Chord Energy Corp (CHRD) 2012 Q2 法說會逐字稿

Good morning. My name is Beverly and I will be your conference operator today. At this time, I would like to welcome everyone to the second quarter 2012 earnings release and operations update for Oasis Petroleum. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session.

(Operator Instructions)

I will now turn the call over to Michael Lou, Oasis Petroleum's CFO, to begin the conference. Thank you. Mr. Lou, you may begin your conference.

Thank you, Beverly. Good morning everyone. This is Michael Lou. We're reporting our second quarter 2012 results. We're delighted to have you on our call. I'm joined today by Tommy Nusz and Taylor Reid, as well as other members of the team.

Please be advised that our remarks, including answers to your questions, include statements that we believe to be 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 causes actual results to be materially different from those currently disclosed in our earnings release and conference call. Those risks include, among others, matters that we have described in our earnings release, as well as in our filings with the Securities and Exchange Commission, including annual report on Form 10-K and our quarterly reports on Form 10-Q. We disclaim any obligation to update these forward-looking statements. Please note that we expect to file our second quarter 10-Q today.

During this conference call, we will also make references to adjusted EBITDA, which is a non-GAAP financial measure. Reconciliations of adjusted EBITDA to the applicable GAAP measure can be found in our earnings release or on our website.

I'll now turn the call over to Tommy.

Good morning, and thank you for joining us. I'll begin with some general comments, and then will turn the call over to Taylor and Michael to cover more detail on operations and financial highlights.

As we've discussed before, Oasis has been rapidly growing these past couple of years, and in the midst of that growth the Company is developing a strong foundation for future success. This year has been largely a transition year for us. As we look back to 2011, it was all about scale and execution. We consolidated our acreage position and began coring up our large blocks, and we secured the services we would need to execute on our development program.

The focus for 2012 has been in four areas. First, holding all of our drill blocks by production, and by the end of this year almost all of our inventoried acreage will be held. As we have talked about before, there still will be some unheld drill blocks, but those will be out in 2014, '15, '16, and easily manageable.

Second, we'll be making progress on extensional testing in both the Middle Bakken, and Three Forks, and associated well density. With that, the Middle Bakken is largely delineated across our acreage position, even up into North Cottonwood and into Montana. We will also make meaningful progress on the Three Forks this year. We commenced several in-fill and interference tasks in the second quarter to determine the optimal number of wells per horizon on each spacing unit and to test communication between laterals.

Third, operations optimization. That's optimizing services, including the start-up of Oasis Well Services, and continuing to evaluate different completion techniques in each of our operated regions to optimize well costs without degrading recoveries, and in some cases even improving recoveries. Fourth, infrastructure development. We're spending a lot of time on infrastructure planning and development to bring down unit costs, as shown in our financial results, and improving operating run time and maximizing revenues on both oil and gas. We're also beginning to realize cost reductions for both drilling and completions. We're expecting to knock off approximately 10% from current well costs by the end of this year, and with the additional savings from pad development, we'll be able to have an even larger impact on capital costs during 2013.

For the second quarter, we produced a record average of 20,353 BOEs per day, an increase of 2,720 BOEs per day, or 15% over the first quarter of 2012. And we were able to outperform our guided production range of 18,000 BOEs to 19,500 BOEs per day for the second quarter. On total completions, we initially planned to complete 22 to 24 wells in the quarter, a pace slightly below our first quarter. Due in part to mild weather, but in large part to our team continuing to push operational improvements, we were able to complete 26 gross operated wells in the quarter. These 26 gross operated wells had a 78% working interest, on average, compared to our budget of approximately 70%.

Our land team continues to do a great job of picking up additional acreage in and around our core blocks, which in turn drives our net well count up. We will continue to pick up leases in our core areas -- or we have continued to in our core areas -- at very competitive prices, and have increased our current net acreage position to approximately 320,000 net acres. We have brought in additional work-over rigs and set up a team to focus on production optimization and up-time on our producing wells. Our drilling pace and efficiencies, and drilling in completions have improved dramatically, and the weather has continued to cooperate, especially when compared to last year.

Production performance has definitely benefited from the excellent execution this year, and when coupled with an increase in activity, we have delivered above the top end of our production guidance ranges in the first two quarters of the year. Therefore, we are increasing our full year production guidance to 20,500 BOEs to 22,500 BOEs per day, and we believe third quarter production will range between 22,000 BOEs and 24,000 BOEs per day. In conjunction with our increased production guidance, we are also providing an update to our full year capital budget.

On July 26 our Board of Directors increased the total 2012 capital expenditure budget from $884 million to $1.062 billion. Development capital, the largest component of our budget, increased from $758 million to $912 million. This increase was driven primarily by higher working interest on our operated wells, and by an increased pace of drilling in both our operated and nonoperated blocks. We had initially budgeted for an average working interest in our operated wells of approximately 70%, but actual working interest on our operated wells has been more like an average of 77%, year-to-date. Our revised budget reflects an implied working interest of 75% for the full year in our operated wells. Additionally, we have increased operational performance from both our rigs and frac crews, and we now expect to be able to spud 112 gross operated wells while running 9 to 10 rigs for the remainder of the year.

So when we look at the full year implications of our revised budget, development capital increased by 20% and the associated uplift in volume from our capital program is also up approximately 20%. On the infrastructure side, we continue to build out our saltwater disposal and water handling systems. In large part due to the gains that we've made on the SWD front, we now expect full year lease operating costs of $5.75 to $7 per BOE verses our previous guidance of $6 to $8 per BOE. So through the first half of the year we are very encouraged by the execution and overall performance of our team. We have a lot of momentum headed into the second half of the year, and we intend to build on the hard work and outstanding results from the first half of the year to continue to deliver on our plan.

With that, I'll now turn the call over to Taylor to cover more operations detail.

Thanks, Tommy.

We have plenty of great news to update you on today. So let's start with well cost. As Tommy mentioned, we are beginning to see well cost reductions as a result of operational efficiencies, and reduced service costs in both the drilling and completion side. We are having constructive conversations with our vendors, and are benefiting from decreased service and product cost. In addition, we are optimizing our completion designs by region to reduce well cost. We currently expect these cost reductions and efficiency gains will decrease completed well costs by approximately 10% by the end of the year. We expect to further reduce well costs by another 5% to 10% in 2013. For reference, our current average well cost is $9.8 million, and we expect this cost to be reduced to approximately $8.8 million by the end of the year.

On the completion side, Oasis Well Services commenced 24-hour operations in June on a rotational basis, with operations on a two week on/one week off schedule. We are currently doing about 30% of our frac work on a 10-rig schedule, and expect that to increase to about 50% in the fall as we go to full 24-hour operations. We are pleased with the development of OWS, and continue to experience cost savings and operational efficiencies. In July, we completed 105 stages, and experienced less than 8% nonperformance down time, which is very good for a start-up crew. OWS has also provided us the opportunity to continually improve our stimulation on both third-party and in-house frac jobs through increased awareness of stimulation design, application, and quality control.

We have also made inroads into the procurement side of the business. Early in the quarter, one of the hot topics was the price of guar. Through our in-house efforts, we locked in a 12-month supply of guar at very reasonable prices in the fall of last year. Similarly, we have procured sand proppant and other input elements at favorable prices. On the infrastructure front, over 60% of our operator-produced water is currently injected into our own disposal wells, and over 30% of the total produced water flows through our water-gathering systems. As we build out our water-gathering systems, the injected and gathering system volumes will equalize. By year end, we expect to have about 80% of our water volumes going through our system and into our injection wells.

We've made significant progress this year on driving down per barrel water disposal costs, as you can see in our year-to-date LOE numbers. In the second quarter, LOE per barrel of oil equivalent increased slightly, as we were able to increase work-over activity during the favorable weather conditions experienced in late spring and early summer. The result was an increase in average run times on our wells. On the oil side, approximately 60% of our operated oil volume currently flows through the Banner system on the west side of the Basin. We anticipate this ramping to 80%-plus by the end of the first half of 2013, when our Cottonwood extension on the east side of the Basin is completed.

On the gas transportation and processing side of the business, we currently have approximately 85% of our wells connected to sales. The majority of production goes through Highland on the west and Bear Tracker on the east. The last major area left to be connected is the North Cottonwood. Bear Tracker is currently building out a gathering system in this area, which should be complete by the first quarter of 2013. As you can see, we continue to make significant strides on infrastructure placement, allowing us to maximize price realization, decrease production costs, and ensure wells can produce without interruption.

With respect to well performance, we continue to optimize our completions to reduce well cost and maximize recovery, based on the reservoir quality and conditions in each individual area. As a result, we have maintained our 36-stage completion design in some areas, and have reduced stages and/or stage sizes in other areas. The variables impacting the stimulation selection include reservoir thickness, shale thickness, water saturation, as well as reservoir quality. For example, in North Cottonwood where the Bakken is thick, but with higher water saturations, we have maintained a 36-stage completion, but have reduced the size of individual stages. We have pumped these modified designs in the last five wells completed in the area. The 30-, 60-, and 90-day cumulative oil volumes have been over 30% better than previous wells, with about 20% less proppant pumped, resulting in EURs of about 500,000 barrels of oil equivalent on these wells, based on very early time data.

In the Hebron area in Montana, we have taken a similar approach, but with even less proppant per stage. The Bakken is thinner in this area, but with a little higher water saturation. So we have employed 36-stage fracs, but with about 1 million pounds less proppant than North Cottonwood. The result has been wells with EURs in the 500,000 barrel oil equivalent range, but at a lower cost in stimulations previously used in this area. In contrast, in Northwest Red Bank, we have reduced the number of stages and the size of each individual stage, and achieved similar results to our previous 36-stage design for this area.

As you can see, we have a lot of variability in reservoir type and stimulation across our acreage, and as a result, we plan to talk about average well cost and well results going forward. We will use the type curve going forward of 450,000 to 750,000 barrels of oil equivalent, with an average well of approximately 600 BOE across all of our acreage. In addition to individual well performance, we have also focused on inner well spacing in 2012 as we approach year end, and have at least one well in most of our spacing units. We have four full pilots in various stages of maturity, with two in Indian Hills and two in Red Bank. In addition, we had 30 additional interwell spacing tests across the acreage position. We are augmenting these tests with micro-seismic and extensive subsurface evaluation to develop in-fill drilling plans by area as we go to full pad development in early 2013. As Tommy mentioned, an additional focus for us in 2012 has been extensional tests.

While the Bakken is largely de-risked across the acreage position, we continue to do important work in establishing 0.75 production in all of our areas. Indian Hills and South Cottonwood's 0.75 testing continues to progress, with well performance generally being in line with Bakken tests in those areas. In a recent interference test, the JO Anderson Three Forks well was drilled about 800 feet from a Bakken well which had already produced about 140,000 barrels. So far, the JO Anderson well has produced at a higher rate than other nearby Three Forks wells. We think that this is indicative of unique Three Forks reserves, even at close-Bakken/Three Forks well spacing.

Additionally, there are important Three Forks tests either underway or planned in most of our other areas. In North Cottonwood the Zdenek has just been fracked, and will be producing shortly, and O'Ryan is drilled and waiting on completion. In Red Bank the Arlos is drilling, and the Mercedes well will be spud in Q3. We will update you on these wells at the end of Q3.

I will now turn the call over to Michael to cover more of the financial detail.

Thanks, Taylor.

In the second quarter our realized oil price averaged $82.36 per barrel, which was a 11.7% differential to WTI. As most of you know, differentials have been pretty volatile this year. We had ticked up to as much as 19% in March, but we have seen a steady decline since then to about 8% in June. In July, Clearbrook and Guernsey differentials to WTI averaged around $5 to $6 per barrel, which is basically where they are now. We continue to have about a 50/50 mix between rail and pipeline, giving us a very balanced portfolio approach to our marketing efforts.

Marketing transportation and gathering expense was $1.06 per BOE in the second quarter, a $0.32 increase compared to the first quarter of $0.74 per BOE. The first quarter of $0.74 per BOE excludes our $1.4 million bulk oil purchase. The increase was primarily attributable to increased volumes of our operated production flowing through our gathering system. As Taylor mentioned, we saved between $3 and $5 per barrel in trucking costs; however, we incur about a $2 per barrel marketing and transportation fee.

On the natural gas front, we increased volumes from the first to second quarter by 30%, up to an average 11.2 million cubic feet per day. Importantly, all of that revenue drops to the bottom line, since we've already covered the processing and transportation costs in our POP contracts. Gas realizations were down from $8.32 per Mcf to $6.52 per Mcf, as our gas is liquids-rich, and liquids prices fell this quarter. Given the high BTU content of the gas, we are still realizing a substantial premium to Henry Hub prices.

In the second quarter, adjusted EBITDA was $108.5 million, a 7% increase over the first quarter. We had $239 million of cash on the balance sheet as of June 30. We completed a $400 million senior notes offering on July 2, and taking the offering into consideration, we had $631 million of pro forma cash and short-term investments as of June 30. Our $500 million revolver remains undrawn, providing us with total liquidity north of $1.1 billion to invest in the Business. We continue to have a strong balance sheet, which gives us both surety and flexibility, depending on the operating environment that we're in.

With regards to capital expenditures, as Tommy mentioned previously, we increased our 2012 capital budget from $884 million to $1.06 billion. We spent about $555 million in the first half of 2012. Adjusting for the $30 million spent in the first quarter relating to 2011 activity, which is not included in the revised budget, we have spent $460 million in development capital in the first half of the year. We completed about 44 net wells, so implied well costs in the first half of the year were about $10.5 million per well. The remaining development capital for the year is $452 million, and we have about 50 wells scheduled to complete in the second half of the year. So the implied well cost for the second half of the year is about $9 million per well.

We continue to hedge a little more aggressively in 2012 and 2013 as we drill up our acreage and outspend cash flow. Since our last update, we've increased hedge volumes by 1,500 barrels per day in the second half of 2012; and 2,500 barrels per day in 2013. We now have 18,000 barrels per day hedged in the second half of 2012, and 13,750 barrels per day hedged in 2013; and another 2,000 barrels per day hedged in 2014; all with about $90 per barrel floors. Overall, we had a record quarter on many fronts, and we're continuing the momentum created in the first quarter.

With that, we'll turn the call over to Beverly to open the lines up for questions.

Thank you.

(Operator Instructions)

Ron Mills, Johnson Rice.

Good morning Ron.

Ron, your line is open. Irene Hoff, Wunderlich Securities.

Congratulations on seeing some really great cost reduction. So my first question is, should we look at the least operating trend and sort of expect similar improvement in 2013; and then secondarily, recently EOG has become a whole lot more bullish on the Bakken, and some of their thought process has to do with down-spacing, which you guys are talking about, and also enhanced oil recovery. Would that be an aspect of your development plan in the Williston at some point in time?

I think probably a bit early to talk about enhanced oil recovery, at least for us. We have been talking about, pretty consistently, the potential to go from six wells, three in the middle Bakken and three in the Three Forks, to potentially as many as eight wells per 1280. As Taylor mentioned, we're doing a lot of testing on that this year, but early results look encouraging with respect to four wells per 1280. On the well cost front, (inaudible) do you want to cover that going into '13?

So you asked about the LOE. When you look at the guidance range we're giving this year, I think over time what you'll see is we'll continue, as we connect more of our wells to the disposal systems, we'll continue to trend down our unit cost and be closer to low end of that range. Whether that happens in '13 or a little further out just depends on pace of getting everything connected to the systems, but we trend to the lower end of the range.

You also talk about well costs of $8.8 million by the end of 2013, and you've still got room to reduce it by about 5% to 10% for 2013, is that what I heard?

$8.8 million by the end of 2012.

Yes.

Then another 5% to 10% as we go into '13 on pad drilling.

That's got to be kind of great for your margins, considering what a good job you've been doing on the marketing end as well.

You bet.

Thank you.

Thanks Irene.

Brian Lively, Tudor Pickering Holt.

Just some more color on the 10% reductions that you guys are anticipating. What specific services can you guys point to where you're expecting to see some break-over in terms of cost?

So the areas where we're getting cost reduction, one of them is definitely on the stimulation side. As you know, that's our biggest ticket item with respect to our total well cost. So both on actual reductions by service companies, reductions in the input costs, so reductions in Propit cost, reduction in some of the other products that go into our completions, and then on top of that, as we've talked about, we've also optimized our completion, so that in a lot of cases we're pumping less product and getting the same or better results on our wells. When you put all those things together, those are probably the biggest impact items getting to the 10%.

Taylor, on the stimulation side, are you expecting to see the same types of reductions on the wells, whether it's non-op or wells that you're completing outside of your OWS business?

We're doing that in OWS. We're really optimizing all operated wells. So whether it's OWS that's doing the work, or we have a third party pumping, we're still seeing savings. In fact, in some cases we're getting some really good pricing on product, Propit, for example. We're actually supplying that to some of our third parties. So yes, in general we are seeing those same cost reductions on all the operated wells. Hard to say on the non-op wells. I think they're trending down as well. I can't tell you if it's going to be at the same pace.

Sure. Then just on sort of the stage that you guys are at on sort of optimizing the completions. The commentary around, I guess, 36 stages, I guess probably sounds like it's sort of the upper limit at this point, and then the commentary around lower volume stages. Is that a function of where current costs are, and would that optimization be different if your stimulation or your frack costs were down 10% or 15% from here?

No. So to contrast, the short answer is we would pump the wells like we're doing, even in a higher cost environment, because we're seeing as good or better results. Now, the contrast to that would be in central deeper parts of the basin. So Indian Hills and parts of South Cottonwood, we continue to pump 36-stage jobs with the same volume of Propit. It's thicker, lower water saturations, and we think the intensity of the frack jobs are still warranted in those areas to get the most inquiries per stage. We're just, really when you get to some of the areas that have more variability from that. So either thinner reservoir, higher water saturations, or combinations are the areas where we've reduced the Propit.

That makes sense. Then last for me, on the Three Forks, the guidance that you guys gave on the 600,000 barrel equivalent average well, was that for both the middle Bakken and the Three Forks, or are you expecting the same results in the Three Forks as the middle Bakken?

So generally right now, the places that the Three Forks is de-risked is Indian Hills and South Cottonwood. Generally those two areas, the Bakken and Three Forks, are aligned to get a little more specific, and South Cottonwood, the Three Forks wells are as good or better than the Bakken wells. In Indian Hills, they're not quite as good, but close to being as good, so 80% to 90% of a Bakken well. The areas outside, so like North Cottonwood, as I mentioned, we've got some tests that we'll get data from in the next two quarters so we can tell you about, and then similarly for Red Bank, we're going to be drilling a couple tests in Q3 and Q4.

Thanks, appreciate the call, the color.

Welcome.

Dave Kistler, Simmons & Company.

Real quickly, in your release you talked about, and in your commentary, maybe being 9 to 10 rigs throughout the balance of this year, and two to three frack crews. Can you talk about the swing factors around those, and why those would be varying a bit, one way or the other?

Yes, I think Dave, it's just a function of where we are at any point in time. We've got another new build, which will be the last of the rigs that we have showing up, and we'll go to 10, but depending on how efficient we are, we may drop back to 9. So, again on the frack side, it's similar. There may be points in time where we pick up a rig or a frack crews, but generally the program will be 9 rigs, maybe 10. We should be able to get the bulk of our work done with two frack spreads, but maybe we have to pick up a slot a month. It's just a little bit early to tell.

Okay, that's helpful. Then with the comment of moving to full development mode or pad drilling in '13, how do you guys think about, then, the ongoing inventory and future, maybe M&A, or maybe even looking beyond the Bakken on an M&A perspective?

Yes. So what we've said is, is last year we looked at., I think, 2011 like 15 or 16 different projects in and around our core areas, but every time we do, we end up cannibalizing the asset teams in order to have the manpower to evaluate them. What we have done now is set up a separate, albeit connected, A and B group to kind of focus more attention on that, and looking in order of priority, building around the core, although that's, as we all know, is very expensive these days. Further, we'll list an expansion, and then further down the list other expansion outside of the Williston. The good news is, is we've got the luxury of not having to do anything any time in the near future in order to have a very robust business plan over the next 5 to 10 years.

Great, appreciate that. Then sort of last thing with respect to the Bakken, as far as additional benches underneath the Three Forks, previously you've been kind of letting industry drive that. Any changes to your thought process there? Do you start testing deeper benches in the Three Forks in the future? Just any kind of thoughts around that would be helpful.

Have not done a whole lot of work on that at this point. We're kind of watching industry activity and letting it come to us. We have cored a well, but don't have meaningful data to share out of that at this point.

Okay, appreciate that. Thank you, guys.

You bet. Thanks, Dave.

Neal Dingmann, SunTrust.

Say, just a couple questions. First, you continue, it looks like, do a good job by marketing higher percentage of your operated volumes, and was wondering, going forward if that will continue to be the case as your volumes continue to increases?

Yes, Neal. We're going to have more and more control with our marketing group over our marketed volumes. As Taylor mentioned, we've got more of our oil and gas coming in gathering system, and especially as that oil comes in our gathering systems, we have the ability to move that further and further down the line, and have a little bit more control, which you've seen a little bit in that in our realizations.

Okay, and then I was just wondering, I was trying to get the completed well costs, just sort of what original budget and then current, and I'm wondering, it looks like, was the estimated net wells originally around 80 and that's going to 93, and with developmental capital going from $758 million to $912 million? Because I clearly see how, you mention about the costs coming down, but when I'm just doing that quick math on that, it implies that the completed well cost is actually just a bit higher.

Yes, you're right. Those are spud wells. So the detail that I gave you in the call, so wouldn't go over that again but that's on a completed well basis. So it probably gives you a little bit better of a feel. So from that perspective, $460 million of development capital in the first half of the year with 44 net wells brought on to first production. That's operated and non-operated, both on the capital front as well as the completed front. It ends up being about $10.5 half million a well. Then for the second half of the year, we've got development capital of about $452 million, with 50 net wells scheduled to be coming online.

Got it, okay.

So it ends up being about $9 million a well.

Got you, okay. Then just last question. You mention about having some of the guar and sand procured already. Now when you look at the design, and I guess kind of when you move from the east, the Nesson all the way to your West Williston, are you continuing to sort of tweak with how much and which type of sand you're using, versus again maybe remind me how much, if any, ceramic you're still using there.

Yes, we continue to optimize the Propit. So the places that we use the most ceramic are Indian Hills and far South Cottonwood, and we still use 60% to 65% ceramic in those areas. North Cottonwood is all sand at this point. Red Bank, we've actually begun to pump less ceramic Propit, so some of the recent wells have had around 30% of ceramic Propit, and similar amounts of Propit in recent wells in Montana. So that is another variable in the completion design, and we'll continue to optimize around that.

Great, that's great color. Thanks, gentlemen.

Thanks.

Tim Resvan, Sterne Agee.

Just had a question kind of as we look out to activity levels in 2013. We have a $90 oil price. Hedges are locked in, and you have secured financing with the recent debt issuance. How do you think about your rig count into 2013, given that visibility?

Yes. I think the way to look at 2013 is call it, at least as a straw man at this point, 115 to 120 gross operated wells. So slightly up from this year, but relatively flat, which would imply that rig count's probably relatively flat as well, unless we get a lot more efficient than we are now. We can do same amount of work with less rigs.

Okay, and then do you have any thought as you kind of head into development mode, the breakout of Bakken verses Three Forks wells you may drill?

For next year?

Yes.

Yes, we're not that granular yet.

Okay, that's all I had. Thank you.

You bet. Thanks.

Eli Kantor, Iberia Capital.

Like 85% of your wells tied into gap gathering lines, how should we think about natural gas lines trending as a percentage of overall production for the balance of this year, and really more importantly, in 2013?

So I think our gas volumes on a BOE basis are kind of in the 8% to 10% range right now, and over time, as we get all of our wells hooked in production, that will trend up more to the 10% to 12% range.

Okay, thanks. On the pad drilling side, and you're talking about well costs coming down, how many wells per pad do you anticipate on drilling next year, as you move forward into development in '13, '14, '15? I mean, is there an opportunity to further reduce well costs by adding additional wells per pad?

Yes, we could potentially further reduce costs by adding any more wells to a pad. Right now, most of our pads will have either two or four wells on them at this point, just the way we have them configured, and we potentially have the ability to add wells to those pads, probably more likely more four-well pads. We continue to work on that design as we go forward.

Okay, thanks.

Michael Hall, Robert W Baird.

I guess I'm just curious on the capital spending front, how much of the increase in 2012 spending do you think would trickle into or more impact 2013, or is that predominantly just going to just be from increased well, increased net interest per well?

Yes. So you will see, Tommy mentioned kind of the 115 to 120 gross operated wells next year. You will see the higher working interest probably trickle into the next year as well, Michael. So we'd expect somewhere probably around that 75% working interest range right now.

Okay. I guess I was also trying to get on just the 2012 spending, some of that production is going to be kind of really impacting the 2013 outlook, or is that predominantly going to be felt this year? Yes, you're going to come in with, because of the higher spending, right, you're going to come up with strong production volumes going into the end of the year and into next. So it will carry over and impact next year's volumes as well. Okay, and would you care to put any sort of exit rate targets out? If you have already, I'm sorry I missed it.

No, we haven't given any exit rates, but you can kind of imply them through our third quarter guidance range and our annual guidance range.

Okay, fair enough. Then in terms of the cost improvements expected in the rest of this year, how much of that would you, I guess, attribute to service cost improvements verses efficiencies, if you had to kind of split out those two?

I'd say maybe roughly it's 50%, 50/50 between the two.

Okay, and then on next year's improvement, is that predominantly, then, going to be efficiencies, it sounds like?

It's going to be, a lot of it's efficiency.

Okay, and then I guess last on my end, just kind of on the new ventures front, any commentary? You've seen some activity, or we've some activity, the more kind of, say, northwestern extension of the Bakken? Have you guys looked in that general area, or any thoughts on that?

You mean across the fault?

Yes.

Yes. I mean, obviously you have seen a lot of things, industry information, recently over there. To be honest, we haven't been focusing a lot of attention over there. It's really, for what we have been doing recently, it's really kind of focused around the core positions.

Great, fair enough. Thanks.

You bet. Thanks.

(Operator Instructions)

Ron Mills, Johnson Rice.

Sorry about that earlier. Couple of questions that I don't think have been asked. The change in gross well count verses net well count, most of which is related to the increased working interest. Michael, I think you just mentioned you may have a 75% interest next year as well. How much opportunity do you guys think there is to continue to increase working interest in your current projects, or do you think you're almost at that maximum level?

I think you're getting close to that maximum level, because as you're drilling, getting through this year, we've drilled kind of that first well in most of our blocks, and once you get kind of through that first well, it's much more difficult to pick up working interest in subsequent wells.

Right.

The 75% number should be a pretty good number.

Okay, and the $9 million well cost that your second half budget is alluding to, how much cost savings are already included in there, relative to pad development? I guess I am looking ahead to 2013, once you've move to pad development. What further cost improvements do you think you can achieve beyond that second half number?

So it's a small portion of the savings or pad. I think 30% of our wells, roughly, are pad wells this year. We're still working on that design. So quite a bit of the savings next year will be from pad operations, and then also just overall operational efficiency, and we think we'll be able to further reduce the costs an additional 5% to 10%.

Okay. On the OWS side, is that also a function of the well cost, and is that on track towards meeting your original expectations of saving, plus or minus that $0.5 million per well verses third-party services?

Yes, so the cost savings that we've talked about do not include savings from OWS. The amount that we save per well when we talk about this, two to three quarters ago when we got started talking about OWS, we talked about a gross well cost savings of about $1 million per well. With the reduction in service cost, we are also reducing what we charge to do work with OWS, and so that's been reduced by around 25%. So your savings gross per well are probably more in the $700,000 range.

Okay, and then lastly, I think you just started to address this on the gas production mix. As that trends from that 8% to 10% level a little bit higher, is that purely a function of having more gas infrastructure in place, or do you think different areas of the Bakken will end up having higher gas/oil ratios, helping to drive that, or is it a function of both?

Yes, if you look at our [pred] reserves, Ron, they're around 11% to 12% gas on an equivalence basis. So as you get all your wells connected, we are 85% now, which is what gets us into the 8% to 10% range. As you get all those wells connected, and really what's missing right now in terms of a big chunk, is that North Cottonwood area. So as that comes on call at the end of the year, first quarter of next year, when that comes online almost all of our gas volumes will be online and you'll be in that 10% to 12%.

Perfect. All right, guys. Let me let someone else in. Thank you.

Thanks Ron.

Peter Mahon, Dougherty.

I just had one question. You talked about securing some of your water and your Propit and things like that under contract last fall. I was wondering where the pricing of those contracts is verses current market price, and when those contracts will expire, and if that is something you think you can -- if that's an area you can save going forward, and if it's been kind of considered in that 5% to 10% savings in 2013 that you talked about?

So on the Propit side, we don't have any current long-term contracts on Propit. So we've been able to take advantage of the reductions in the price that we're seeing in the market. We did talk at one time about, I think, a little longer term Propit contract, but we never got to fruition on that, never executed it. So we've continued to being able to work our costs for Propit down. On the water side of the business, similarly we don't have long-term contracts right now, and just working to get the best price we can in the spot market.

What you might have been alluding to is Taylor's comment on guar. We did get into a contract on guar late last fall. Now, what you saw was guar prices really went up incredibly high in the first quarter, second quarter this year, and we were able to withstand that because we actually had our own supply. Now that those guar prices have come back to a more reasonable level now.

Okay, perfect. Thank you very much.

You bet.

(Operator Instructions)

Gail Nicholson, KLR Group.

Just a quick question. I wanted to know your thoughts regarding possible Three Forks potential out on your Montana acreage?

So in Montana or very close to Montana, we have two producing wells in the Three Forks. The first, actually the first Three Forks well that we drilled on the west side was in Montana, and that well, we didn't get an effective stimulation off in the well and had difficulty geo-steering the well. It has ultimate recovery, probably of about 250,000 barrels. The follow-up well to that, that was in pretty close proximity, was just across the state line, but right next to Montana, probably about a 1.5 miles away from the first well. Better job of geo-steering, better stimulation. It looks like it's 400,000 barrel-plus well. So we've had some improving and decent results, and we'll drill some additional tests going forward.

Thank you.

Andrew Coleman, Raymond James.

Talking about, I guess forecasting your gas volumes going forward. You guys have said previously that we should go with 1000 to 1200 GOR. Is that still the same, or has that been increasing with the gas takeaway capacity?

That's still the same. 750 to 1000 GORs still works.

Okay. All right, and then one other clarification here. What was the mix again of volumes sent to Oasis-owned SWD verses trucked in third party?

So we've got about 60% of our volume going into our own injection wells, and 30% of that is actually going through our gathering systems directly to the injection wells.

So half of the 60% is going through our gathering system.

Okay. Thank you.

Okay.

At this time there are no further questions. I'll turn the floor back to management for any closing remarks.

Great, thanks. This has been a very exciting year for Oasis and we're proud of what the team has done across all fronts. This year we're putting in the foundation, including efficient operations, lower well costs, improving our up-time, and optimized price realizations, just to name a few. We've also continued to rapidly grow the Company while maintaining a strong conservative balance sheet. We believe we're focused on the right things and have the right people in place to execute on our plan. Thanks again for everyone's participation in our call today.

Thank you, everyone, for joining today's conference call. You may disconnect your lines at this time, and have a wonderful day.