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 2nd 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.
I will now turn the call over to Michael Lu, Oasis Petroleum's CFO to begin the conference. Thank you. Mr. Liu, you may begin your conference.
Thank you, Beverly. Good morning, everyone. This is Michael Liu. We're reporting our Q2 2012 results. We're delighted to have you on our call.
I'm joined today by Tommy News and Taylor Reid as well as other members of the team. Please be advised that our remarks, including the 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 cause 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 our annual report on Form 10 ks 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 Q2 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 we'll 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 4 areas. 1st, holding all of our drill blocks by production and by the end of this year almost all of our inventory to acreage will be held. As we've talked about before, there still will be some unheld drill blocks, but those will be out in 2014, 2015, 2016 and easily manageable. 2nd, 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 infill and interference tests in the Q2 to determine the optimal number of wells per horizon on each spacing unit and to test communication between laterals. 3rd, 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. And 4th, 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 Q2, we produced a record average of 20,353 BOEs per day, an increase of 2,720 BOEs per day or 15% over the Q1 of 2012.
And we were able to outperform our guided production range of 18,000 to 19,500 BOEs per day for the 2nd quarter. On total completions, we initially planned to complete 22 to 24 wells in the quarter, a pace slightly below our Q1, 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 continue to 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 uptime on our producing wells. Our drilling pace and efficiencies in drilling and 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 1st 2 quarters of the year. Therefore, we are increasing our full year production guidance to 20,500 to between 220,200 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 $884,000,000 to $1,062,000,000 Development capital, the largest component of our budget, increased from $758,000,000 to $912,000,000 This increase was driven primarily by higher working interest in our operated wells and by an increased pace of drilling in both our operated and non operated blocks. We had initially budgeted for an average working interest in our operated wells of approximately 70%, but actual working interest in 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 versus 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're having constructive conversations with our vendors and are benefiting from decreased service and product costs. In addition, we are optimizing our completion designs by region to reduce well cost.
We currently expect these cost reductions 10% in 2013. For reference, our 10% in 2013. For reference, our current average well cost is 9,800,000 dollars and we expect this cost to be reduced to approximately $8,800,000 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 our 2 week on, 1 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% non performance downtime, 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 operated 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 cost 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 workover 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 twenty thirteen 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 our production goes through Highland on the West and Bear Tracker on the East. The last major area left to be connected is in North Cottonwood. Bear Tracker is currently building out a gathering system in this area, which should be complete by the Q1 of 2013. As you can see, we continue to make significant strides on infrastructure placement, allowing us to maximize price realization, decrease production cost 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 5 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 £1,000,000 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 and 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 a 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 inter well spacing in 2012 as we approach year end and have at least one well in most of our spacing units.
We have 4 full pilots in various stages of maturity with 2 in Indian Hills and 2 in Red Bank. In addition, we have 30 additional inter well spacing tests across the acreage position. We are augmenting these tests with microseismic and extensive surface evaluation to develop infill 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 test. While the Bakken has largely derisked across the acreage we continue to do important work in establishing Three Forks production
in all of our areas.
Indian Hills and South Cottonwoods Three Forks testing continues to progress with well performance generally being in line with Bakken test in those areas. In a recent interference test, the J. O. Anderson Three Forks well was drilled about 800 feet from a Bakken well, which had already produced about 140,000 barrels. So far, the J.
O. 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 Z Neck has just been fracked and will be producing shortly and Orion is drilled and waiting on completion.
In Red Bank, the Arliss 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 details. Thanks, Taylor. In the Q2, our realized oil price averaged $82.36 per barrel, which was a 11.7 percent 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 fixed fifty-fifty 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 2nd quarter, a $0.32 increase compared to the Q1 of $0.74 per BOE. The first quarter of $0.74 per BOE excludes our $1,400,000 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 $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 11,200,000 cubic feet per day. Importantly, all 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 2nd quarter, adjusted EBITDA was $108,500,000 a 7% increase over the Q1. We had $239,000,000 of cash on the balance sheet as of June 30. We completed a $400,000,000 senior notes offering on July 2 and taking the offering into consideration, we had $631,000,000 of pro form a cash and short term investments as of June 30. Our $500,000,000 revolver remains undrawn providing us with total liquidity north of $1,100,000,000 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 $884,000,000 to $1,060,000,000 We spent about $555,000,000 in the first half of 2012. Adjusting for the $30,000,000 spent in the Q1 relating to 20 11 activity, which is not included in the revised budget, we've spent $460,000,000 in development capital in the first half of the year. We completed about 44 net wells, implied well costs in the first half of the year were about $10,500,000 per well. The remaining development the implied well cost for the second half of the year is about $9,000,000 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 1500 barrels per day in the second half of twenty twelve and 2,500 barrels per day in 2013. We now have 18,000 barrels per day hedged in the second half of twenty twelve 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 Q1. With that, we'll turn the call over to Beverly to open the lines up for questions.
Thank you. Your first question comes from the line of Ron Mills with Johnson Rice.
Good morning, Ron.
Ron, your line is open. Your next question comes from the line of Irene Haas with Wunderlich Securities.
Hi. Congratulations on seeing some really great cost reduction. And so my first question is, so should we look at the lease operating trend and sort of expect a similar improvement in 2013? 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 enhance oil recovery. Would that be an aspect of your development plan in the Williston at some point in time?
Yes. 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 6 wells, 3 in the middle Bakken and 3 in the Three Forks to potentially as many as 8 wells per twelve eighty. And as Taylor mentioned, we're doing a lot of testing on that this year, but early results look encouraging with respect to 4 wells per 1280. On the well cost front.
Taylor, you want to cover that going into 13?
So you asked about the LOE. We're when you look at the guidance range that we've given this year, I think over time what you'll see is we'll continue as we connect more of our wells to disposal systems, we'll continue to trend down our unit cost and be closer to the low end of that range. Whether that happens in 2013 or a little further out just depends on pace of getting everything connected to the systems, but we've trended at the lower end of the range.
And you also talked about well cost of $8,800,000 by the end of 2013 and you still got room to reduce it by about 5% to 10% for 2013. Is that what I heard?
$8,800,000 by the end of 2012.
Yes.
And 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, Armin.
Your next question comes from the line of Brian Lively with Tudor, Pickering, Holt.
Hi. Good morning.
The 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 costs?
So the areas where we're getting the 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. And so both on actual reductions by service companies, reductions in the input costs, so reductions in profit costs, reduction in some of the other products that go into our completions. And then on top of that, as we 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. So when you put all those things together, those are probably the biggest impact items getting to the 10%.
And Taylor on the stimulation side, do you 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 3rd party pumping, we're still seeing savings. In fact, in some cases, we are where we're getting some really good pricing on product proppant, for example, we're actually supplying that to some of our 3rd party. 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 don't I can't tell you if it's going to be at the same pace.
Sure. And 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 the 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 frac 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 at a higher cost environment because we're seeing as good or better results. Now the contrast of that would be in central deeper parts of the basin. So Indian Hills and in South Parcel Cottonwood, We continue to pump 36 days jobs with the same volume of proppant. It's thicker, lower water saturations and we think the intensity of the frac jobs are still warranted in those areas to get the most increase 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 saturation or combinations are the areas where we've reduced the proppant.
That makes sense. And 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 is that 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 derisked 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 that we can tell you about.
And then similarly for Red Bank, we're going to be drilling a couple of tests in Q3 and Q4.
Thanks. Appreciate the color. Welcome.
Your next question comes from the line of Dave Kistler with Simmons and Company.
Good morning, guys.
Good morning, Dave.
Real quickly in your release you talked about and in your commentary maybe being at 9 to 10 rigs throughout the balance of this year and 2 to 3 frac 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. And so again, on the frac side, it's similar.
And there may be points in time where we pick up a rig or a frac crews. But generally, the program will be 9 rigs, maybe 10. We should be able to get the bulk of our work done with 2 frac 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. And then with the comment of moving to full development mode or pad drilling in 2013, how do you guys think about then the ongoing inventory and future maybe M and A or maybe even looking beyond the Bakken on an
M and A perspective?
2019, we looked at, I think, 2011, like 16 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. But we have done is now is set up a separate, albeit connected, A and D group to kind of focus more attention on that and looking at an order of priority building around the core, although that's, as we all know, is very expensive these days. Further Williston expansion and then further down the list, other expansion outside of the Williston. I mean, the good news is, is we've got the luxury of not having to do anything anytime in the near future in order to have a very robust business plan over the next 5 to 10 years.
Great. Appreciate that. And 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.
I 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 quarter 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.
Your next question comes from the line of Neal Dingmann with SunTrust.
Good morning, gentlemen. Just a couple of questions. First, you continue to it looks like you do a good job by marketing a higher percentage of your operated volumes. I was just wondering going forward if that will continue to be the case as you volumes continue to increase?
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 trying to get the completed well cost just sort of what original budget and current and I'm wondering it looks like was the estimated net wells originally around 80 and that's going to 93 and with the developmental capital going from 758 to 912? Because I clearly see how you mentioned about the cost 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. That's a you're right. Those are spud wells. And so the detail that I gave you in the call, so I 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, dollars 460,000,000 of development capital in the first half of the year with 44 net wells brought on to 1st production. And that's operated and non operated, both on the capital front as well as the completed front. So it ends up being about $10,500,000 a well. And then for the second half of the year, we've got development capital of about $452,000,000 with 50 wells scheduled to be 50 net wells scheduled to be coming online.
Got it. Got it. Okay.
Ends up being about $9,000,000 a well.
Got you.
Okay. And then just last question. You mentioned about having some of the Gordon and Sand procure 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 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 proppants. 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 profit.
So some of the recent wells have had around 30% of ceramic proppant and similar amounts of profit profit 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.
Your next question comes from the line of Tim Rezvan of Stearnsky.
AG. Hi. Good morning, folks. Just had a question kind of as we look out to activity levels in 2013. We have a $90 oil price.
Your hedges are locked in and you've secured financing with the recent debt issuance. How do you think about your rig count into 2013 given that
2013 is call it, at least as a straw man at this point, 100 and 15 to 120 gross operated wells. So slightly up from this year, but I mean relatively flat, which would imply that rig count is probably relatively flat as well unless we get a lot more efficient than we are now. We can do the 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 versus 3 Forks wells you may drill? For next year? Yes.
Yes. I don't we're not that granular yet.
Okay. That's all I had. Thank you. You bet. Thanks.
Your next question comes from the line of Eli Kantor of Iberia Capital.
Good morning, guys. Good morning. With roughly 85% of your wells tied into gas gathering lines, How should we think about natural gas volumes 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 8% to 10% range right now. And over time, as we get all of our wells booked 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 further into development in 2013, 2014, 2015? I mean is there an opportunity to further reduce well cost by adding additional wells per pad?
Yes. We could potentially further reduce cost by adding any more wells to a pad. Right now, most of our pads will have either 2 or 4 wells on them at this point, just the way we have them configured. And we essentially have the ability to add wells to those pads probably more likely more 4 well pads, but we just we continue to work on that design as we go forward.
Okay. Thanks.
Your next question comes from the line of Michael Hall with Robert W. Baird.
Thanks. Good morning. I guess on my end, 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 be from increased well increased net interest per well?
Yes. So you will see the Tommy mentioned 115 to 120 gross operated wells next year. You will see the higher working interest probably trickle into 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 out on just the 2012 spending, some of that production 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 in 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 target 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 Q3 guidance range and our annual guidance range.
Okay. Fair enough. And 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 versus efficiencies if you had to kind of split out those
2? I'd say May roughly, it's half, fifty-fifty between the 2.
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 its efficiency.
Okay. And then I guess last on my end just kind of on the New Ventures front. Any commentary on you've seen some activity or we've seen some activity in the more kind of let's say northwestern extension of the Bakken, if you guys looked in that general area or any thoughts on that?
You mean across the fall?
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've been doing recently, it's really kind of focused around the core positions.
Great. Fair enough. Thanks.
You bet. Thanks.
Your next question comes from the line of Ron Mills with Johnson Rice.
Hey, guys. Sorry about that earlier. A couple of questions that I don't think have been asked. The change in gross well count versus 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 in the $9,000,000 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'm looking ahead to 2013 once you 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 are 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 cost to additional 5% to 10%.
Okay.
And 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 $500,000 per well versus third party services?
Yes. So we 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, gosh, 2 to 3 quarters ago when we got started talking about OWS, we talked about a gross well cost savings of about $1,000,000 per well. With the reduction in service cost, we're 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. Is 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 proved reserves, Ron, they're about 12 around 11% to 12% gas on an equivalence basis. So as you get all your wells connected, we're at 85% now, which is what gets us into that 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 Q1 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, Rob.
Your next question comes from the line of Peter Mahone with Dougherty.
Good morning, guys. I just had one question. You talked about securing some of your water and your proppant and things like that under contract last fall. I was wondering where those the pricing of those contracts is versus current market price and when those contracts will expire and if that is something you think you can that scenario 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 proppant side, we don't have any current long term contracts on proppant. 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 proppant contract, but we never got to fruition on that never executed it. So we've continued to be able to work our cost for profit 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.
And Peter, what you might have been alluding to is Taylor's comment on GWAR. We did get into a contract in GORE late last fall. Now what you saw was GORE prices really went up incredibly high in that Q1, Q2 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. Your next question comes from the line of Gail Nicholson with KLR Group. Good morning, gentlemen. Just a quick question. I wanted to know your thoughts regarding possible Three Forks potential out on your Montana acreage.
So in Montana, we in or very close to Montana. We have 2 producing wells in the Three Forks. The first actually the first Three Forks well that we drilled on the west side was in Montana. In that well, We didn't get an effective stimulation off in the well and had difficulty geosteering the well. It has ultimate recovery probably about 250,000 barrels.
The follow-up well of that that was in pretty close proximity was just across the state line, but right next to Montana probably about a mile and a half away from the first well, better job of geosteering, 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. Your next question comes from the line of Andrew Coleman with Raymond James.
Hey, thanks a lot for taking the question. I'd like talking about your I guess forecasting your gas volumes going forward, what you guys have said previously that we should go with 1,000 to 12 100 GOR. Is that still the same or has that been increasing with the gas takeaway capacity?
That's still the same, 750 to 1000 GOR still works.
Okay. And then one other clarification here. What was the mix again of volumes sent to Oasis owned SWD versus truck and 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.
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 cost, improving our uptime 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.