Chord Energy Corp (CHRD) 2012 Q1 法說會逐字稿

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 session. (Operator Instructions). 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 the 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'm joined by Tom 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 are 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 and thank you for joining us this morning. I will begin with some general comments and 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 are still working off of a relatively early timed data but with the exception of a couple of areas, it looks like we are 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 is getting our blocks held and figuring out well density, optimizing services, and realizing the cost benefit of building up infrastructure. By 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 is 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 interwell spacing so we are kind of 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 is extremely important to make sure that we capitalize the spacing units appropriately not having too many wells which would overcapitalize the unit or too few wells which would effectively not drain all of the oil that is there.

We will get this date the that later this year and we don't currently have any intention of accelerating activity in advance of having that data in hand. We have also done extensive work this year on optimizing services so that we have everything that we need to operate on our program which Taylor will describe in more detail in a minute. On infrastructure we have made tremendous progress on oil and gas gathering in 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 first quarter we produced a record average of 17,633 BOEs about per day an increase of near early 2400 BOEs per day or 16% over the fourth quarter of 2011.

As you know we originally guided production at 15,000 to 16,500 per day for the first quarter. We 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 first quarter of 2012. We have also driven the days to frac a well down by over a half and we are 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 are 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 two months. Production in March was approximately 18,700 BOEs per day but we would expect growth to moderate a bit here through the second quarter as we start drilling more pad wells. So 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 interests, 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 seconded quarter which we believe will be in the 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 but we plan on weighting until the end of the second quarter to do any further updating.

Michael will give you a little more color around that in a moment. We are 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 are attracting some very talented people across all functional groups to help us to continue to deliver on our plan. With that I will 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 in-fill tests in 2012. That activity will really start to pick up in the second quarter.

When you drill on pads we will typically drill all the wells before the frac crew shows up to start completing the wells. All tolled 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 eye 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 and 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 two external frac 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 in 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 ten rigs instead of the 12 that we have available. We will drop two of the rigs we had been running when the new build rigs show up allowing us to highdrate our rig fleet in preparation for pad work.

Easiest way to think about this is that we will stay flat at ten 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 had 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 made in terms of efficiency in cost reductions have been offset about 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 that are waiting on completion backlog which is where it was on both March 31 and April 30.

As we have addressed previously, the service bottle neck has been obtaining the work over rigs to work through the backlog of wells that need to be cleaned out or work over. We have one more work over rig showing up in May and a riglet which has more horsepower than a normal work over rig coming in June. We continue to be excited about our Three Forks program. On the east side, the Spratley Three Forks well and 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.

In addition 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 plan 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 will 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 volume will equalize. By year end we expect to have about 80% of our volumes going through our system and into our injection wells. We are making a lot of headway this year on driving down per barrel water disposal costs as you can see in our LOE numbers this quarter. Gas infrastructure is something that is moving quickly across the basin and most of our peers are well on their way to getting their wells tied in to it gas infrastructure.

In our case we move the bulk of our gas to highland. 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 about 60% of our oil production flowing through the Banner system. A big loop system on the west side of the base sin 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 we can optimize where our volumes go. We 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 will 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 tipped up to as much as 19% in March but 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 a 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 of that revenue drops to the bottom line since we have 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 $1.5 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 $1.00 to $1.50 per barrel given the impact of the oil gathering system was not for the full quarter.

On May 1 and 2 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 that we have 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 are 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 31 and we are up to $322 million 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 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 compare 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 and 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 $6.00 to $8.00 per BOE.

G&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% 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 are reserve portfolio towards the West Willston 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 interests 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 interest in wells we do not operate into wells that we are drilling on an operated basis. This resulted in swapping approximately 3700 net acres in the first quarter.

We also have working interests 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. 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 addict ional activity should result in higher production.

Finally on the non and 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 EDP 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 and 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 interests increases on our operated blocks. Overall we had a record quarter on many fronts and the first quarter has been a great way to begin the new year. With that we will turn the call over to Tracy to open the lines up for question hest.

(Operator Instructions). Your first question comes from the line of Neal Dingman with SunTrust. Please go ahead.

Good morning, guys. Two quick ones. You mentioned about going after the B bench on a well or two. I was wondering 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 are 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 in complete wells in the lower benches for this year.

Okay. And then just lastly, you know, I know there is some packages out there, just your thoughts on M&As or things that you are looking at either on -- I know there is some non-op pack ands being shopped around and if you are seeing any operative, are you looking at any on the M&A side?

Last year we looked at I think 16 packages and we continue to see deal throw out 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 that we would like to see how that plays out.

Okay. Thank you for the color.

You bet.

The next question comes from the line of Brian Langley with Tudor Pickering. Please go ahead.

Hi, good morning.

Good morning.

Tell me he your comments on potentially raising production and 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 are seeing the higher EURs on the wells with more stages and costs continue to kind of hold the line from the per well basis. Can you provide some commentary on it from that standpoint.

Yeah, as Michael mentioned we had about $50 million which -- that basically is first quarter that -- money that we know we are going to spend incrementally. And basically what that does is drives 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, you know, incrementally it could be another over and above the 50 it could be another $50 to $100 million but we will have to see how that plays out. With that obviously 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 the Cottonwood and I don't mean the B bench, 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 have learned on sweet spots for the Three Forks versus the middle Bakken and kind of how we should think about that from an overall resource standpoint?

If you look at where we have tests 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 have got some, as we mentioned Three Forks wells that are better than Bakken wells. But on average I think across that position they are at least equal. As you go to the northern portion of the block we just don't have the Three Forks test with greater frac intensity.

We have older tests with sliding sleeves so we will drill those two 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 as compared to the Bakken there is not quite as good so it is probably 80% of Bakken well in the Three Forks at least at this point kind of in Indian hills area. And then in red bank and Hebron it is still early days in terms of testing the Three Forks in those areas.

So there is not an overall concept are where the middle Bakken is good and Three Forks is good, just a different I guess an evolving concept in your all's mind?

It really depends on area. You see variable between Bakken and Three Forks depending on where you are and 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?

So you are talking about purchasing pipe relative --

No, I'm just saying Michael said that 50 or so percent of the volume that you sold was in rail versus pipe and I'm just wondering what the ability is to flex that real time?

A lot of our marketing volumes are still done on a month-to-month basis, Brian. So the system that we have got in place, the gathering system actually gives us a lot more flexibility. If you look at that system it has access to a lot more -- so six different rail sites, three different pipe sites. Gives us a lot more flexibility and a lot of our volumes are now on that system. On a month so month basis we can start to actually move some of those volumes around a little bit more. Once again, we are 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 first quarter when differentials blew out a little bit.

But does that minimize you think the volatility at least a little bit going forward on the swings we have seen in differential's?

There is still going to be potentially some volatility there and while it certainly minimizes or reduces it some from where we were six months ago there is still going be volatility. If you have enbridge blow out like you did a year and a half ago you would still have issues in the basin.

All right. Thanks, guys.

Your next question comes from the line of Dave Kistler with Simmons & 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 utilization's 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 drill?

So we have -- as we have stated we have initiated fracking. We have actually fracked five wells. Four of those were actually partial wells where we didn't complete a frac previously and we he came back and finished stages. The last well, the fifth well, was actually a complete frac on a well. So we are improving the efficiency of the operation. We are still staffing the crew. We have got a little over 30 employees in OWS right now. We think by June we will 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 will have three frac crews so as you get into third and fourth quarter they should be doing at least a third of our frac work.

Okay. That is helpful. Appreciate it. And then with respect to kind of the drilled uncompleted backlog and the issue with clean outs, et cetera, have you guys had any structural issues with those wells that you have been waiting to either complete or that have been completed and waiting to tie in? Just kind of curious if there is any degradation between drilling, completing and time to tie in?

No. I think overall we have 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 will continue to work that down. There is --

Okay --

Yeah.

But 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 I guess wells that are completed ready to be tied in relative to wells that are smoothly start to finish done?

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 what not throughout this year, can you just articulate of the 80 some odd wells you are looking at what percent are going to be pad versus what are just going to be individual wells?

Well, it is probably for this year --

About a third.

About a third. But you know, going forward really all of our -- even if we are not drilling a pad, one well in each direction, you are 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. But roughly a third nor year.

That's helpful. I appreciate the clarifications, guys.

You bet.

Your next question comes from the line of Scott Hanold with RBC Capital market. Please go ahead.

Thanks, good morning. Good morning, Taylor. Taylor, you mentioned that continue on the pad drilling something to the effect of there is generally a two month sort of lag once you start getting the pad development. Is that sort of what you would imply is short of a short-term as you start developing this you will see a little bit of a lag or is this an ongoing thing we are going to look at and sort of how do you when you think about 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 is going to take a little more into development mode into 2013?

You going to have -- it 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 it will effectively smooth out. The early time wells we may go to simultaneous operations over time doing more simultaneous operations. And so it will smooth out as you get into 2013.

O Kay but this is something -- I guess most of the quarters going forward we should actually expect some impact from moving into pad development is that a fair statement?

Yes, there will probably be a little bigger impact in the second quarter but you will see that in all of the quarters of this year. Understood. And also on the DD&A obviously you indicated DD&A came up this quarter. I'm hearing a little bit of mixed message where it sounds like there are some efficiencies coming into place and some costs that you are seeing coming down but obviously the DD&A rate jumped a fair amount quarter over quarter. Is -- in that DD&A is there anything relative to -- what was like E&P DD&A versus all other stuff? Can you separate that as well as a percent of it?

That is a good question, Scott. From the DD&A side it is Two things. One, it as 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 were 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 of 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 dollar impact from the saltwater disposal infrastructure like you were talking about. It is about a dollar impact to the DD&A rate. And you probably had another around a dollar impact from just shifting volumes as we move away from the impact of Sandish on our crude PDP reserve base and move more towards kind of that west Williston side that shift is about another a dollar. A dollar from the infrastructure. A $1.00 in the shift in the portfolio mix. And then another call it $2.50 or so from the increased costs in 2011.

Is there anything in oil field services? I mean I should say Oasis' oil field services is there any DD&A on those assets in there as well?

There will be a small impact but that is not big right now.

That is not 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 optionally what do the economics right now look like when you are doing it versus rail? What kind of pricing are you seeing there and with the transportation costs versus sort of the pipe to the sort of the end market?

At this point we are selling at points that are still kind of inside the basin. So overall we are kind of getting to a blended price but we are able to shift a little bit more towards rail when it as little beneficial but we are not talking about massive differences between pipe and rail. We are talking about a couple dollars maybe differences in these rates. But we have got a pretty blended type system. We have over 20 marketers that we sell to even on the system. So it is spread out quite a bit and their rates vary a couple of dollars on each side.

When we see the pricing dislocation from WTI or clearbrook to some of the water born prices the marketers are going to it 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 they will continue to keep that. If the infrastructure continued to build as we kind of see in the last couple of months and we think we will continue through the end of the year as more of that rail comes in more of the pipe comes in I think the producers will get a little more of that over a period of time.

I appreciate that color. Thanks, guys.

The next question comes from the line of David Tameron 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.

David, the $6.12 number, great number for us in the first quarter. We still think that kind of towards the end of the year we will keep it in the $6.00 range. You may see the second quarter come up a little but we were helped in that first by some of the flush production we got off of those 26 wells that we completed and early time when you get some of that flush production it brings down the LOE costs on a per unit basis. I'm not sure that you would see it necessarily trend in line from the $6.12 and continually go down from there. We do think we will be in the better half of the $6 to $8 range for the year but you may see it tick up a little bit in the second quarter before it starts trending back down towards that $6.00 range.

Okay. Then you may have said that but I missed it, on that pad what would it save on the well costs, on individual well costs?

Based on the work we have 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 are saving or the amount per frac job that you save I think before you previously indicated up to a million dollars a frac job. Is that still the right way to think about that once that gets up and running?

We will probably see -- I mean 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 he are going to lose some of that margin. But I don't know that we have got a good number to give you today on that.

All right.

That's all I have. Go ahead, I'm sorry.

Currently it is still wing that range and probably going come down a bit as the year goes on.

Makes sense. Thanks.

You bet.

Your next question comes from the line of Rob Mills with Johnson Rice. Please go ahead.

Good morning, guys. My remaining question is related to working interest. I think, Michael, you said that you were averaged 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 because I think you were talking about 74 or 75 net wells off of 108 gross. Is that something that obviously that impacts your CapEx but you 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 are going to have in the second half?

Yeah, so we did have around like you said Ron around 70% budgeted for the year. And you are exactly right as those working interests 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 first quarter with our volumes being higher than our guidance range. That seems like it will at least continue some at least into the second quarter from what we can see there will be higher working interests in our operated blocks.

And it is just a little bit early to know how the full year impact is going to be which is why we are going to wait until the end of the second quarter to give you full numbers on the capital side. But from if you look at $25 million for additional working interests as well as additional activity on the non-op side, $25 million for that first quarter of kind of outside o the budget work if you actually saw that in the next three quarters a similar number call that 50 to 100 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 as being in the mid to upper 70% range then your average for the year is clearly above the 68% or 70%, it is just a matter as to where is shakes out depending on how I assume the non-op activity comes in over the second half of the year.

That's correct. We he didn't have a disproportionate amount of high working interest wells in the first half of the year and higher in the second half. It should have been blended at 70% throughout the year. So that 77% in the first quarter and 79% in our backlog does represent a bit of a growth over what we he initially budgeted.

Okay. Great. And just to push one question further, just in terms of the Three Forks, you talked about differences between Redburn and Bakken and Indian hills. What do you attribute most of the differences to? Is it organic content? Is it thickness? Or is it -- is there something else that is kind of driving the difference between the Three Forks and the Bakken?

You know, it depends on the area, but in general thickness is important, quality of the rock in the Three Forks, the reservoir quality that you see by area and water saturations. Those are all big components.

All right. Guys, thank you very much.

You bet, Ron.

Your next question comes from the line of Marcus Talbert with Canaccord Genuity. Please go ahead.

Hi, guys. Good morning.

Good morning.

I had just a few questions on OWS, if I could. I guess you know after Taylor had mentioned you guys had worked on five jobs or so thus far just curious as to where the spread is located in the basin and maybe how it is going to be moved around going forward if that is more a function of low ticks and getting -- logistics and getting to locations or could it depend on I guess your working interest in the wells?

You know, we can use it anywhere in the basin and we have got still most of our activity on the west side of the basin so it is likely we will frac a fair amount in that area with you we don't have a pegged a certain type of well or working interest or anything of that nature at this point.

Okay. And I guess you guys had touched on, you know, 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 sat out -- first set out on this priority?

We are still seeing significantly higher costs being charged by third 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 is pressure on cost because of the increasing amount of equipment coming into the basen that is starting to erode a little bit but still significant savings.

Okay. And I guess just based on that savings and it sounds like you will 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 is 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, a year and a half but more than 12 months at this point.

Okay. Great. And I guess just one more financial related question for are 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. Is there -- can you itemize that or is that specific to any one I expense?

No, I kind of broke it up into $10 million for infrastructure work, and then $15 million 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 would completed in November and December and that actually got pushed into January and February so it is just a timing differential. So that is 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 Resbin with Stern Agee. Please go ahead.

All of 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 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 looks like you are probably going to get more than in 2012 than expected. 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 if 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?

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 time frame when things got pretty tight in the basin on the marketing side. Then what you saw and what we he have 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 are just not moving at their full capacity yet but they are continually bringing on -- at their full capacity yet but they are continually bringing on more and more of the unit traps and a lot was on the rail car side that they were a little slow getting the rail scars in. As they are moving in more and more cars everybody's capacity is increasing and it is really the momentum of some of the growth on the rail side that has brought the differentials back so quickly from the $27 at Guernsey down to the $1.50 that we saw yesterday. We think that will continue on the rail side, that capacity will continue to grow and should kind of normalize and reduce volatility on the 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 then that will start to help reduce some of that volatility going forward. On the gas side about two thirds of the $8.00 per Mcf that we got, two thirds of that piece is coming from the liquids side. Obviously the liquid side still gets a significant benefit. This is 1500 btu content gas. All of our gas on the west side going through the Highland system and that ultimately goes to WIB and alliance.

There is three main systems we flow into.

Yeah, so the gas will be essentially staying in sort of the northern US, consumed locally, that is 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. To the amount of volume that is consumed in North Dakota is not really big.

So it goes west rather than coming to the gulf coast.

No, it goes to the Midwest so more like alliance coast to Chicago.

I'm sorry, okay.

And northern borders also the Midwest.

Got you. All right. One last question. The rail crude by rail the final destination is the gulf coast, right?

It is a mix. There is some that goes to and some that goes into the gulf coast and even some going to the west coast and the east coast. Primarily you are still going kind of towards Cushing and 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 Mahone 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 pro posed by the Obama administration. Do you guys, are any of your lease holdings on federal land and do you envision this meaningfully impacting well costs if it were to be -- were to move forward in north Dakota?

The amount of federal land we have is miniscule, it is a very small amount and as Taylor mentioned the state is really taking control and been proactive on this. So and we have -- we are going to incur incremental costs and have so far. But we think we are in pretty good shape.

And those regulations that I think went into 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, there abouts. Is that pretty consistent with what you guys are seeing?

It has been -- it has been generally in that range. And we think over time that we will be able to work some of that impact down but we have 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 market. Please go ahead.

Just a quick follow-up on the frackers. Just to understand this right. Right now you have got three outside frackers and then the one OES fracker and you are going to let the one non-OES fracker and go back down to three. Am I correct about that?

We have already dropped a crew so we have two outside right now and then with OWS we have three.

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 second quarter because you are going to do pad drilling and obviously the OES frac crews are not 24/7 right now, the wells that get completed in Q2 probably drops, dips down before it ramps back up in the back half of the year? Is that a fair way to look at it?

No, we will still be probably as I mentioned probably some where in the 6 to 8 per month.

Okay. So you are looking basically so maintain to that well backlog around 26 through most of the year.

Yeah, the way you need to think about that. Generally is it is typically about two times the rig count will be your general inventory number. So if we are at 10 that is 20. We have 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 some where around 20.

Okay. Understood. Thanks.

There are no further questions at this time. I will turn the call back over to the presenters.

Thanks again for everybody's participation today. Appreciate all of 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.