Good morning. My name is Tracy, and I will be your conference operator today. At this time, I would like to welcome everyone to the First 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 Thank you.
I will now turn the call over to Michael Liu, Oasis Petroleum's CFO to begin the conference. Thank you, Mr. Liu. You may begin your conference.
Thank you, Tracy. Good morning, everyone. This is Michael Liu. We are reporting our Q1 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 following 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 anticipated. 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 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 measures 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 this morning. I'll begin with some general comments, then turn the call over to Taylor and Michael cover more detail on operations and financial highlights. In 2011, our focus was on acreage consolidation and our large concentrated acreage blocks, completion optimization and securing the services needed to execute on our plan. We made a great deal of progress coring up our large blocks and increased the amount of acres contained within our identified drilling inventory to between 250,000,260,000 acres out of our total of roughly 300,000 net acres. At the end of the year, we had roughly 184,000 net acres held by production.
On the completion front, everything we do now for the most part is plug and perf completions. We did a lot of testing last year, primarily going from 28 stages to 36 stages. We're still working off of relatively early time data, but with the exception of a couple of areas, it looks like we're realizing from 17% to 31% increases. So not completely linear uplift, but still very efficient capital deployment. We also secured the services that we needed in order to execute on our capital plan.
For 2012, it's getting our blocks held and figuring out well density, optimizing services and realizing the cost benefit of building up infrastructure. At the end of the year, we will be in pretty good shape on holding our acreage and effectively will have held all of our drilling blocks. That's not to say that we still won't have some undrilled blocks at the end of the year, but the first expiries on those are primarily out in 2015 2016, so easily manageable. Additionally, we will be drilling in excess of 30 wells to test inter well spacing. So we're kind of in a transition year from holding all of our acreage blocks to go into full pad development in 2013.
We want to make sure that we have some well density testing under our belt before we transition into drilling multiple wells in our spacing units. It's extremely important to make sure that we capitalize the spacing units appropriately, not having too many wells which would over capitalize the unit or too few wells which would effectively not drain all of the oil that's there. We'll get this data later this year and we don't currently have any intention of accelerating activity in advance of having that data in hand. We've also done extensive work this year on optimizing so that we've got everything that we need to operate on our program, which Taylor will describe in more detail in a minute. And then on infrastructure, we've made tremendous progress on oil and gas gathering and our company operated saltwater disposal systems.
This infrastructure is a big key for us for this year in driving down our per barrel unit costs and increasing our profit margins. For the Q1, we produced a record average of 17,006 133 BOEs per day, an increase of nearly 2,400 BOEs per day or 16% over the Q4 of 2011. As you know, we originally guided production at 15,000 to 16,500 per day for the Q1. We have planned for a normal cold winter and expected to complete around 16 to 18 gross operated wells during the quarter. Given the mild winter that we experienced, we got a little bit more than that done.
Additionally, our operations continue to become more efficient and we saw improvement in both drilling and completions. We have improved drilling days bringing spud to rig release down from about 27 days in 2011 to 23 days in the Q1 of 2012. We've also driven the days to frac a well down by over a half and we're around 5 days per well in the Q1. Our spud to first production decreased from an average of 110 days in 2011 to under 70 days in the Q1. That being said, as Taylor will cover with the pad work that we're initiating now, that will likely creep up a bit to the 80 to 90 day range in the near term.
Due to the good weather and overall operational improvements, we brought on production a record 26 gross operated wells in the quarter. In March alone, we brought 13 wells on production. We brought another 8 wells on in April, which is basically at the high end of our expectations for completions by month and we would expect bringing on 6 to 8 wells in each of the next 2 months. Production in March was approximately 18,700 BOEs per day, but we would expect growth to moderate a bit here through the Q2 as we start drilling more pad wells. So no surprise, our capital spend in the Q1 has been higher than expected driven by a number of things including acceleration, increase in operated well working interest and outside operated activity.
We continue to expect to grow production and take advantage of our early year success. With all the moving parts, for now, it makes sense for us to just give you a view on the Q2, which we believe will be in a range of 18,000 to 19,500 BOEs per day based on the completion schedule that I described earlier. Obviously, the bias to our full year guidance on capital and volumes would be upward given our Q1 results, but we plan on waiting until the end of the second quarter to do any formal updating. Michael will give you a little more color around that in a moment. We're executing and delivering on the initiatives that we established at the beginning of the year and the Q1 was an excellent way to start the year.
The team continues to grow and we're attracting some very talented people across all functional groups to help us to continue to deliver on our plan. With that, I'll now turn the call over to Taylor and Michael to cover more operating and financial detail.
Thanks, Tommy. As we have discussed in the past, we will be drilling and completing a number of infill tests in 2012. That activity will really start to pick up in the Q2. When you drill on pads, a rig will typically drill all of the wells before the frac crew shows up start completing the wells. All told, this process slows down the overall completion process for a couple of months, bringing the spud to first production cycle times for the early pad projects back up into the 90 day range as Tommy mentioned.
But this has been baked into our plan all along and we fully expect to bring cycle times back down over time. Our operations team has done a great job in managing the drill and completion schedule along with our service company contracts to accomplish our overall goals for 2012. We were recently able to drop one of our frac spreads as we were not going to need their services in the second quarter based on the pad work I just described as well as the overall efficiency of our crews. So we currently stand at 2 external frac spreads. At the same time, we are ramping OWS, which will be operating 20 fourseven at the end of the second quarter.
So with OWS ramping and improved efficiency, we are really balanced on completion crews for our rig activity. The team is also managing rigs in a similar fashion. We have improved drilling efficiency and now expect to drill our projects this year with closer to 10 rigs instead of the 12 that we have available. We will drop 2 of the rigs we have been running when the new build rigs show up, allowing us to high grade our rig fleet in preparation for pad work. Easiest way to think about this is that we'll stay flat at 10 rigs from here with better spud to spud times and maintain our target of 108 gross operated projects or slightly up depending on efficiency.
From a capital cost perspective, for a typical 36 stage well, we are still in the $10,000,000 range that we have been talking about. It feels like we have seen the top on service costs and are starting to see reductions both on the drilling and completion side. Some of the recent gains we have made in terms of efficiency and cost reductions have been offset by the cost to comply with the recent NDIC regulations. That being said, we applaud the state's approach to being proactive at the state level with these changes. We continue to have about 26 gross operated wells and are waiting on completion backlog, which is where it was on both March 31 April 30.
As we've addressed previously, the service bottleneck has been obtaining workover rigs to work through the backlog of wells that need to be cleaned out or worked over. We have 1 more workover rig showing up in May and a Riglet which has more horsepower than a normal workover rig coming in June. We continue to be excited about our Three Forks program. On the east side, the Spratly Three Forks well in South Cottonwood still looks to be the best well we have drilled to date and has produced a cumulative volume of just under 160,000 barrels over the 1st 200 days. Additionally, our Caspian well up in 156 North, 96 West up closer to the center of our Cottonwood block has produced about 57,000 barrels over the 1st 130 days.
We have planned 2 more Three Forks wells in East Nesson this year north of our Spratley and Caspian wells. 1 will be in the center of the East Nesson block and one will be 1 unit below our northernmost Cottonwood Bakken Wells. On the west side of the basin, we just cored the lower benches of the Three Forks formation in Southern Indian Hills on a well called the Lefty. I do not have anything to share with you right now, but we'll definitely give our initial read on oil saturations and rock quality once we have had more time to analyze the data. We expect to drill 22 Three Forks wells on the Westside this year.
On the infrastructure 60% of our operated produced water is injected into our own disposal wells and about 25% of the total produced water flows through our gathering systems. As we build out our gathering systems, the injected and gathering system volumes will equalize. By year end, we expect to have about 80 percent of our volumes going through our system and into our injection wells. We're making a lot of headway this year on driving down per barrel water disposal cost as you can see in our LOE numbers this quarter. Gas infrastructure is something that's moving quickly across the basin and most of our peers are well on their way to getting their wells tied in the gas infrastructure.
In our case, we moved the bulk of our gas to Highland. Last year, if you looked at the end of the summer, our total net gas production to sales was about 2,000,000 cubic feet per day. That number today is about 10,000,000 cubic feet per day and approximately 83% of our wells are now connected. On the oil side, we've got about 60% of our oil production flowing through the Banner system. It's a big loop system on the west side of the basin that gives us access by pipe from all our wells to larger oil pipelines and rail transport systems.
We started taking more of the marketing responsibility in house for this so that we can optimize where our volumes go. We've connected 91 wells so far on the oil side. We are also working with 3rd parties on connecting wells in our East Nesen position as well and hope to have some more news on that in coming quarters. I'll now turn the call over to Michael.
Thanks, Taylor. In the Q1, we averaged an $88 per barrel realized oil price, which was a 14% differential to WTI. We had ticked up to as much as 19% in March, but we have seen a steady decline since then to about 13% in May. As of yesterday, Clearbrook and Guernsey differentials to WTI were only $1.50 versus the $2.27 in February. In April, we had about 60% of our volumes moving by rail and we continue to have about a fifty-fifty mix between rail and pipeline, giving us a very balanced portfolio approach to our marketing efforts.
As Taylor mentioned on the gas front, we had 8,600,000 cubic feet per day average in the Q1 and over 10,000,000 per day in March. Importantly, all that revenue drops to the bottom line since we've already covered the costs in our POP contract. Given the high BTU content of the gas, we continue to realize north of $8 per Mcf. It might also be helpful to note that we had a one time bulk purchase of oil of $1,500,000 with associated costs of $1,400,000 This is not part of our day to day plans, but the $1,400,000 of costs showed up in our marketing, transportation and gathering expenses. Without these costs, we were well below the low end of our guidance range at $0.74 per BOE.
We still to be expect to be within our range for the full year of 2012 of $1 to $1.50 per barrel, given the impact of the oil gathering system was not for the full quarter. On May 1 and 2nd, we opportunistically put some more hedges when oil prices were up for a short period of time. You can see in our latest hedging report, but we put on about 2,000 barrels a day at 9,750 by 114 for the back half of twenty twelve, 2,000 barrels a day and 95 by 111 in 2013 and another 2,000 barrels a day of 3 way with $20 put spreads in average collars of $9,250 by $114.40 for 2014. We continue to hedge a little more aggressively in 2012 'thirteen as we drill up our acreage and outspend cash flow. In the Q1, we had adjusted EBITDA of $101,000,000 a growth of 18% over the Q4 of 2011.
We had $287,000,000 of cash on the balance sheet as of March 31 and we're up to $322,000,000 in cash and investments as of May 1. Finally, addressing our total liquidity, our borrowing base, which is fully undrawn, was increased in early April to $500,000,000 leaving us with total liquidity north of $800,000,000 to invest in the business. In the Q1 of 2012, LOE averaged just $6.12 per BOE, a reduction of $2.10 per BOE compared to the 4th quarter. This is another example of how our guys are executing on the plan and finding ways to reduce costs. We were able to drive down trucking costs in the quarter to assist in this improvement and our higher production coupled with a milder winter helped on a per unit basis.
Given results today in our infrastructure system, we expect to trend more towards the lower half of our twenty twelve range of $6 to $8 per BOE. G and A costs have trended up in line with projections as we staffed up the team to execute on a larger drilling program as well as staffing up OWS. Production taxes for the quarter were approximately 9.6 percent of revenue, which is a bit better than originally projected. DD and A rates are up as well due to 20 11 well cost increases and the changing mix of our reserve portfolio towards the West Williston side. On the capital expenditures front, as Tommy previously mentioned, obviously, there was some additional capital spent associated with our accelerated activity in production in the Q1.
We spent $288,000,000 in the Q1, which included about $50,000,000 of capital associated with activity, which is not part of our $884,000,000 budget. Of that $50,000,000 $25,000,000 was associated with higher working interest in our operated wells and increased activity on the non operated side. The other $25,000,000 was due to one time costs originally anticipated for 20 11 that was carried over to 2012, including $10,000,000 for infrastructure and $15,000,000 for drilling and completion activities. We completed operated wells with an average working interest of 77% compared to the average in our budget of 70%. The working interest increase is primarily due to the heavy lifting of our land department as they trade out interest in wells.
We do not operate into wells that we are drilling on an operated basis. This resulted in swapping approximately 3,700 net acres in the Q1. We also have working interest of about 79% in our wells waiting on completion backlog, which is again above budget and drove additional spending in the Q1 as well as additional spending in future quarters. Additionally, our non operated partners completed more net wells than we expected aided by the mild winter weather and presumably more efficient operations similar to our own. We are not assured that this pace will continue, but additional activity should result in higher production.
Finally, on the non E and P capital side, as expected, we had 21,000,000 dollars of the $38,000,000 capital budget for this year occurring in the Q1, mainly related to OWS activity being brought into 2012. In all, adjusting for the $50,000,000 spent above the $884,000,000 budget in the 1st quarter and the timing of non E and P capital, we completed about a quarter of our expected work for the year in the Q1 and spent about a quarter of our budget. We know that the capital will be a bit higher for the year and we will update you with a revised capital budget after the Q2 when we have a bit more clarity on the ultimate pace of our non op drilling and the extent of our working interest increases on our operated blocks. Overall, we had a record quarter on many fronts and the Q1 has been a great way to begin the New Year. With that, we'll turn the call over to Tracy to open the lines up for questions.
Your first question comes from the line of Neal Dingmann with SunTrust. Please go ahead.
Good morning, guys. Just two quick ones. As far as you mentioned about going after the B bench on a well or 2, is one of your plans going forward as far as, I guess, for the remainder of this year, how you see that playing out as far as what you're going to be targeting?
At this point, we did the core work on the well in Southern Indian Hills, but we don't have any plans to actually drill and complete wells in the lower benches for this year.
Okay. And then just lastly, I know there's some packages out there. Just your thoughts on M and A. Is there things that you're looking at either on a I know there's some non op packages being shopped around and if you're seeing any operators, are you looking at anything on the M and A side?
Yes. Last year, we looked at, I think, 16 packages and we continue to see deal flow, although not at the same pace for the early part of this year. As a general rule, we pass on the non operated stuff. There have been a couple of those out there that we don't look at because it really isn't consistent with our business model. And a few more things on the operated side, but we'll have to see how that plays out.
Okay. Thank you for the color.
You bet.
Your next question comes from the line of Brian Lively with Tudor Pickering. Please go ahead.
Hi, good morning.
Good morning.
Tommy, your comments on potentially raising production and CapEx sometime around midyear if things sort of continue going as they have. With that, it seems like from a capital efficiency standpoint, the production uplift should be greater than the CapEx uplift, given that you're seeing the higher EURs on the wells with more stages and costs continue to kind of hold the line from a per well basis. Can you provide some commentary on it from that standpoint?
Yes. It's as Michael mentioned, we had about $50,000,000 which I mean we're that basically is 1st quarter that money that we know we're going to spend incrementally. And basically what that does is drive us to bias us to the upper half of our original annual range. If that trend continues, which I suspect at least on our operated drill blocks based on the data that we have now, that will continue based on some of the numbers that we have so far. So incrementally, it could be another over and above the $50,000,000 it could be another $50,000,000 to $100,000,000 but we'll have to see how that plays out.
But again, with that, obviously, I mean, if we have that incremental number or incremental amount of capital, then that would cause us to come back in and have to adjust our range upward.
Okay. On the Three Forks, the positive well results out of Cottonwood and I don't mean to be bent, I just mean the normal Three Forks. What are you guys seeing from a geologic standpoint, maybe just sort of compare and contrast what you've learned on sweet spots for the 3 ForEx versus the middle Bakken and just kind of how we should think about that from an overall resource standpoint?
So if you look at where we have test in the Three Forks is really the southern most southern portion of Cottonwood. And the Three Forks and Bakken in general in that area are pretty comparable. I mean we've got some, as we mentioned, Three Forks wells that are better than Bakken wells. But on average, I think across that position, they're at least equal. As you go to the northern half of the block, we just don't have the Three Forks test with greater frac intensity.
We've got some older test with sliding sleeves. So we'll drill those 2 wells this year and have them tested by end of the year in the Three Forks on the northern position. And then over on the West side in Indian Hills, we have a number of tests that confirm economics in the Three Forks. The Three Forks is compared to the Bakken there is not quite as good. So it's probably 80% of Bakken well in the 3 Forks at least at this point kind of in Indian Hills area.
And then in Red Bank and Hebron, it's still early days in terms of testing the Three Forks in those areas.
So there's not an overall concept of where the middle Bakken is good, the Three Forks is good. It's just a different, I guess, an evolving concept than the Als Mine?
Yes. It really depends on the area. You see variability between Bakken and Three Forks depending on where you are and it depends on rock quality, thickness, saturations, all those things.
Last question for me. Michael, this might be for you. The what is your ability to flex your well and pipe volumes just based on spot prices?
So you're talking about purchasing pipe relative
to No, I'm just saying Michael said that 50% or so of the volume that you sold was in rail versus pipe. And I'm just wondering what the ability to flex that is real time?
Yes. A lot of our marketing volumes are still done on a month to month basis, Brian. So the system that we've got in place, the gathering system actually gives us a lot more flexibility. If you look at that system, it's got access to 6 different rail sites, 3 different pipe sites. It gives us a lot more flexibility and a lot of our volumes are now on that system.
So on
a month to month basis, we can actually start to move some of those volumes around a little bit more. Once again, we're going to keep a pretty balanced approach, but we were able to move a little bit more towards rail because of better pricing over the back part of that Q1 when differentials blew out a little bit.
So does that minimize you think the volatility at least a little bit going forward on the swings we've seen in differentials?
Yes. There's still going to be potentially some volatility there. And while it certainly minimizes or reduces it some from where we were 6 months ago, there's still going to be volatility. If you had Enbridge blow out like you did 1.5 years ago, you'd still have issues in the basin.
All righty. Thanks, guys.
Your next question comes from the line of Dave Kinstler with Simmons and Company. Please go ahead.
Good morning, guys. Good morning, Dave.
Real quickly on OWS, can you talk a little bit about where you are on kind of current utilizations of that crew and kind of your projected run rate for those guys throughout the year given that you had a willingness to drop another frac crew?
So we've as we've stated, we've initiated frac and we've actually fracked 5 wells. 4 of those were actually partial wells, where we didn't complete a frac previously and we came back in thinner stages. The last well, the 5th well was actually a complete frac on a well. So we're improving the efficiency of the operation. We're still staffing the crew.
We've got a little over 30 employees in OWS right now. We think by June, we'll be closer to true 24 hour operations early to late June, we should be going 20 fourseven, and then going at full capacity. In terms of utilization, we'll have 3 frac crews. So as you get into 3rd and 4th quarter, they should be doing at least a third of our frac work.
Okay. That's helpful. Appreciate it. Then with respect to kind of the drilled uncompleted backlog and the issue with clean outs, etcetera, have you guys had any structural issues with those wells that you've been waiting to either complete or that have been completed and waiting to tie in? Just kind of curious if there's any degradation wall between drilling, completing and time to tie in?
No. I think overall, we've gotten more efficient on drilling, more efficient on fracking. Those cycle times are way down. We still have the backlog is really still around the clean out operation. And as we bring on more clean out rigs, we'll work continue to work that down.
There is
yes. Okay. But no structural issues while those are waiting to be either cleaned out or tied in? I guess what I'm asking is, is there any performance degradation on wells that are, I guess, drilled uncompleted and waiting to be tied in relative to wells that are smoothly from start to finish
done? Yes. We don't think so, Dave.
Okay. That's helpful. And then last thing, when you talked about pad drilling and looking at what the cycle times are going to do and whatnot throughout this year, can you just articulate, I think, of the 80 some odd wells you're looking at, what percent are going to be pad versus what are just going to be individual wells?
It's probably for this year.
It's about a third.
About a third. But going forward really all of our even if we're not drilling a pad one well in each direction, you're going to get to where everything is a pad well either drilling in opposing directions or multiple wells in the same direction of the same path, but roughly a third for this year.
Okay. That's helpful. I appreciate clarifications guys.
You bet.
Your next question comes from the line of Scott Hanold with RBC Capital Markets. Please go ahead.
Thanks. Good morning. Good morning, Taylor. Hey, Taylor, you had mentioned that continuing on the pad drilling, something to the effect of there's generally a 2 month sort of lag once you start getting the pad development. Is that sort of a what you would imply is sort of a short term as you start developing this, you'll see a little bit of a lag or is that sort of an ongoing kind of thing we're going to look at and sort of how do we when we look at 2012, how should we think about the pad, the lumpiness of pad drilling, will it smooth out by the end of the year or is that something that's going to take a little bit more into development mode into 2013?
Yes. So you're going to have it's going to be kind of choppy for this year. But once we get into full pad operations with all of our rigs or most of them drilling on pad operations that will effectively smooth out. The early time wells, we may go to simultaneous operations over time, doing more simultaneous operations. And so it'll smooth out as you get into 2013.
Okay. But this is something I guess most of the quarters in 2012 where we should actually expect some impact from moving into pad development. Is that a fair statement?
Yes. Most of the impact there's probably a little bigger impact in the Q2, but you'll see some of that in all the quarters of this year.
Okay, understood. And also on the DD and A, obviously, you indicated DD and A came up this quarter. And I'm sort of hearing a little bit of a mixed message where it sounds like there's some efficiencies that are coming in place and some costs that you're seeing coming down, but obviously the DD and A rate jumped a fair amount quarter over quarter. In that DD and A, is there anything relative to like the I mean, what was like E and P DD and A versus like all other stuff? Can you separate that as well?
Is that the point of it?
Sure. That's a good question, Scott. From the DD and A side, it's 2 things. 1, it is a bit in hindsight, right? So some of the 2011 cost increases that we talked about all last year are in those numbers now, whereas they hadn't been before.
So those costs remember in 2010 more like $8,500,000 they got to about $10,000,000 in 2011 as we had service cost increases and we also moved from 28 to 36 stages on a lot of our wells, a lot of those costs came in. Now we may or may not have gotten full credit for all those 36 stage reserves even though we think that early time data looks good. It was still early time especially at year end when we set those reserves. We also had about $1 impact from the saltwater disposal infrastructure like you were talking about. It's about $1 impact to the DD and A rate.
And you probably had another around $1 impact from just shifting volumes as we move away from the impact of Sanish on our PDP reserve base and move more towards kind of that West Williston side, that shift is about another dollar. So dollar from the infrastructure, dollar from the shift in the portfolio mix and then another call it $2.50 or so from the increased cost in 2011.
Is there anything in from oilfield services? Yes, I mean, I should say Oasis is Oilfield Services. Is there any DD and A on those assets in there as well?
There will be a small impact, but that's not big right now.
That's that big right now. Okay, fair enough. And I guess my last question is on sort of rail versus pipeline. Obviously, it seems like you all have some pretty good flexibility. Can you give us a general sense of when you look at that optionality, what are the economics right now look like?
I mean, when you're doing it versus rail, what kind of pricing are you seeing there? And what's the transportation cost versus sort of the pipe to the sort of end market?
At this point, we're selling at points that are still kind of inside the basin. So overall, we're kind of getting to a blended price, but we're able to shift a little bit more towards rail when it's a little bit beneficial. But we're not talking about massive differences between pipe and rail. We're talking about a couple of dollars maybe differences in these rates. But we've got a pretty blended type system.
We've got over 20 marketers that we sell to even on the system. So it's spread out quite a bit and their rates vary a couple of dollars on each side.
So when we see some of
this pricing dislocation from WTI or Clearbrook to some of the waterborne prices, the marketers are going to take the majority of that. Is that a fair way to think of it?
As you keep I think as you have a constrained market, yes, they will continue to keep that. If the infrastructure continues to build as we've kind of seen in the last couple of months and we think we'll continue through the end of the year as more of that rail comes in and more of the pipe comes in, I think the producers will get a little bit more of that over time.
Okay. Appreciate the color. Thanks guys.
Your next question comes from the line of David Tamarone with Wells Fargo. Please go ahead.
Good morning. Most of the questions have been answered, but a couple on the cost side. And I guess you gave us some year end numbers, but what do you how should we think about the additional benefit from the disposal systems in the second quarter on the LOE side?
Yes, David. The 612 number, great number for us in the Q1. We still think that kind of towards the end of the year, we'll keep it in that $6 range. You may see the 2nd quarter come up a little bit. We were helped in that Q1 by some of the flush production that we got off of those 26 wells that we completed.
And early time when you get some of that flush production, it brings down your LOE costs on a per unit basis. So I'm not sure that you would see it necessarily trend in line from that $6.12 and continually go down from there. We do think we'll be in kind of better half of the $6 to $8 range for the year. But you may see it tick up a little bit in the Q2 before it starts trending back down towards the $6 range.
Okay. All right. And then on you may have said this, I missed it, but on the pad, what would that save on a well cost, on individual well costs?
Based on the work we've done so far, we think the pad drilling will save us on the order of 10% on our wells.
Okay. And then final question, you guys have previously talked about OWS and the, I guess, the amount of frac jobs you're saving or the amount per frac job that you're saving, I think before you previously indicated up to $1,000,000 of frac job. Is that still the right way to think about that once that gets up and running?
Yes. We'll probably see I mean that was early time data probably 9 months ago or so, obviously with availability of services continuing to improve and now prices starting to come down, we're going to lose some of that margin. But I don't know that we've got a good number to give you today on that.
All right. Go ahead, I'm sorry.
So currently, it's still within that range and it's probably going to come down a bit as the year goes on. Yes, makes sense.
Thanks. You bet.
Your next question comes from the line of Ron Mills with Johnson Rice. Please go ahead.
Good morning, guys. Just my question my remaining question is related to working interest. I think, Michael, you said that you were average I think 77% working interest in your 1st quarter wells and on the well backlog you have a 79% average working interest. How does that compare to what you budgeted? Because I think you were talking about 74, 75 net wells off of 108 gross.
Is that something that obviously that impacts your CapEx, but should also have a corresponding impact on production? Or is the first half of the year's working interest, is that overstated a little bit relative to what you're going to have in the second half?
Yes. So we did have around, like you said, Ron, around 70% budgeted for the year. And you're exactly right. As those working interest continue to increase, we should see not only capital go up, but also a production bump from that. And you saw some of that in the Q1 with our volumes being higher than our guidance range.
That seems like it will at least continue some at least into the Q2 from what we can see. There'll be higher working interest in our operated blocks. And it's just a little bit early to know how that the full year impact is going to be, which is why we're going to wait until the end of Q2 to give you full numbers on the capital side. But from a if you look at $25,000,000 for additional working interest as well as additional activity on the non op side, dollars 25,000,000 for that Q1 of kind of outside the budget work. If you actually saw that in the next three quarters, a similar number, call it, that $50,000,000 to $100,000,000 that Tommy was talking about of additional capital spend, all that would come with kind of associated additional production as well.
Okay. And but regardless given the first half average working interest is being the mid to upper 70% range, then your average for the year is clearly above the 68% or 70%. It's just a matter as to where it shakes out depending on how the I assume the non op activity comes in over the second half of the year?
Yes, that's correct. We didn't have a disproportionate amount of high working interest wells in the first half of the year and lower in the second half. So it should have been pretty blended at 70% throughout the year. So that 77% in the Q1 and 79% in our backlog does represent a bit of a growth over what we initially budgeted.
Okay, great. And just to push one question further just in terms of the Three Forks, you talked about differences between Red Bank, Hebron and Indian Hills. Taylor, what do you attribute most of the differences to? Is it organic content? Is it thickness?
Or is there something else that's kind of driving the difference between the 3 Forks and the Bakken?
It depends on the area, but in general thickness is important, quality of the rock in the Three Forks, the reservoir quality you see by area and water saturation. So those are all big components.
All right, guys. Thank you very much.
You bet, Ron.
Your next question comes from the line of Marcus Talbot with Canaccord Genuity.
I had just a few questions on OWS, if I could. I guess, after Taylor had mentioned you guys have worked on 5 jobs or so thus far, just curious as to where the spread is located in the basin and maybe how it's going to be moved around going forward if that's more a function of logistics and getting to the locations or could it depend on I guess your working interest in the wells?
It's we can use it anywhere in the basin and we've got still most of our activity on the west side of the basin. So it likely will frac a fair amount in that area, but we don't have it pegged to a certain type of well or working interest or anything of that nature at this point.
Okay. Good. And I guess you guys had touched on services being a little bit more available and well costs maybe reaching a plateau, how does that perspective compare with the first couple internal completions? Are those costs in line with the other wells? Or I guess how have those pressures changed from when you guys first set out on this priority?
Yes, we're still seeing significantly higher costs being charged by 3rd parties relative to what we can do with OWS. And so savings that we perceive to start out with are still there and very significant. Like I said, there's pressure on cost because of the increasing amount of equipment coming into the basin that's starting to erode a little bit, but still significant savings.
Okay. And I guess just based on that savings and it sounds like you'll be completing some higher working interest wells here, I guess, at least initially before the middle part of the year? Are you still thinking in terms of the payback period still 12 months or so?
It's probably going to be when we talked about that last year that was based on pricing at that time. So it was probably a little bit more than 12 months, I don't know if it's year and a half, but more than 12 months at this point.
Okay, great. And I guess just one more financial related question for me. Mike, you had sort of broken out the CapEx and what drove the near term increase here. There was, I think you said $25,000,000 carried over from 12. Is there can you itemize that or is that specific to anyone, I guess, expense?
No. I kind of broke it up in the $10,000,000 for infrastructure work and then $15,000,000 on the drilling completion side. And essentially, if you go through our budgeting process, the budget is essentially set and done in November. And so you have some work that we thought we'd complete in November December that actually got pushed into January February. So it's just a timing differential.
So that's why it wasn't initially in that 884.
Okay.
Great. Well, I appreciate the color guys. Thanks.
Your next question comes from the line of Tim Rezvan with Stern, Aegis. Please go ahead.
Yes. All my questions have been answered. Thank you.
Your next question comes from the line of Irene Haas with Wunderlich Securities. Please go ahead.
Yes. Hi. This has been a great spring exactly kind of opposite of last year. So it looks like between the weather and efficiency gains, you guys are doing great, better volume and getting more work done. So it looks like you probably get more done in 2012 than expected.
So my question for you is, is this an industry's trend and should we expect sort of a spike in crude production coming out of the Bakken? And if yes, how robust is the rail capacity to be able to handle that? And can you sort of hedge the differential just in case? And similarly, a question for the natural gas, great prices as such. Can you give us a little color as to how the rich gas is being processed and where do they end up?
So sure. On the oil side, given the mild winter, I think everybody is producing probably at a higher rate than expected. And you saw some of that in the February timeframe when things got pretty tight in the basin on the marketing side. Then what you saw and what we've been talking about is that there are a number of rail projects that are all built and ready to go and are actually moving volumes now. They're just not moving at their full capacity yet, but they're continually bringing on more and more of these unit trains.
And a lot of it was on the railcar side that they were a little slow getting those railcars in. As they're moving in more and more railcars, everybody's capacity is increasing. And it's really that momentum of some of the growth on the rail side that has brought the differentials back so quickly down from the $27 at Guernsey down to the $1.50 that we saw yesterday. So we think that will continue on the rail side. That capacity will continue to grow and should kind of normalize and reduce volatility in that differential side towards the end of this year and going into next year.
Next year in 2013, you see a lot of the pipe projects starting to come in as well. So once again, that will start to help reduce some of that volatility going forward. On the gas side, about 2 thirds of the $8 per Mcf that we get, 2 thirds of that piece is coming from the liquid side. Obviously, the liquid side still gets a significant benefit. This is 1500 BTU content gas.
A lot of all of our gas on the west side going through the Highland system, and that ultimately goes
to WIB and Northern Border.
And Alliance, there's 3 main systems we flow into.
Yes. So the gas will be essentially staying in sort of the Northern U. S. Is it consumed locally? That's really my question, dry gas and wet gas.
Some of it is consumed locally, but there is the Northern Border Pipeline goes more Midwest as does the Alliance pipeline. So, the amount of volume that's consumed in North Dakota is not real big.
So it goes west rather than coming to the Gulf Coast?
No, it goes to the Midwest. So more like Alliance goes to Chicago.
Oh, I sorry, sorry.
And in
Northern borders also the Midwest.
Got you. All right. One last question. Does the rail crude by rail, the final destination is the Gulf Coast, right, Or Cushing?
It's a mix. There's some that goes to Cushing, some that goes into the Gulf Coast. And I mean, there's even some going to the West Coast and the East Coast. But primarily you're still going towards kind of Cushing and then down to the Gulf Coast and most people are trying to focus on the premium markets.
Got you. Thanks so much.
Thanks Irene.
Your next question comes from the line of Peter Mahan with Dougherty. Please go ahead.
Good afternoon, guys. Just a couple of follow-up questions. This has to do with the proposed regulation of fracking proposed by the Obama administration. Do you guys are any of your leaseholdings on federal land? And do you envision this meaningfully impacting well costs if it were to be were to move forward in North Dakota?
Yes. The amount of federal land we have is minuscule. It's a very small amount. And as Taylor mentioned, the state has really taken control and been proactive on this. So, I mean, we have incurred we are going to incur incremental costs and have so far, but we think we're in pretty good shape.
And those regulations that I think went to effect in North Dakota on April 1, has the realized cost kind of met your expectations? I think people were talking about maybe $400,000 or $500,000 thereabouts. Is that pretty consistent with what you guys are seeing?
It's been generally in that range. And we think over time that we'll be able to work some of that impact down, but we've been able to offset it with other efficiencies in our drilling completion program.
Okay, perfect. Thank you guys.
You bet.
Your next question comes from the line of Scott Hanold with RBC Capital Markets. Please go ahead.
Hey, guys. Just a quick follow-up on sort of the frac crews. So just so I understand this right. Right now, you've got 3 outside frac crews and then the 1 OAS frac crew and you're going to let the one of the non OAS frac crews go and get back down to 3. Is that am I correct with that?
We've got 2 outside crews. We've already dropped the crew. So we've got 2 outside right now. And then with OWS, we have 3.
Okay. Understood now. And then in terms of like, just kind of the way to expect well completions, it seems like and correct me if I'm wrong here, in the Q2 because you're going to do some pad drilling and obviously the OAS fracture is not 20 fourseven right now. The wells that get completed in 2Q probably dropped dips down before it ramps back up in the back half of the year. Is that a fair way to look at it?
We'll still be probably, as I mentioned, probably somewhere in the 6 to 8 per month.
Okay. So you're looking basically to maintain sort of that well backlog around 26 to most of the year?
Yes. The way you need to think about that generally is it's typically about 2 times the rig count will be your general inventory number. So if we're at 10, that's 20. We've got a little bit more than that now because of some of the wells that need to be fixed. But you should expect that to come down and kind of normalize somewhere around 20.
Okay. Understood. Thanks.
There are no further questions at this time. I will turn the call back over to the presenters.
Yes. Thanks again for everybody's Yes. Thanks again for everybody's participation today. I appreciate all the hard work and focus on continuous improvement on the part of the Oasis employees, both in the office here in Houston and in the field. We appreciate the support that we continue to get from our strong shareholder base.