Good morning. My name is Tracy. 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 speaker's remarks, there will be a question and answer session. If you would like to ask a question during this time, simply press star, then the number 1 on your telephone keypad. If you would like to withdraw your question, press the pound key. Thank you. 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, Tracy. Good morning, everyone. This is Michael Lou. We are reporting our first quarter 2012 results. We are delighted to have you on our call. I am joined today by Tommy Nusz 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-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 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 will now turn the call over to Tommy.
Good morning. Thank you for joining us this morning. I will begin with some general comments, then turn the call over to Taylor and Michael to cover more detail on operations and financial highlights. In 2011, our focus was on acreage consolidation in 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 and 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. With the exception of a couple of areas, it looks like we're realizing from 17%-31% increases. 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 and 2016, so easily manageable.
Additionally, we will be drilling in excess of 30 wells to test inter-well spacing. We're in a transition year from holding all of our acreage blocks to going to 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 services so that we've got everything that we need to operate on our program, which Taylor will describe in more detail in a minute. 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 cost and increasing our profit margins. For the first quarter, we produced a record average of 17,633 BOEs per day, an increase of nearly 2,400 BOEs per day or 16% over the fourth quarter of 2011. As you know, we originally guided production at 15,000-16,500 per day for the first quarter. We had planned for a normal cold winter and expected to complete around 16-18 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 first quarter of 2012. We've also driven the days to frack a well down by over a half, and we're around five days per well in the first quarter. Our spud to first production decreased from an average of 110 days in 2011 to under 70 days in the first quarter. 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 80-90-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 eight wells on in April, which is basically at the high end of our expectations for completions by month, and we would expect bringing on six to eight wells in each of the next two months. Production in March was approximately 18,700 BOEs per day. We would expect growth to moderate a bit here through the second quarter as we start drilling more pad wells. No surprise, our capital spend in the first quarter 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 second quarter, 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 first quarter results. 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 first quarter 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 second quarter. When you drill on pads, a rig will typically drill all of the wells before the frack crew shows up to 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. This has been baked into our plan all along. 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 frack 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. We currently stand at two external frack spreads. At the same time, we are ramping OWS, which will be operating 24/7 at the end of the second quarter. 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 two 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. The 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 million 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 31st and April 30th. 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 one 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 Spratley 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 first 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 first 130 days. We have planned two more Three Forks wells in East Nesson this year, north of our Spratley and Caspian wells. One will be in the center of the East Nesson block, and one will be one 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 west side this year.
On the infrastructure front, about 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% 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 Hiland.
Last year, if you look at the end of the summer, our total net gas production into sales was about 2 million cubic feet per day. That number today is about 10 million 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 that we can optimize where our volumes go. We've connected 91 wells so far on the oil side.
We are also working with third parties on connecting wells in our East Nesson 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 first quarter, 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, 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 $27 in February. In April, we had about 60% of our volumes moving by rail, and we continue to have about a 50/50 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 8.6 million cubic feet per day average in the first quarter and over 10 million per day in March. Importantly, all that revenue drops to the bottom line since we've already covered the cost 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 $1.5 million with associated costs of $1.4 million. This is not part of our day-to-day plans, but the $1.4 million 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 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 1st 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, we put on about 2,000 barrels a day at $97.50 by 114 for the back half of 2012, 2,000 barrels a day at 95 by 111 in 2013, and another 2,000 barrels a day of three-way with $20 put spreads and average collars of $92.50 by 114.40 for 2014. We continue to hedge a little more aggressively in 2012 and 2013 as we drill up our acreage and outspend cash flow. In the first quarter, we had adjusted EBITDA of $101 million, a growth of 18% over the fourth quarter of 2011. We had $287 million of cash on the balance sheet as of March 31st, we're up to $322 million in cash and investments as of May 1st.
Finally, addressing our total liquidity, our borrowing base, which is fully undrawn, was increased in early April to $500 million, leaving us with total liquidity north of $800 million to invest in the business. In the first quarter of 2012, LOE averaged just $6.12 per BOE, a reduction of $2.10 per BOE compared to the fourth 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. Our higher production, coupled with a milder winter, helped on a per unit basis. Given results to date in our infrastructure system, we expect to trend more towards the lower half of our 2012 range of $6 to $8 per BOE.
DD&A costs have trended up in line with projections as we've 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% of revenue, which is a bit better than originally projected. DD&A rates are up as well due to 2011 well cost increases and a 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 and production in the first quarter. We spent $288 million in the first quarter, which included about $50 million of capital associated with activity, which is not part of our $884 million budget. Of that $50 million, $25 million was associated with higher working interest in our operated wells and increased activity on the non-operated side.
The other $25 million was due to one-time costs originally anticipated for 2011 that was carried over to 2012, including $10 million for infrastructure and $15 million 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 interests 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 first quarter. 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 first quarter, as well as additional spending in future quarters.
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. On the non-E&P capital side, as expected, we had $21 million of the $38 million capital budgeted for this year occurring in the first quarter, mainly related to OWS activity being brought into 2012. In all, adjusting for the $50 million spent above the $884 million budget in the first quarter and the timing of non-E&P capital, we completed about a quarter of our expected work for the year in the first quarter and spent about a quarter of our budget.
We know that the capital will be a bit higher for the year, we will update you with a revised capital budget after the second quarter 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, the first quarter 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.
At this time, I would like to remind everyone, in order to ask a question, press star, then the number one on your telephone keypad. Your first question comes from the line of Neal Dingmann with SunTrust. Please go ahead.
Morning, guys. Just two quick ones. As far as you mentioned about going after the B Bench on a well or two, is one of your plans going forward as far as 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. Just lastly, I know there's some packages out there, just your thoughts on M&As or things that you're looking at, either I know there's some non-op packages being shopped around, and if you're seeing any operated, are you looking at anything on the M&A side?
Yeah. 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. 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.
Morning.
Tommy, your comments on potentially raising production in CapEx sometime around mid-year 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 hold the line from a per well basis. Can you provide some commentary on it from that standpoint?
Yeah. As Michael mentioned, we had about $50 million, that basically is first quarter, the money that we know we're going to spend incrementally. Basically what that does is drive us or 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. Incrementally, over and above the $50, it could be another $50 million to $100 million, we'll have to see how that plays out. Again, with that, obviously, if we have that incremental number or incremental amount of capital, 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, I don't mean the B bench, I just mean the normal Three Forks.
Right.
What are you guys seeing from a geologic standpoint, maybe just compare and contrast what you've learned on sweet spots for the Three Forks versus the Middle Bakken, just how we should think about that from a overall resource standpoint.
If you look at where we have tests in the Three Forks is really the most southern portion of Cottonwood. The Three Forks and Bakken, in general, in that area are pretty comparable. We've got some, as we mentioned, Three Forks wells that are better than Bakken wells. 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 tests with sliding sleeves. We'll drill those two wells this year and have them tested by end of the year in the Three Forks on the northern position. Over on the west side in Indian Hills, we have a number of tests that confirm economics in the Three Forks.
The Three Forks as compared to the Bakken there is not quite as good. It's probably 80% of a Bakken well in the Three Forks, at least at this point, in Indian Hills area. In Red Bank and Hebron, it's still early days in terms of testing the Three Forks in those areas.
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 Osborn?
Yeah, 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 from me. Michael, this might be for you. What is your ability to flex your well and pipe volumes just based on spot prices?
You're talking about purchasing pipe relative-
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.
Yeah. A lot of our marketing volumes are still done on a month-to-month basis, Brian, 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, a lot of our volumes are now on that system. 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. We were able to move a little bit more towards rail because of better pricing over the back part of that first quarter when differentials blew out a little bit.
Does that minimize, you think, the volatility at least a little bit going forward on the swings we've seen in the differentials?
Yeah, there's still going to be potentially some volatility there. While it certainly minimizes or reduces it some from where we were six months ago, there's still going to be volatility. If you had Enbridge blow out like you did a year and a half ago, you'd still have issues in the basin.
All righty. Thanks, guys.
Your next question comes from the line of Dave Kistler with Simmons & Company. Please go ahead.
Morning, guys.
Morning, Dave.
Real quickly on OWS, can you talk a little bit about where you are on current utilizations of that crew and your projected run rate for those guys throughout the year, given that you had a willingness to drop another frac crew?
As we've stated, we've initiated frac, and we've actually fracked five wells. Four of those were actually partial wells, where we didn't complete a frac previously, and we came back and finished stages. The last well, the fifth well, was actually a complete frac on a well. 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 24/7, and then going at full capacity. In terms of utilization, we'll have three frac crews. As you get into third and fourth quarter, they should be doing at least a third of our frac work.
Okay. That's helpful. Appreciate it. With respect to the drilled uncompleted backlog and the issue with cleanouts, et cetera, 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 curious if there's any degradation 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. The backlog is really still around the cleanout operation, and as we bring on more cleanout rigs, we'll continue to work that down.
Okay.
Yeah.
No structural issues while those are waiting to be either cleaned out or tied in. I guess what I'm asking 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?
Yeah, we don't think so, Dave.
Okay. That's helpful. 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 % are going to be pad versus what are just going to be individual wells?
Oh, it's probably for this year.
It's about a third.
About a third. Going forward, really, 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 off the same pad. Roughly a third for this year.
Okay. That's helpful. I appreciate the clarification, guys.
You bet.
Your next question comes from the line of Scott Hanold with RBC Capital Markets. Please go ahead.
Thanks. Good morning.
Morning.
Hey, Taylor. You had mentioned that, continuing on the pad drilling, something to the effect of there's generally a two-month lag once you start getting the pad development. Is that what you'd imply is a short term, as you start developing this, you'll see a little bit of a lag, or is that an ongoing thing we're going to look at? When we look at 2012, how should we think about 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?
Yeah. It's going to be choppy for this year. Once we get into full pad operations with all of our rigs, or most of them drilling on pad operations, it'll effectively smooth out. The early time wells, we may go to simultaneous operations over time, doing more simultaneous operations. It'll smooth out as you get into 2013.
Okay, but this is something, I guess, most of the quarters in 2012, we should actually expect some impact from moving into pad development. Is that a fair statement?
Yes, most of the impact. There'll probably be a little bigger impact in the second quarter, but you'll see some of that in all the quarters of this year.
Okay, understood. Also on the DD&A, obviously, you indicated DD&A came up this quarter, and I'm 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. Obviously, the DD&A rate jumped a fair amount quarter-over-quarter. In that DD&A, is there anything relative to the what was E&P DD&A versus all other stuff? Can you separate that as well as a component of it?
Sure. That's a good question, Scott. From the DD&A side, it's two things. One, it is a bit in hindsight, right? Some of the 2011 cost increases that we talked about all last year are in those numbers now, whereas they hadn't been before. Those costs, remember, in 2010, more like $8.5 million. They got to about $10 million 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 the early time data looks good. It was still early time, especially at year-end, when we set those reserves. You also had about a $1 impact from the saltwater disposal infrastructure like you were talking about.
It's about a $1 impact to the DD&A rate. You probably had another around a $1 impact from just shifting volumes as we move away from the impact of Sanish on our proved PDP reserve base and move more towards that West Williston side. That shift is about another $1. A $1 from the infrastructure, a $1 from the shift in the portfolio mix, and then another, call it $250 or so from the increased cost in 2011.
Is there anything from oil field services? I should say Oasis' oil field service. Is there any DD&A on those assets in there as well?
There will be a small impact, but that's not big right now.
That's not big right now. Okay, fair enough. I guess my last question is on 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 do the economics right now look like? When you're doing it versus rail, what kind of pricing are you seeing there, and what's the transportation cost versus the pipe to the end market?
At this point, we're selling at points that are still inside the basin. Overall, we're getting to a blended price, but we're able to shift a little bit more towards rail when it's a little bit beneficial. We're not talking about massive differences between pipe and rail. We're talking about a couple of dollars maybe differences in these rates. We've got a pretty blended type system. We've got over 20 marketers that we sell to even on this system. It's spread out quite a bit, and their rates vary a couple of dollars on each side.
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?
I think as you have a constrained market, yeah, they will continue to keep that. If the infrastructure continues to build as we've seen in the last couple of months and we think will 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 that color. Thanks, guys.
Your next question comes from the line of David Tameron with Wells Fargo. Please go ahead.
Morning. Most of the questions have been answered, but a couple on the cost side. I guess you gave us some year-end numbers, but how should we think about the additional benefit from the disposal systems in the second quarter on the LOE side?
Yeah, David, the $6.12 number, great number for us in the first quarter. We still think that towards the end of the year, we'll keep it in that $6 range. You may see the second quarter come up a little, we were helped in that first quarter by some of the flush production that we got off of those 26 wells that we completed. Early time, when you get some of that flush production, it brings down your LOE costs on a per unit basis. 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 the better half of the $6-$8 range for the year.
You may see it tick up a little bit in the second quarter before it starts trending back down towards that $6 range.
Okay. All right. You may have said this, and 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. Final question. You guys had previously talked about OWS and, 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 million a frac job. Is that still the right way to think about that once that gets up and running?
Yeah, we'll probably see That was early time data, probably nine 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. I don't know that we've got a good number to give you today on that.
All right.
I think currently.
Go ahead. I'm sorry.
Currently, it's still within that range, and it's probably going to come down a bit as the year goes on.
Yep, makes sense. Thanks.
Yeah.
Your next question comes from the line of Ron Mills with Johnson Rice. Please go ahead.
Morning, guys. My remaining question is related to working interest. I think, Michael, you said that you were average, I think, 77% working interest in your first quarter wells, and on the well backlog, you have a 79% average working interest. How does that compare to what you budgeted? 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? 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?
Yeah. We did have around, like you said, Ron, around 70% budgeted for the year. You're exactly right. As those working interests continue to increase, we should see not only capital go up, but also a production bump from that. You saw some of that in the first quarter with our volumes being higher than our guidance range. That seems like it'll at least continue some, at least into the second quarter from what we can see. There'll be higher working interest in our operated blocks. It's just a little bit early to know how the full year impact is going to be, which is why we're going to wait until the end of the second quarter to give you full numbers on the capital side.
If you look at $25 million for additional working interest, as well as additional activity on the non-op side, $25 million for that first quarter of outside-the-budget work. If you actually saw that in the next three quarters, a similar number called that $50 million-$100 million that Tommy was talking about of additional capital spend, all that would come with associated additional production as well.
Okay. Regardless, given the first half average working interest is being in the mid to upper 70% range, 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, I assume, the non-op activity comes in over the second half of the year.
Yeah, 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. It should've been pretty blended at 70% throughout the year. That 77% in the first quarter and 79% in our backlog does represent a bit of a growth over what we initially budgeted.
Okay, great. 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 driving the difference between the Three 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. Those are all big components.
All right. Guys, thank you very much.
Bye, Ron.
Your next question comes from the line of Marcus Talbert with Canaccord Genuity. Please go ahead.
Hi, guys. Good morning.
Morning.
I had just a few questions on OWS, if I could. I guess, after Taylor had mentioned you guys have worked on five 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?
We can use it anywhere in the basin. We've got still most of our activity on the west side of the basin, it likely will frack 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. 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?
Yeah, we're still seeing significantly higher costs being charged by third parties relative to what we can do it with OWS. Savings that we proceed 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 a significant savings.
Okay. 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's probably a little bit more than 12 months. I don't know if it's a year and a half, but more than 12 months at this point.
Okay, great. 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 million carried over from 2012. Can you itemize that, or is that specific to any one, I guess, expense?
No, I broke it up into $10 million for infrastructure work and then $15 million on the drilling completion side. Essentially, if you go through our budgeting process, the budget's essentially set and done in November. You have some work that we thought we'd complete in November and December that actually got pushed into January and February. It's just a timing differential. 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 Sterne Agee. Please go ahead.
Yeah, all my questions have been answered. Thank you.
Your next question comes from the line of Irene Haas with Wunderlich Securities. Please go ahead.
Yeah. Hi. This has been a great spring, exactly opposite of last year. It looks like between the weather and efficiency gains, you guys are doing great, better volume and getting more work done. Look like you're going to probably get more done in 2012 than expected. My question for you is this an industry trend, and should we expect sort of a spike in crude production coming out of the Bakken? If yes, how robust is the rail capacity to be able to handle that? Can you sort of hedge the differential just in case? 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?
Sure, on the oil side, given the mild winter, I think everybody is producing probably at a higher rate than expected. You saw some of that in the February timeframe when things got pretty tight in the basin on the marketing side. 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 rail car side that they were a little slow getting those rail cars in.
As they're moving in more and more rail cars, 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. We think that'll continue on the rail side, that capacity will continue to grow and should 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. Once again, that'll start to help reduce some of that volatility going forward. On the gas side, about two-thirds of the $8 per Mcf that we get, two-thirds of that piece is coming from the liquid side. Obviously, the liquid side still gets a significant benefit.
This is 1,500 BTU content gas. All of our gas on the west side going through the Hiland system, and that ultimately goes to-
WIB or-
WIB-
Northern Border
Northern Border.
Alliance. There's three main systems we flow into.
Yeah. 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, there is the Northern Border Pipeline goes more Midwest, as does the Alliance Pipeline. The amount of volume that's consumed in North Dakota is not real big.
It goes west rather than coming to the Gulf Coast.
No, it goes to the Midwest, more like Alliance goes to Chicago.
Oh, I sorry. Okay.
Northern Border is also the Midwest.
Gotcha. All right. One last question. The rail, crude by rail, the final destination is the Gulf Coast, right? Cushing.
It's a mix. There's some that goes to Cushing, some that goes into the Gulf Coast, and there's even some going to the West Coast and the East Coast. Primarily, you're still going towards Cushing and then down to the Gulf Coast, and most people are trying to focus on the premium markets.
Gotcha. 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. Are any of your lease holdings on federal land, and do you envision this meaningfully impacting well costs if it were to move forward in North Dakota?
Yeah. The amount of federal land we have is minuscule. It's a very small amount. As Taylor mentioned, the state has really taken control and been proactive on this. We are going to incur incremental costs and have so far. We think we're in pretty good shape.
Those regulations that I think went into effect in North Dakota on April 1st, has the realized cost 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. 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
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. Just so I understand this right now you've got three outside frac crews and then the one OAS frac crew, and you're going to let one of the non-OAS frac crews go and get back down to three. Am I correct with that?
We've got two outside crews. We've already dropped a crew.
Okay.
We've got two outside right now, and then with OWS, we have three.
Okay, understood now. In terms of just the way to expect well completions, it seems like, and correct me if I'm wrong here, in the second quarter, because you're going to do some pad drilling, and obviously the OAS frac crew's not 24/7 right now. The wells that get completed in 2Q probably 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 six to eight per month.
Okay. You're looking basically to maintain that well backlog around 26 through most of the year?
Yeah. The way you need to think about that generally is, it's typically about two times the rig count will be your general inventory number. 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.
Okay.
You should expect that to come down to, and 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.
Yeah. Thanks again for everybody's participation today. 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.
This concludes today's conference call. You may now disconnect.