where the estimated ultimate recovery for wells is significantly higher resulting in greater per well productivity. These per well productivity improvements will help to mitigate production declines in the second half of the year. As a result, we are confident in our original production guidance that calls for flat overall 2015 production versus 2014. Lastly, I would like to touch on how we plan to manage the business as we look into 2016. As always we will continue to demonstrate capital discipline. As such regardless of the commodity price, we will continue to participate in those wells that give our shareholders a high rate of return. In a similar commodity price environment, we expect to live within cash flow in 2016. And with similar rig activity in the basin in 2016, we would expect to participate and add to production approximately 15 net wells next year. Depending on the timing of those additions, this number of wells should hold production relatively flat in 2016. With that, I will turn the call over to Tom to discuss the specific highlights from the second quarter. -------------------------------------------------------------------------------- Tom Stoelk, Northern Oil & Gas, Inc. - CFO [4] -------------------------------------------------------------------------------- Thanks, Mike. Today, I'm going to cover some of the financial highlights for the second quarter and provide some commentary on our liquidity and capital expenditures. Adjusted net income from the second quarter 2015 was $11.5 million or $0.19 per diluted share. Adjusted EBITDA for the second quarter was $70.4 million. Both of these amounts were impacted during this quarter by local crude oil, natural gas and NGL prices. Production was up 8% year-over-year. The second quarter production averaging 16,610 barrels of oil equivalent per day. The year-over-year production growth was primarily driven by the improved economics and recoveries on the 34 net wells added to production over the last 12 months. As Mike mentioned earlier, we entered the year believing that well completions would be lighter in the first half and heavier in the second half as operated for weighed out service cost reductions and commodity price recovery. As it turned out, we added 13.5 net wells to production during the first half putting a slightly ahead of our internal production estimate for 2015. Realized price per barrel of oil equivalent after reflecting our settled derivative transactions was $62.22 per BOE for the second quarter which was down approximately 21% on a year-over-year basis. This decrease were due to low commodity prices, lower commodity prices in the same period a year ago. Our average oil differentials to NYMEX WTI benchmark was a $11.50 per barrel in the second quarter of 2015. This compared to a $12.25 per barrel in the second quarter of 2014. We recently seen an improvement in oil differentials and expected they will trend towards $10 a barrel for the second half of 2015. In the second quarter of 2015, oil, natural gas and NGL sales, which include the effect of our settled derivatives totaled $94 million which was up 4% from the first quarter of 2015. For the second quarter of 2015, we incurred a gain on settled derivatives of $31 million, compared to an $11.3 million loss for the second quarter of 2014. The gain on settled derivatives increased our average realized price per BOE by $20.50 in the second quarter of 2015. As a result of forward oil price changes, we recognize a non-cash, mark to market derivative loss of $53.2 million in the second quarter of 2015, compared with $35.3 million loss in the second quarter of 2014. Looking at expenses, our combined per unit production expenses, production taxes and G&A for the second quarter of 2015 declined by $4.52 per BOE or 22%, compared to the second quarter of 2014. When reviewing our outlook for the second half of 2015, we made adjustment to some of these expense expectations. We expect our product expense per BOE to improve to a range of between 925 to 975 per BOE. Production taxes as a percentage of oil and gas revenue should remain relatively flat with the first half of 2015 right around 11%. G&A expenses should also remain flat with the first half at approximately $3 per BOE. And lastly, our outlook for DD&A in the second half is slightly under $25 per barrel of oil equivalent. Drilling activities slowed in the basin resulting a decline in our wells in process from 22.7 net wells in process at the end of 2004 to 10.8 net wells at the end of this quarter. Approximately 30% of those in process wells are not expected to be completed until late in 2015 or early 2016 as those operators are evaluating well performance on drilling and completion designs. As a result, we believe the completions in the second half of 2015 will be lower and what we experienced so far this year and we're leaving our full-year 2015 production guidance unchanged. The decline in drilling activity and commodity prices continue to lower drilling costs. During the second quarter of 2015, with weighted average authorization for expenditure on the cost per wells we elected to participate in was $7.3 million that was about 21% compared to the $9.2 million average we saw in 2014. Our capital expenditures during the quarter totaled $33.3 million. A breakdown of that total is as follows. Approximately $30.3 million of drilling and completion capital which includes capitalized work over expenses, $2.1 million on acreage and other acquisition activities and $900,000 of capitalized interest and capitalized cost. As mentioned in our earnings release, we believe we're still on pace to meet or slightly estimated $140 million capital budget for 2015. Turning to liquidity, we took steps to enhance our position in the second quarter, but showing an additional $200 million of senior notes due in 2020. The proceeds from these notes were used to pay down our revolving credit facility. As a result, we had $188 million of borrowings on our credit facility at June 30, 2015 providing us with $362 million of borrowing base availability. With another $7 million of cash on hand the company had available liquidity of approximately $370 million at the end of the quarter. We remained well-positioned from a liquidity and debt maturity perspective to do at lower prices and we maintained a strong hedging position. As a reminder, we have a total of approximately 2.9 million barrels of oil hedged was swapped and average price were approximately $90 per barrel over the next four quarters. After that, we have an additional 900,000 barrels hedged with swapped and average price of $65 per barrel in the second half of 2016. That significant amount of hedging is extremely valuable in the current pricing environment and helps us protect our balance sheet. Our asset base is substantially held by production and its located in areas with some of the lower breakeven economics the US. As an non-operator Northern, has extensive control over capital spending because we have the ability to participate on a well-by-well basis that provides us with the ability to be more selective in the allocation of capital to the highest rate of return project without the burden of contractual drilling commitments, large operational and larger administrative staffs rather than constructions concerns. Given the uncertainty around future oil prices, we are continuing to take aggressive steps to protect our balance sheet. By maintaining capital discipline, we continue to work hard to build resilience given the uncertainty of how long the low price environment will last. By reducing commitment levels and enhancing our liquidity, we are navigating the low price environments and at the same time preparing ourselves for future opportunities and value creations. At this time, I'd like to turn it back over to the operator for question-and-answer. Operator, if you could please give the instructions for Q&A. ================================================================================ Questions and Answers -------------------------------------------------------------------------------- Operator [1] -------------------------------------------------------------------------------- Thank you. (Operator Instructions) Our first question comes from Scott Hanold of RBC Capital Markets. Your line is open. -------------------------------------------------------------------------------- Scott Hanold, RBC Capital Markets - Analyst [2] -------------------------------------------------------------------------------- Thanks. Good morning, guys. -------------------------------------------------------------------------------- Tom Stoelk, Northern Oil & Gas, Inc. - CFO [3] -------------------------------------------------------------------------------- Good morning, Scott. -------------------------------------------------------------------------------- Scott Hanold, RBC Capital Markets - Analyst [4] -------------------------------------------------------------------------------- Mike, if you could go a step back and just again give us your views on how you take a look at the well proposals deciding to elect or non-elect in them in this oil price environment obviously with productivity increasing and cost coming down more these walls may make your hurdle rate as thing focused on the [core operative]. If we get into 2016 and you're seeing improved economics, but still a modest oil price recovery. How do you balance between AFE is meeting that threshold versus trying to keep the balance sheet where you wanted to be? -------------------------------------------------------------------------------- Mike Reger, Northern Oil & Gas, Inc. - Chairman, CEO [5] -------------------------------------------------------------------------------- I think the process that were using essentially solves for all scenarios. Each time we receive a well proposal, we're going to run our internal price tag on the three-year strip, which is getting us fairly accurate prediction of kind of where we're going to be with the assumption that were going to continue to layer and hedges as we go. And as you know in the first half of 2016, we were running economics in the low 60s because there was a certain amount of Contango in the future's curve for the next three years as we've just mentioned we were able to then layer and 65 WTI swaps in the back half of 2016 and will continue later in hedges, essentially opportunistically. The way we're looking at if you just want to quantify it and Scott you and have done this in the past, you kind of look at the number of rigs that are in the field you look at how many wells each rig can drill per year use -- assume that Northern is generally can be in about 25% of the wells that are drilled in the field. You can pretty quickly come to around that 15 to 20 net well range as far as activity goes. That map works itself out pretty accurately. The way we're seeing is if the rig count stays that around 75 is pretty clear how much activity we're going to be seeing for the rest of 2015 and then going into 2016. If you just assume all things remain equal. So we feel really good about our estimates and our thoughts and just the bottom line is commodity prices improve, rig counts increase obviously our activity levels are going to increase. However cash flow continue to increase and will basically grow with the field. But we're really in a good spot as far as deciding on estimating were were going to land from a CapEx and cash flow standpoint. And again as always Northern is an IRR-driven shop. We don't we don't have any opinions about oil here. We look at the returns on each and every individual well. And as an operator as each well comes in, we get to decide specifically whether we deploy capital to that project or not. -------------------------------------------------------------------------------- Scott Hanold, RBC Capital Markets - Analyst [6] -------------------------------------------------------------------------------- Yes, just to clarify something you had mentioned about looking at layering in hedges for wells (inaudible), is that more conceptually or is that what we should expect as you continue to obviously go into -- in the 2016 is that you will later on hedges as you add these at this [script] as the wells (inaudible)? -------------------------------------------------------------------------------- Mike Reger, Northern Oil & Gas, Inc. - Chairman, CEO [7] -------------------------------------------------------------------------------- I think the answer is yes and more specifically just incrementally. If you look at Northerns behavior over the last probably five, six, seven years. Weve usually been hedged out about we typically been hedged out about two years. And so we will continue to layer in hedges as we move on through the year. If you look back based on the current commodity prices, youre going to see the corresponding amount of activity in the field and so it correlates very nicely with commodity prices, if oil prices stay in the 40s, low-40s for the next year. So you're going to see activity levels continue to go down. And so you will see CapEx continue to go down. And therefore we won't have the same needs to hedges much. However we will continue to layer in incrementally which we always have to keep about a two-year hedged book. Right now, were hedged through -- weve got a pretty substantial hedged book that goes through December of 2016. So we feel really good about it. -------------------------------------------------------------------------------- Scott Hanold, RBC Capital Markets - Analyst [8] -------------------------------------------------------------------------------- Okay understood. And one of the other things that you all have done pretty well over the last few years is the acreage capture opportunities and there have been some larger operators in the core the base that had indicated that they monetize some of their non-operated activity to tighten up their budgets. Are you all seeing any of that occurring and have you participated in any of it? -------------------------------------------------------------------------------- Mike Reger, Northern Oil & Gas, Inc. - Chairman, CEO [9] -------------------------------------------------------------------------------- You know we're seeing a lot of different opportunities. What we do best Northern, as you know is we see a lot of the really potent smaller opportunities where we're picking 100 acres here or there to come with other existing production or immediate drilling activity. We see a lot of that stuff. We operate really well in that environment. Were starting to see more and more of the larger packages, but I'll just reiterate that as far as Northern is concerned, were very comfortable with our liquidity position. And from our standpoint, we're going continue to be very patient as it relates to the larger acquisitions in the light of just protecting our precious liquidity cushion. -------------------------------------------------------------------------------- Scott Hanold, RBC Capital Markets - Analyst [10] -------------------------------------------------------------------------------- Okay thanks and maybe one last one for Tom on the liquidity front. Can you discuss know what you anticipate from the next basically [firm redetermination]? -------------------------------------------------------------------------------- Tom Stoelk, Northern Oil & Gas, Inc. - CFO [11] -------------------------------------------------------------------------------- You know we're not really expecting any significant movements to be honest with you. We are expecting and thanks we're going to lower their price tags from what we saw on the spring this fall but I think offsetting that at least in our cases is larger reserves, better reserves the reduced completion cost and in the improving differentials I think at least in our individual situation more than mitigate that. So I'm not expecting much. Nothing significant, Scott. -------------------------------------------------------------------------------- Scott Hanold, RBC Capital Markets - Analyst [12] -------------------------------------------------------------------------------- Appreciate it. Thanks, guys. -------------------------------------------------------------------------------- Mike Reger, Northern Oil & Gas, Inc. - Chairman, CEO [13] -------------------------------------------------------------------------------- Thanks, Scott. -------------------------------------------------------------------------------- Operator [14] -------------------------------------------------------------------------------- Thank you. Our next question comes from Neal Dingmann of SunTrust. Your line is open. -------------------------------------------------------------------------------- Neal Dingmann, SunTrust Robinson Humphrey - Analyst [15] -------------------------------------------------------------------------------- Good morning. Hey, Mike, a quick question. When you're looking at -- and I know your return continues to be a set required bogie when you're looking at these deals. I guess my thought is do you have the opportunity to take a higher working interest on some of these is again working interest continues to be about the same when you're looking inside of potential AFEs? -------------------------------------------------------------------------------- Mike Reger, Northern Oil & Gas, Inc. - Chairman, CEO [16] -------------------------------------------------------------------------------- We continue to see -- as I mentioned a lot of really potent smaller opportunities, some of them come in and some of the wells were we've seen existing -- where you have existing working interest, that actually is something that were really good at here is consolidating up our higher working interest in the wells that we are actually electing to participate in. But again Northern effectively run primarily by IRR analysis. And so if there's a well that meets our internal rate of return thresholds, it's very likely that there are other participants in that well who have more precarious balance sheet issues or liquidity issues and were able to take advantage in some of those opportunities. -------------------------------------------------------------------------------- Neal Dingmann, SunTrust Robinson Humphrey - Analyst [17] -------------------------------------------------------------------------------- Okay and then just secondly Mike when you're looking at, all the hedges that you got on right now. Any thought that there be a certain price range when you see you know what you can do additional deals that -- so I guess my thought is any thoughts about where you would monetize some of these hedges and then take them redeploy that either buying some stock back or actually you are looking at more acreage? -------------------------------------------------------------------------------- Mike Reger, Northern Oil & Gas, Inc. - Chairman, CEO [18] -------------------------------------------------------------------------------- Yes. I think weve looked at our hedges very simply and that the only reason we've ever added hedges or layered in hedges in the past few years or forever basically has been to mitigate cash flow volatility. So we don't have any intention of monetizing these hedges. These hedges are primarily or I should say 100% to mitigate cash flow volatility. -------------------------------------------------------------------------------- Tom Stoelk, Northern Oil & Gas, Inc. - CFO [19] -------------------------------------------------------------------------------- Just locking to returns that we're electing to -- -------------------------------------------------------------------------------- Mike Reger, Northern Oil & Gas, Inc. - Chairman, CEO [20] -------------------------------------------------------------------------------- Yes. -------------------------------------------------------------------------------- Neal Dingmann, SunTrust Robinson Humphrey - Analyst [21] -------------------------------------------------------------------------------- All right, thanks. -------------------------------------------------------------------------------- Tom Stoelk, Northern Oil & Gas, Inc. - CFO [22] -------------------------------------------------------------------------------- Thank you. -------------------------------------------------------------------------------- Operator [23] -------------------------------------------------------------------------------- Thank you. Our next question comes from Sameer Uplenchwar of GMP Securities. Your line is open. -------------------------------------------------------------------------------- Sameer Uplenchwar, GMP Securities - Analyst [24] -------------------------------------------------------------------------------- Thank you. Mike, on the hedging question. So what do you need to see to layer in more in the back half of 2016 going into 2017? How are you looking at it considering the AFEs and trying to manage that, right? Like how much production you are going to have in the second half of 2016 and 2017 and how are you looking at it? Could you walk a little bit? -------------------------------------------------------------------------------- Mike Reger, Northern Oil & Gas, Inc. - Chairman, CEO [25] -------------------------------------------------------------------------------- Yes, thanks for that question. We naturally just roll it as weve been going and depending on, if oil prices remain lower here, a lot of the wells that -- well proposal, we see may or may not get drilled will see a significant slowdown in AFEs. So it's really a nicely correlated system where as oil prices began to perk-up which they did, if you remember just after Easter you saw oil make a move from the low 40s -- -------------------------------------------------------------------------------- Sameer Uplenchwar, GMP Securities - Analyst [26] -------------------------------------------------------------------------------- Yes. -------------------------------------------------------------------------------- Mike Reger, Northern Oil & Gas, Inc. - Chairman, CEO [27] -------------------------------------------------------------------------------- Up to the low 60s. It obviously increased activity in the field that increase the number of wells that we're electing to participate in and we continue to -- that we began layering an additional hedges into the back half of 2016. So as we go, well just be monitoring essentially, activity will be monitoring the number of wells were electing to participate in. Obviously we've had in the last month year here weve had a pretty material drop in oil prices, which we think would again limit the number of wells that would pass our current internal rate of return threshold. And so were just going to opportunistic and layer them in almost robotically, as it relates to the wells that were electing to participate in. -------------------------------------------------------------------------------- Sameer Uplenchwar, GMP Securities - Analyst [28] -------------------------------------------------------------------------------- Got it. And then on the E&D front I mean with the oil price coming down like you said, what are you seeing out there in the field? Is the bid ask spread coming in, is it still wide like what's some color on that end would be great? -------------------------------------------------------------------------------- Mike Reger, Northern Oil & Gas, Inc. - Chairman, CEO [29] -------------------------------------------------------------------------------- You know I think were on the front edge of the bid ask spread tightening. I'll just say that that if you do the work on Northern you'll find that Northern has a really nice liquidity cushion as it relates to some of our peers. We know that there are assets out there that we would love to own, but we are going to be patient and we're going to watch this oil cycle unfold and again we're going to be very patience. We're not actively looking for big acquisitions. If we see an acquisition that is really good, we're going to be looking at that acquisition primarily through what that means for our liquidity position. -------------------------------------------------------------------------------- Sameer Uplenchwar, GMP Securities - Analyst [30] -------------------------------------------------------------------------------- Got it. Thank you. -------------------------------------------------------------------------------- Mike Reger, Northern Oil & Gas, Inc. - Chairman, CEO [31] -------------------------------------------------------------------------------- Thank you. -------------------------------------------------------------------------------- Tom Stoelk, Northern Oil & Gas, Inc. - CFO [32] -------------------------------------------------------------------------------- Thanks, Sameer. -------------------------------------------------------------------------------- Operator [33] -------------------------------------------------------------------------------- Thank you. (Operator Instructions) Our next question comes from Adam Leight of RBC Capital Markets. Your line is open. -------------------------------------------------------------------------------- Adam Leight, RBC Capital Markets - Analyst [34] -------------------------------------------------------------------------------- Hey, good morning everybody. -------------------------------------------------------------------------------- Mike Reger, Northern Oil & Gas, Inc. - Chairman, CEO [35] -------------------------------------------------------------------------------- Good morning. -------------------------------------------------------------------------------- Tom Stoelk, Northern Oil & Gas, Inc. - CFO [36] -------------------------------------------------------------------------------- Good morning, Adam. -------------------------------------------------------------------------------- Adam Leight, RBC Capital Markets - Analyst [37] -------------------------------------------------------------------------------- First question. I appreciate the color you provided around the estimating well count. Do you have any level of higher confidence in a specific set of wells that you -- I'm pretty sure will get drilled next year that are less sensitive to pricing so you can put your confidence in more than just general estimate? -------------------------------------------------------------------------------- Mike Reger, Northern Oil & Gas, Inc. - Chairman, CEO [38] -------------------------------------------------------------------------------- Yes, if you look at where the existing 75 rigs are in the field and you can see this from the North Dakota Industrial Commission website and just look at it every day and it updates it literally daily. You can see where the rigs are located. And based on the different operators and where they're actively drilling where our acreage sits within those operators field, we have a really good idea of where we are going to see our activity. And the math again it's surprisingly easy when you look at our relative activity to where the rigs are currently located. So we have -- and we have a really good idea now as the Bakken is roughly a maturely mature field. You know we're seeing these permits and AFEs come from these operators in these areas. We know what the EURs are going to be on each one of these wells. It actually makes it fairly easy for us to model with 75 rigs in a very defined bull's-eye or very defined core of the play. -------------------------------------------------------------------------------- Adam Leight, RBC Capital Markets - Analyst [39] -------------------------------------------------------------------------------- Thats great. Thanks. And sort of on the flipside of the non-consent issue, what have you seeing -- and this probably changed, but in the wells you did go non-consent. What proportion of those actually got drilled? -------------------------------------------------------------------------------- Mike Reger, Northern Oil & Gas, Inc. - Chairman, CEO [40] -------------------------------------------------------------------------------- You know it -- as I mentioned in my earlier comments in November and December, we were only electing about 25% of the well proposals that we are receiving. However, of the 75% that we non-consented, very few of those actually got drilled because it's really a delay issue. By the time the letter goes out and the 30-day period starts to come to an end, the operator has 90 days to spud that well or else they have to re-propose or rebalance the well. And so in almost -- in most cases we got a letter from the operator saying that they werent actually going to spud the well and they would re-propose those well at later date. So that's really nice from us from an inventory standpoint so we didnt missed out on any of those spuds and I think our operators are being smart about this. We are not in an acreage holding pattern here. This is -- every well that being drilled is being drilled because our best operators are drilling their highest return wells now and only their highest return wells now with a very limited number of rigs. So we're pleased with the way that this is playing out. We're pleased with our liquidity position. Our operating partners are strong and so we're excited to just to weather the storm with good operators and really good decision-making on their part. -------------------------------------------------------------------------------- Adam Leight, RBC Capital Markets - Analyst [41] -------------------------------------------------------------------------------- Okay, thats great. Sorry if I missed some components of what you said. On the differentials, to what extent is there any -- how much flex is there in the percentage differential as we see prices go down? I forgot what the component is thats related to marketing gathering costs as opposed to just revenue issue of all that price. -------------------------------------------------------------------------------- Mike Reger, Northern Oil & Gas, Inc. - Chairman, CEO [42] -------------------------------------------------------------------------------- Yes, I guess Ill just try to capture your questions with one simple answer is that a couple well -- one point Ill make is we're still in that roughly 50% pipeline, 50% rail environment. As you get into the 2016, 2017 and beyond, its going to be significantly higher from new pipeline, capacity coming on so thats going to be really positive for us starting next year. One other -- as we looked at differentials in the second quarter, differentials were coming in and approaching 10 and in some instances with certain operators into the single digits as we got into June. And so we're really optimistic that differentials will continue to tighten here, but theyve been improving over the last really last month or so two months or so. -------------------------------------------------------------------------------- Adam Leight, RBC Capital Markets - Analyst [43] -------------------------------------------------------------------------------- Thats great too. And then lastly on working capital, can you give us an updated estimate of what you think you might be seeing in working changes sources uses in the next quarters? -------------------------------------------------------------------------------- Tom Stoelk, Northern Oil & Gas, Inc. - CFO [44] -------------------------------------------------------------------------------- You know we kind of reaffirmed our $140 million budget on the cap spend and I think when you take a look at our actually cash spend for the first year -- first half, it was heavier in Q1 right around $45 million in then dropping to [33]. I think you'll probably see it trending down as you go into Q3 and trending down again if you go into Q4 probably cash spend if thats whats you're asking me is probably slightly under maybe $50 million to $60 million is kind of where I [peg it], probably little higher in Q3 little lower in Q4. -------------------------------------------------------------------------------- Adam Leight, RBC Capital Markets - Analyst [45] -------------------------------------------------------------------------------- Yes, I'm sorry, Tom, just to clarify I was asking on working capital is separate from the budgeted CapEx? -------------------------------------------------------------------------------- Tom Stoelk, Northern Oil & Gas, Inc. - CFO [46] -------------------------------------------------------------------------------- Okay. Well we ended the quarter with working capital of around $21.5 million. I think thats going to increase probably $20 million, $30 million but thats going to be highly depended on obviously the price while the timing of receives and (inaudible) and things like that. You'll continue to see improvement would be my expectation as our cash spending -- as we kind of work of that high level of wells and process so we had coming in the beginning of the year. -------------------------------------------------------------------------------- Adam Leight, RBC Capital Markets - Analyst [47] -------------------------------------------------------------------------------- Okay, I'll take the rest offline. Thanks. -------------------------------------------------------------------------------- Mike Reger, Northern Oil & Gas, Inc. - Chairman, CEO [48] -------------------------------------------------------------------------------- Okay. -------------------------------------------------------------------------------- Tom Stoelk, Northern Oil & Gas, Inc. - CFO [49] -------------------------------------------------------------------------------- Perfect. Thanks, Adam. -------------------------------------------------------------------------------- Operator [50] -------------------------------------------------------------------------------- Thank you. Our next question comes from Phillips Johnston of Capital One. Your line is open. -------------------------------------------------------------------------------- Phillips Johnston, Capital One Southcoast, Inc. - Analyst [51] -------------------------------------------------------------------------------- Yes. I just want a follow-up with Tom, just on that CapEx, that the cash versus the accruals. It did look like the increase in your liquidity was maybe about $55 million or so less than what it should have been if you just add everything up. Is that just a difference between the percentage of completion on accrual amounts on a GAAP basis versus actual cash out the door? I mean is that mainly the explanation? -------------------------------------------------------------------------------- Tom Stoelk, Northern Oil & Gas, Inc. - CFO [52] -------------------------------------------------------------------------------- Yes, effectively its just -- its really driven by the decrease in wells and process and thats whats causing kind of the higher cash expenditures versus reported capital spend. Our cash flow from those investing activities that you see reflected in the statement of cash flows relates to the actual cash spend and its not always reflective of kind of the current levels with development activity. For example if you think about, during the first six months period of this year, our capitalized cost reported were roughly around $77.9 million, but when you take a look at our cash flow the actual investing activities was about $188.3 million and the delta between that is really just as we continue to work down you know that wells and process amount. So you are going to kind of continue to see that trend down it was about $110 million in Q1. It was about $77 million, $78 million in Q2 on a cash spend. You'll continue to see that go down. And thats -- in one of the earlier responses as well as referring to. I think you'll see a spend roughly around $60 million in cash spend, if you're trying to zero in on where you think you're going end on the revolver. -------------------------------------------------------------------------------- Phillips Johnston, Capital One Southcoast, Inc. - Analyst [53] -------------------------------------------------------------------------------- Okay. That completely makes sense. Just second question your DD&A run rate fell from about $30 a barrel in the last six quarter or so its just under $25 a barrel. What drove that and what are your expectations going forward? -------------------------------------------------------------------------------- Tom Stoelk, Northern Oil & Gas, Inc. - CFO [54] -------------------------------------------------------------------------------- Really its the impairment so when you impair your oil and gas properties, you reduce the amount of the net asset and you still have the same kind of amount of reserves, so the denominator stays relatively the same, but the numerator which is the basis of your oil and gas properties is reduced by the impairment. And so the rate that I gave you in the script was a little bit under $25 per BOE is our expectation in the second half. Thats probably a pretty good number for Q3. And then if there is another impairment which I think we expect another impairment in Q3 just due to the continued low commodity prices in the way the SEC pricing works, we're replacing higher dollars with lower dollars. And in computation, youll continue to see a drop probably little bit further in the fourth quarter, but until we get to the third quarter we won't know what that answer is. -------------------------------------------------------------------------------- Phillips Johnston, Capital One Southcoast, Inc. - Analyst [55] -------------------------------------------------------------------------------- Okay, it makes sense. Thank you. -------------------------------------------------------------------------------- Mike Reger, Northern Oil & Gas, Inc. - Chairman, CEO [56] -------------------------------------------------------------------------------- Thanks. -------------------------------------------------------------------------------- Operator [57] -------------------------------------------------------------------------------- Thank you. And Im not showing any further questions in the queue. Id like to turn the call back over to management for any further remarks. -------------------------------------------------------------------------------- Mike Reger, Northern Oil & Gas, Inc. - Chairman, CEO [58] -------------------------------------------------------------------------------- All right. We appreciate everyones participation in the call today and your interest in Northern Oil and Gas. Ashley, if youll give the replay information. We look forward to talking to you guys again next quarter on the road soon. Thanks. -------------------------------------------------------------------------------- Operator [59] -------------------------------------------------------------------------------- Thank you. For this call's replay information please dial 800-585-8367 or 855-859-2056. For international dialing, its 404-537-3406. Please use the passcode 94735042. Ladies and gentlemen, thank you for calling in today. This does conclude the conference. Have a wonderful day.
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