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 speaker's remarks, there will be a question and answer session. At that time, if you would like to ask a question, please press star, then the number one on your telephone keypad. If you would like to withdraw your question, press the pound key. 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 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-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 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 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've 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 infill and interference tests 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 startup 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 runtime 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. 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. We were able to outperform our guided production range of 18,000 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 at very competitive prices that have increased our current net acreage position to approximately 320,000 net acres.
We have brought in additional workover 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. 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 to 22,500 BOEs per day, and we believe third quarter production will range between 22,000 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 26th, 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 non-operated 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 on 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 nine to 10 rigs for the remainder of the year. 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-$7 per BOE versus our previous guidance of $6-$8 per BOE. 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, 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. 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 on both the drilling and completion side. We are 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 and efficiency gains will decrease completed well cost by approximately 10% by the end of the year. We expect to further reduce well cost by another 5%-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 frack 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 startup crew. OWS has also provided us the opportunity to continually improve our stimulation on both third party and in-house frack 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 runtimes 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 percent 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 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 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 on 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. 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 barrels of oil equivalent-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 interwell 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 have 30 additional interwell spacing tests across the acres position. We are augmenting these tests with microseismic and extensive subsurface 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 is largely de-risked across the acres position, we continue to do important work in establishing Three Forks production in all of our areas. Indian Hills and South Cottonwood's Three Forks testing continues to progress, with well performance generally being in line with Bakken tests 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.
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 spudded 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 second quarter, our realized oil price averaged $82.36 per barrel, which was an 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-$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 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 30th. We completed a $400 million senior notes offering on July 2nd. Taking the offering into consideration, we had $631 million of pro forma cash and short-term investments as of June 30th. 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've spent $460 million 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 $10.5 million per well. The remaining development capital for the year is $452 million, we have about 50 wells scheduled to complete in the second half of the year. 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 hedged 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. At this time, if you would like to ask a question, please press star, then the number one on your telephone keypad. Your first question comes from the line of Ron Mills with Johnson Rice.
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. My first question is, should we look at the lease operating trend and sort of expect a similar improvement in 2013? Secondarily, recently, EOG has become a whole lot more bullish on the Bakken, and some of their thought process has to do with downspacing, 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?
Yeah, 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, Taylor, you want to cover that and going into 2013?
You asked about the LOE. 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. We trend to the lower end of the range.
You also talk about well cost of $8.8 million by the end of 2013, and you still got room to reduce it by about 5%-10% for 2013. Is that what I heard?
$8.8 by the end of 2012.
12, yeah.
Then another 5%-10% as we go into 2013 on pad drilling.
That's got to be 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.
Your next question comes from the line of Brian Lively with Tudor, Pickering, Holt.
Hi.
Morning.
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?
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. Both on actual reductions by service companies, reductions in the input costs, reductions in proppant costs, reduction in some of the other products that go into our completions. 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. 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, where we're getting some really good pricing on product proppant, for example, we're actually supplying that to some of our third parties. Yeah, 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 the stage that you guys are at on optimizing the completions. The commentary around, I guess, 36 stages, I guess, sounds like it's the upper limit at this point, and then the commentary around lower volume stages. Is that a function of where current costs are? Would that optimization be different if your stimulation or your frac costs were down 10% or 15% from here?
No. 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 far South Cottonwood. We continue to pump 36-stage 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 saturations, or combinations, are the areas where we've reduced the proppant.
That makes sense. 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?
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, in 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%-90% of a Bakken well. The areas outside, 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. 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 & Company.
Morning, guys.
Morning, Dave.
Real quickly, in your release, you talked about, and in your commentary, maybe being at 9-10 rigs throughout the balance of this year and 2-3 frac crews. Can you talk about the swing factors around those and why those would be varying a bit one way or the other?
Yeah. 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.
Depending on how efficient we are, we may drop back to nine. Again, on the frac side, it's similar. There may be points in time where we pick up a rig or a frac crews. Generally, the program will be nine rigs, maybe 10. We should be able to get the bulk of our work done with two frac spreads. Maybe we have to pick up a slot a month. It's just a little bit early to tell.
Okay. That's helpful. 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&A or maybe even looking beyond the Bakken on an M&A perspective?
Yeah. What we've said is that last year we looked at, I think, 2011, 15 or 16 different projects in and around our core areas. 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&D group to focus more attention on that and looking at, in order of priority, building around the core, although that's, as we all know, is very expensive these days. Further Williston expansion, then further down the list, other expansion outside of the Williston. The good news 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. Last thing with respect to the Bakken. As far as additional benches underneath the Three Forks, previously you'd been 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 thoughts around that would be helpful.
Have not done a whole lot of work on that at this point. We're 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.
Your next question comes from the line of Neal Dingmann with SunTrust.
Morning, gentlemen. Say, just a couple of questions. First, you continue to, looks like, do a good job by marketing a higher percentage of your operated volumes, and I was just wondering going forward if that will continue to be the case as your volumes continue to increase.
Yeah. 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. I was just wondering, I was trying to get the completed well cost, just what original budget and in current. 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? 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 actually just a bit higher.
Yeah. No, you're right. Those are spud wells. 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. It probably gives you a little bit better of a feel. 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 million a well. 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.
That ends up being about $9 million a well.
Got you. Okay. Then just last question. You mentioned about having some of the guar and sand procured already. When you look at the design, and I guess, when you move from the east, the Ness and all the way to your West Williston, are you continuing to tweak with the 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?
Yeah, we continue to optimize the proppant. The places that we use the most ceramic are Indian Hills and Far South Cottonwood, and we still use 60%-65% ceramic in those areas. North Cottonwood is all sand at this point. Red Bank, we've actually begun to pump less ceramic proppant, some of the recent wells have had around 30% of ceramic proppant and similar amounts of proppant in recent wells in Montana. 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 Stifel, Nicolaus.
Good morning, folks. Just had a question, 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 visibility?
I think the way to look at 2013 is, call it 150, at least as a straw man at this point, 115-120 gross operated wells. 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, and we can do the same amount of work with less rigs.
Okay. Do you have any thought as you head into development mode, the breakout of Bakken versus Three Forks wells you may drill?
For next year?
Yeah.
We're not that granular yet.
Okay. That's all I had. Thank you.
Yeah, you bet. Thanks.
Your next question comes from the line of Eli Kantor of Iberia Capital.
Good morning, guys.
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?
That's for you, Tommy.
I think our gas volumes on a BOE basis are an eight to 10% range right now, and over time, as we get all of our wells hooked in production, that'll trend up more to the 10%-12% range.
Okay, thanks. On the pad drilling side, and the talking about well cost coming down, how many wells per pad do you anticipate on drilling next year as you move further into development in 2013, 2014, 2015? Is there an opportunity to further reduce well cost by adding additional wells per pad?
We could potentially further reduce cost 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, but 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.
Michael.
I guess, on my end, just curious on the capital spending front, how much of the increase in 2012 spending you think would trickle into or more impact 2013? Is that predominantly just going to be from increased net interest per well?
Yeah, you will see the, Tommy mentioned the 115-120 gross operated wells next year.
Yeah.
You will see the higher working interest probably trickle into next year as well, Michael Liu. We'd expect somewhere probably around that 75% working interest range right now.
Okay. I guess I was also trying to get at, on just the 2012 spending, some of that production going to be really impacting the 2013 outlook, is that predominantly going to be felt this year?
Yeah, because of the higher spending, you're going to come in with strong production volumes going into the end of the year and into next. It will carry over, and impact next year's volumes as well.
Okay. 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. You can imply them through our third quarter guidance range and our annual guidance range.
Okay. Fair enough. In terms of the cost improvements expected in the rest of this year, how much of that would you attribute to service cost improvements versus efficiencies, if you had to split out those two?
I'd say roughly it's half, 50/50 between the two.
Okay. On next year's improvement, is that predominantly then going to be efficiencies, it sounds like?
A lot of it's efficiency.
Okay. I guess last on my end, just on the new ventures front, any commentary on, you've seen some activity or we've seen some activity in the more, let's say, northwestern extension of the Bakken. Have you guys looked in that general area or any thoughts on that?
You mean across the fault?
Yep.
Yeah. 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. For what we've been doing recently, it's really focused around the core positions.
Great. Fair enough. Thanks.
You bet. Thanks.
As a reminder, if you would like to ask a question, please press star one on your telephone keypad. Your next question comes from the line of Ron Mills with Johnson Rice.
Hey, guys. Sorry about that earlier.
Hi, Ron.
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 that first well in most of our blocks, and once you get through that first well, it's much more difficult to pick up working interest in subsequent wells.
Right.
That 75% number should be a pretty good number.
Okay. In 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'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?
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. Quite a bit of the savings next year will be from pad operations, and then also just overall operational efficiency. We think we'll be able to further reduce the cost an additional 5%-10%.
Okay. On the OWS side, is that also a function of the well cost, is that on track towards meeting your original expectations of saving ± that half a million dollars per well versus third-party services?
Yeah. The cost savings that we've talked about do not include savings from OWS. The amount that we save per well, when we talked about this, gosh, 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 costs, we're also reducing what we charge to do work with OWS, that's been reduced by around 25%. Your savings gross per well are probably more in the $700,000 range.
Okay. Lastly, I think you just started to address this on the gas production mix. As that trends from that 8%-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?
If you look at our proved reserves, Ron, they're around 11%-12% gas on an equivalent basis. As you get all your wells connected, we're at 85% now, which is what gets us into that 8%-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. 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%-12%.
Perfect. All right, guys, let me let someone else in. Thank you.
Thanks, Ron.
Your next question comes from the line of Peter Mahon 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 the pricing of those contracts is versus current market price and when those contracts will expire and if that's an area you can save going forward, and if it's been considered in that 5%-10% savings in 2013 that you talked about.
On the proppant side, we don't have any current long-term contracts on proppant. 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, we never got to fruition on that, never executed it. We've continued to be able to work our costs for proppant down. On the water side of the business, similarly, we don't have long-term contracts right now, and we're just working to get the best price we can in the spot market.
Peter, what you might have been alluding to is Taylor's comment on guar. We did get into a contract in guar late last fall. What you saw was guar prices really went up incredibly high in that first quarter, second quarter this year, and we were able to withstand that because we actually had our own supply. Those guar prices have come back to a more reasonable level now.
Okay, perfect. Thank you very much.
You bet.
Once again, if you would like to ask a question, please press star one. 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.
In Montana, or in or very close to Montana, we have two producing wells in the Three Forks. 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 a difficulty geosteering the well. It has ultimate recovery, probably about 250,000 barrels. The follow-up well of 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, and it looks like it's a 400,000-barrel plus well. 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. Taylor, talking about your, I guess, forecasting your gas volumes going forward, you guys have said previously that we should go with a 1,000 to 1,200 GOR. Is that still the same, or has that been increasing with the gas takeaway capacity?
No, that's still the same. 750 to a 1,000 GOR still works.
Okay. All right, one other clarification here. What was the mix again of volumes sent to Oasis owned SWD versus trucked and third party?
We've got about 60% of our volume going into our own injection wells, 30% of that is actually going through our gathering systems directly to the injection wells.
Half of the 60% is going through our gathering system.
Okay. Thank you.
You got it.
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 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.
Thank you everyone for joining today's conference call. You may disconnect your lines at this time, and have a wonderful day.