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Unit Corporation (NYSE:UNT)

Q1 2012 Earnings Call

May 1, 2012 11:00 am ET

Executives

Larry Pinkston - President, CEO & COO

Brad Guidry - SVP, Exploration - Unit Petroleum Company

Bob Parks - Manager & President, Superior Pipeline Company

John Cromling - SVP, Drilling Operations

David Merrill - CFO & Treasurer

Analysts

Marshall Adkins - Raymond James

Brad Evans - Heartland Funds

Operator

Welcome to the Unit Corporation first quarter 2012 earnings conference call. My name is John and I will be your operator for today’s call. At this time all participants are in a listen-only-mode. Later, we will conduct a question-and-answer session. Please note that this conference is being recorded.

This conference call contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act. All statements other than statements of historical facts included in this call that address activities, events, or developments that the company expects or anticipates will occur or may occur in the future are forward-looking statements.

A number of risks and uncertainties could cause actual results to differ materially from these statements, including the impact that any decline in wells being drilled will have on production and drilling rig utilization; the productive capabilities of the company's wells, including the ability of recently completed wells to maintain their initial rate of production or their projected rate of production; future demand for oil and natural gas, future drilling rig utilization and day rates; projected or anticipated growth of the company's oil and natural gas production; oil and gas reserve information, as well as the ability to meet future reserve replacement goals; anticipated gas gathering and processing rates, and throughput volumes; the prospective capabilities of the reserves associated with the company's inventory of future drilling sites; anticipated oil and natural gas prices; the number of wells to be drilled by the company's exploration segments; development, operational, implementation and opportunity risks; possible delays caused by limited availability of third-party services needed in the course of its operations; possibility of future growth opportunities and other factors described from time to time in the company's publicly available SEC reports. The company assumes no obligation to update publicly such forward-looking statements whether as a result of new information, future events or otherwise.

I will now turn the call over to Mr. Larry Pinkston, President and CEO. Mr. Pinkston, you may begin.

Larry Pinkston

Thank you, John. Good morning everyone. I want to thank you for joining us this morning. With me today are David Merrill, Brad Guidry, John Cromling and Bob Parks. Each of these gentlemen will be providing you with updates concerning their segments in a few minutes. We will take questions after their comments.

We released our first quarter results this morning. We reported net income of $52.4 million and earnings per share of $1.09. This represents a 28% increase in net income and a 27% increase in earnings per share as compared to the first quarter of 2011. Net income in the first quarter was basically flat with the fourth quarter, which was quite an achievement considering natural gas spot prices were down 26% and natural gas liquids spot prices were down 15% in the first quarter.

Our Contract Drilling segment had a very good quarter especially considering all the movement of rigs out of the dry gas producing formations. Rig utilization was basically flat with the fourth quarter averaging 81.5 rigs for the first quarter. During the first quarter, we sold one of our smaller mechanical rigs and added a new 1500 horsepower rig into our Wyoming operation at Pineville.

We have one additional new rig that will be added to our Balkan operation later in the second quarter. The movement of rigs out of the dry gas formation continues, we currently only have three rigs operating in dry gas areas. The demand for smaller rigs and the 800 to 1000 horsepower range continues to increase. These rigs are being utilized to drill the shallow or the horizontal liquid-rich wells.

The increase cannot be described as a dramatic year, but has been very steadily increasing. Most of the increased demand we have seen has been in the Mississippian play and Northern Oklahoma and Kansas. We believe this demand would continue to increase for the next several months. Our mid-stream segments achieved a good quarter with first quarter operating margin at 26% over the fourth quarter. The increase is due to higher liquids volumes and better processing margins.

We continue to see good opportunities for mid-stream growth primarily in natural gas processing. The Mississippian play continues to grow as the industry drills wells. This play will need hundreds of millions of dollars to build out the natural gas processing infrastructure and we hope to be a significant participant in that buildout.

Our Oil and Natural Gas segment had a good quarter. On our average daily oil and natural gas production was up 2% sequentially and up 18% over the first quarter of 2011. Our liquids volumes continue to increase, [book] per day liquids, up 2% sequentially and up 32% over the first quarter of 2011.

Liquids production was 42% of our total production in the first quarter of 2012 as compared to 39% for the year 2011. In 2012 virtually all of our CapEx budget has been directed towards liquid-rich prospects. Since 2009, when our focus changed primarily from natural gas to liquids, our liquids production has increased 87% and is now 42% of our total production as compared to 27% in 2009.

I will now turn the call over to Brad for him to talk more in depth about the exploration and production division.

Brad Guidry

Good morning. I will start out in the Granite Wash Texas Panhandle. We had first oil and gas sales on eleven operated wells with an average working interest of 84%. The higher than the normal number of completed wells drilled in the first quarter was due to a number of wells that were drilled in the fourth quarter of 2011, but we did not have first sales until the first quarter of 2012 due primarily to pipeline hook up delays.

The 30-day average rate for the eleven wells range from 1.3 million cubic equivalent per day up to 10 million cubic equivalent per day with an average rate of 4.8 million equivalent per day. The net production from our Granite Wash play for the first quarter of 2012 averaged 1363 barrels of oil per day, 3115 barrels of NGLs per day and 25.7 million cubic feet per day and that would equate to an equivalent rate of 52.6 million MCF per day that represents 8% increase over the previous quarter and 19% increase over the first quarter of 2011.

The quarterly production was negatively impacted by approximately 4%, that was due to a third-party plant being shut in during March. The Granite Wash laterals completed in the first quarter targeted 6 different Granite Wash sands with 55% of those laterals being drilled in the Granite Wash B and the Granite Wash C1 intervals.

We have now successfully completed wells in 7 different Granite Wash sand intervals. Currently we have four unit rigs drilling horizontal Granite Wash wells that should result and completed in approximately 25 gross operated wells for 2012. The net capital cost will be approximately a $100 million. In the Marmaton oil play located in Beaver county Oklahoma, we had first oil sales on six new wells with an average working interest of 75%.

The 30-day average rate was 263 barrels of oil equivalent per day. The net production from our operated Marmaton wells averaged 1775 barrels of oil per day, a 188 barrels of NGLs and 1,000,054 MCF per day which is a 23% decrease over the fourth quarter of 2011. The decrease was due primarily to fewer wells coming on production during the first quarter. However production for the first quarter of 2012 increased 29% as compared to the first quarter of 2011.

Early results from wells completed since the end of the first quarter look favorable which should positively impact second quarter production. The first quarter production stream was comprised of approximately 83% oil, 9% NGLs and 8% natural gas.

During the quarter, we successfully drilled and completed our first extended lateral Marmaton well in which we own a 94% working interest. The total measured depth of the well was 16,170 feet and that includes a 9,500 foot lateral.

The well was fracked, stimulated in 32 stages and the total cost was approximately $4.2 million. The well had first sales on April 14 of 2012. The production rates continue to increase as the well cleans up and the artificial lift system is optimized. The current production rate is 800 barrels of oil per day, 69 barrels of NGLs and 292 Mcf and that's an equivalent rate of 918 barrels of oil per day. This rate is a 77% increase as compared to two nearby short lateral wells and that represents the first 16 days of oil production for all of those wells.

Even though it’s still very early in the flow back period, we are certainly encouraged by the production results so far. Our current plans are to spread a second, extended lateral well during the second quarter of 2012. That well would be located approximately half mile to the east of that first extended lateral well.

In total, for 2012 we plan to run a continuous two rig drilling program which should result in completing 30 to 35 gross wells, approximate net cost of $70 million. Our lease hold position continues to increase. We got approximately 10,000 acres during the quarter and that brings our total current lease hold to approximately 103,000 net acres.

Moving down to the Wilcox prospect in Southeast Texas. We had first oil & gas sales on three wells during the quarter with the working interest and a success rate of above 100%. The net production from the Wilcox field for the first quarter averaged 866 barrels of oil, 1,375 barrels of NGLs and 19.2 million cubic feet for an equivalent rate of 33.2 million a day. This is an increase of 10% as compared to the first quarter of 2011.

The quarterly production was negatively impacted by approximately 9%. That was also due the third party gas processing plant being shut in for seven days during February. For 2012, we plan to run one rig and drill approximately 12 to 15 gross wells. We expect our working interest average around 87% and an estimated total cost about $41 million.

In our Bakken play in North Dakota continues to gain momentum with 10 wells having first oil sales during the first quarter with average working interest of approximately 15%. The net production from our Bakken wells has increased first quarter. We’re now producing 1,029 barrels of oil per day, 1 million cubic feet per day, and this represents an increase of about 27% as compared to the previous quarter.

Currently, there are three rigs drilling in the prospect which should equate to approximately 25 gross wells, approximate cost there, CapEx cost is about $40 million. In addition to the Granite Wash, the Marmaton, Wilcox and the Bakken, we’ve acquired a leasehold; we’re going to develop an Mississippian play located in Oklahoma and Kansas. We’ve completed drilling operations on our first horizontal Mississippian well that’s located in Reno County, Kansas.

The well was drilled a total measure depth of 8,115 feet and that includes a 3532 foot lateral. The well was fractured, stimulated last week and we’re just currently starting to flow back of that frac. Our current plan is to drill two to three additional horizontal Mississippian wells in different areas over the next six months, and evaluate the results before planning any further drilling in this play.

I will now turn the call over to John Cromling for an operations update of the drilling segment.

John Cromling

Thank you, Brad. Our contract drilling segment experienced a good first quarter. As Larry mentioned earlier, our average rate utilization during the first quarter was 81.5 rigs, which is relatively flat to the fourth quarter of 2011. Day rates increased slightly during the first quarter. The average day rate for the first quarter was $19,838 before elimination of intercompany profits as compared to $19,330 for the fourth quarter.

However the fleet average day rate was 20,010 at the end of the first quarter. The average per day operating margin for the first quarter before elimination of intercompany profits was $9,414 which is a $377 per day increase over the fourth quarter or a 4% increase. This is attributable to an increase in day rates, localization revenues, and other revenues for a total of $600 per day. The daily operating expenses slightly increased by about 2% for the first quarter, which is attributable to the labor increase in the Rocky Mountain division. All other daily cost remained constant.

One of our new wells was commissioned during the first quarter in Wyoming and the second one will be deployed in May for the Bakken play in North Dakota. We continue to sell surplus equivalent which will not be needed in our future plans and has the potential to sell additional small mechanical rigs, which are not yet candidates for refurbishments. Our average rig utilization for the first quarter was almost constant. However, during the last couple weeks of March, our total rig count increased to 77 rigs. This was due to further reductions in the Haynesville area and also just some operators reducing their activity in the Woodford (inaudible) play.

The interest and activity is steadily increasing in the Mississippian play in Northern Oklahoma and Kansas where we recently added two additional rigs to this area. We are presently refurbishing three 500 to 1000 horsepower rigs to operate in these regions. As the work is competed on these rigs and assuming the activity continues, we will begin refurbishing additional rigs to be available during the third quarter.

It is our expectation that increased activity in this market will allow us to maintain approximately the same rig utilization during the remainder of the year. Unit Drilling’s capitals expenditure budget for 2012 was approximately $120 million and a large portion of this budget will be utilized to upgrade rigs with new engines, pumps, fits and top drives. We also have plans to refurbish several other rigs as the market demands.

I’ll now turn the call over to Bob Parks.

Bob Parks

Thank you, John. As Larry previously noted, the mid-stream segment begin the year with operating profit of $9.7 million in the first quarter, up 26% compared to the fourth quarter of 2011. Our mid-stream success is primarily due to continued strong crude liquid prices, increased profits volumes and improved production capacity. The pair is active in both Mid-continent and Appalachian areas.

Our first quarter profits volumes rose 79% compared to the first quarter of 2011 to 154,825 MMBtu per day. The increase in per day profits volumes is mainly due to higher level of drilling activity resulting in new wells connected to our existing systems.

Our Natural Gas Liquids sold per day increased 59% from the first quarter of 2011, up to 522,829 gallons per day. This increase was primarily due to upgrading our existing processing facilities, expanding our total processing capacity and collecting new wells for our gathering systems.

The increase in liquids recovered do not match the percentage increase and gas profits due to takeaway product line constraints from the Texas Panhandle and the need to truck and reduced ethane [wide range] products early in the first quarter of 2012.

During the first quarter of 2012 we incurred capital expenditures of $24.5 million as compared to $9 million in the first quarter of 2011. For 2012, we have budgeted capital expenditures of approximately $224 million.

Now I would like to provide an update on our activities in the Mid-Continent and Appalachian areas. I’ll speak first about our activity in the Mid-Continent.

At our Hemphill facility in the Texas Panhandle, we are currently processing approximately 100 million cubic feet per day which is approximately 87% of capacity. Due to the high level of activity around our Hemphill facility, we are expanding our total processing capacity of this facility by adding an additional gas plant.

This new plant expansion project will add an additional 45 million cubic feet per day of processing capacity, and will increase our total capacity to approximately 160 million cubic feet per day. This new plant expansion project is scheduled to be complete in the second quarter of 2012.

At our Cashion facility in Central Oklahoma, we are continuing to connect new wells and we completed the installation of a new 25 million cubic foot per day processing plant which will increase our total capacity to 50 million cubic feet per day.

The Mississippian play in North Central Oklahoma remains a key area of focus for the midstream segment. In 2011, we completed the construction of our Spring Creek system which is located in Grant County, Oklahoma. This new gathering system currently consists of approximately seven miles pipe and a skid-mounted gas processing plant.

Also in this area, construction is underway on another new gathering and processing system located in Noble and Kay Counties in Oklahoma. This new system will consist of approximately 10 miles of pipe and initially a 10 million cubic foot per day gas processing plant that will be upgraded to a 30 million cubic foot per day gas processing plant in the fourth quarter of 2012. This new system is expected to be operational in the second quarter of 2012.

In addition to these projects, we are planning to connect our existing Marmaton system to the new system in Noble and Kay Counties. This extension will require 26 miles of pipe to connect these two systems. We are pursuing other opportunities in the Mississippian area and are currently in discussions with various producers that may lead to potential new projects or expansion.

Turning to the Appalachian area, we are expanding our Pittsburgh Mills gathering system in Allegheny and Butler Counties in Pennsylvania. We currently have one well connected to this system with five additional wells scheduled to be connected in the second quarter of 2012.

We are in the process of expanding this system to the North including construction of a compressor station to connect additional wells. We anticipate completing this expansion in late 2012.

In summary, we are off to a strong start in 2012 and look forward to continuing to expand our Midstream business. I’ll now turn the call over to David Merrill.

David Merrill

Thanks Bob and good morning everyone. I just wanted to update you on our hedges for the Oil & Natural Gas segment. We have added some Oil & Natural Gas hedges from the positions that were disclosed in our 2011 Form 10K.

Our overall hedge position for the balance of 2012 includes 6,250 barrels per day of oil production and 51,700 MMBtu per day of natural gas production. The oil and natural gas production is hedged at an average price of $97.72 and $4.95 respectively.

Look out to 2013; we have hedged 4,000 barrels per day of oil production and 30,000 MMBtu per day of natural gas production. The oil production is hedged at an average price of $102.68 and the natural gas production hedged 10,000 MMBtu is hedged with a swap at $3.21 and 20,000 MMBtu per day is hedged with the collar of $3.25 floor and $3.72 ceiling. The detail of our hedges is included in our Form 10-Q filed with the SEC today.

Our operating segment capital expenditure budget for 2012 remains unchanged from the beginning of the year and it is $801 million excluding acquisitions. Budgeted capital expenditure by segment are $457 million for the Oil & Natural Gas segment, $120 million for contract drilling segment in $224 million for the Midstream segment.

The 2012’s capital program is anticipated to be funded using internally generating cash flow and borrowings through our credit facility.

The effective income tax rate for 2012 first quarter was 38.7% with the current portion of income taxes estimated to range from zero to 10% for the year.

John, we would now like to open the call for questions.

Question-and-Answer Session

Operator

Thank you (Operator Instructions) Our first question comes from Marsh Adkins [Raymond James]. Please go ahead.

Marshall Adkins - Raymond James

A couple of little ones here; in the press release you mentioned potential production curtailments; you know what makes your top process there?

Larry Pinkston

Well, storage, our concerns going forward is what happens in the summer months. Storage still, if we start seeing some real short term pricing pressure on natural gas and if it should fall substantially from where it is now, certainly don’t think that it gives us the sell, especially the dry natural gas. The liquid rich natural gas is a different scenario, but the dry gas don’t make a whole lot of sense.

Marshall Adkins - Raymond James

So really what you are saying is, if prices get meaningfully weaker from here you would be concerned, but at this price just you keep (inaudible) with what you are doing?

Larry Pinkston

I think for us Marshall, we have not done or we did a little bit in the fourth quarter, a very little bit then we didn’t do any in the first quarter and again it’s kind of the outlook for the next few months if we see it starting, strengthen or definitely start feeling better about it. But last few days have been nice.

Marshall Adkins - Raymond James

It seems like you’ve had pretty access on drilling rig side away from the dry gas areas, sands or etcetera. Is that about done, most rigs that were there, that you are running; are they migrated or already shutdown?

Larry Pinkston

Yeah, in the dry gas area only three rigs left that we would classify as a dry gas area. So for us, I think it’s done; for the industry, I don’t really think it’s done yet, but any rigs that comes off of location, restricted on all the rigs, but for us, it’s only three rigs left and we’re working in those kind of areas.

Marshall Adkins - Raymond James

Last question from me, it seems like you are going through quite a learning curve on the Granite Wash and going through it on the Bakken as well, even started to drill some horizontals in the Marmaton. What made through and I am not sure who should answer this question out, but can you give me some help in terms of understanding how much productivity is improved in those areas over the last two or three years?

Brad Guidry

Yeah Marshall, this is Brad. In the Marmaton, increase that we have seen in both in production and the drilling costs; in the Marmaton we first started out there you know our well cost was upward $3.5 million; the number of days it took us was 20 to 23, you know we have gotten well cost now and this is for the shorter lateral, for 4,500 feet down to about $2.7 million pretty consistently. So certainly we’ve made improvements on that end.

The things that we have done on the production end is, in the Marmaton again I am talking specific to that, is in the artificial wood systems that we had out there, you know we pretty well decided how we produce the wells now we go from submersible pump pretty much down to conventional pump at some time period in there.

So there is less trying of different production, not just different production models that we might have done in the past and would have more cost associated with it.

As far as picking locations in the Marmaton, certainly as we drill more wells out there, we get a better handle of the fracture patterns that are out there which is the main driver of productivity in that play. So there is no question that the play matures as we drill more wells, we will see more consistency in our production rates. We will focus more in the areas where we know we have known fractures and stay out of the areas where we don't.

To this point really the best way to determine fractures is based off of well control. There's not a 3D grid out there. There is some 2D data, but with the concentration of data it's really not that helpful on a big scale to determine the fractures. But the well controls get more and it's not you know just the wells we drill. Cabot is out there drilling now and Questar has drilled some wells, so all of that figures into the overall picture.

The Granite Wash, again so we've seen the same thing on the drilling efficiencies. We've now drilled seven different zones out there pretty much as you drill a new zone and the area may have some differences and how the zone drills. So we've been able to do that. We have some new equipment out there for drilling the curve, that we didn't have a year or two ago that has helped us. Our cost out there is, has remained pretty constant at about 5.5 million.

We've seen a little bit of a reduction in the frac cost, so consistently what we are not seeing is the problem wells that we might have had in the past. The production side of it you know we are really not doing a whole lot different from a frac standpoint, it's still pretty standard slick water frac out there, as we've gone into additional zones out there, we've seen a little bit of variability but for the most part the Granite Wash has been pretty consistent and a lot of that Marshall is because we are in a fairly confined area in that Hemphill and Roberts area.

Larry Pinkston

You know the other thing Marshall I will add on it. In the Marmaton area the next big leap in the efficiency state, potentially really is the longer laterals. Even though we've drilled our first one now that 9500 feet and all the rest of them before have been.

Marshall Adkins - Raymond James

That was a big well.

Larry Pinkston

Yes it could be and if the production keeps -- we’re still in a stage right now that production is going up. We’re in that stage of early on in the life, the production life of the well. If it continues to work and that becomes a longer lateral play which we think at this point that's definitely a potential. And then you are drilling basically two wells for 4.2 million versus previously two wells, the same amount of lateral would have been 5.4 million per well. So that has a possibility of increasingly the economics even further in that field.

Operator

Our next question comes from Brad Evans [Heartland Funds]. Please go ahead.

Brad Evans - Heartland Funds

Just curious with some of the smaller rigs coming online. I realized they probably will come on at slightly lower average day rates, should they have a major impact in terms of EBITDA per rig day at the margin level?

Larry Pinkston

No, no, some yes Brad, I mean they have to have some, but when you spread it over 70 rigs you know the impact is much reduced, but you know we would expect with the smaller rigs going to work that you know the average day rate for the fleet will be coming down. You know margin is a different animal, you don’t loose as much on margin as you loose on day rates, but we would expect it to come down.

For the second quarter and into the third quarter possibly I think once we get through storage season you know is kind of the new world again in the gas arena. If we have any winter and you know it is and but that happens in the fall, you could start seeing again more activity in the gas drilling, but short term, I think the average day rates I think will gradually come down a little bit and margins a little, but not as much.

Brad Evans - Heartland Funds

So Larry, is your current view still that what we are seeing in the lat rig side is similar to what we saw in 2006-2007 where the rig kind of plateaued for a little while and then we saw recovery in 2008 or do you think we are heading to something a more negative from a land rig demand perspective.

Larry Pinkston

Brad, you know that is going to be just totally dependant on gas prices short term, be in the next, throughout the remainder of this year and early into 2013. I still don’t believe gas prices would have been below $3 this year, had we not had the winter that we had last winter. If we get back up in the $3.5 to $4 range for next year, you are going to see some activity come back. I am going to see 300 rigs, go back to work, drilling gas wells. But you will see some activity coming back.

In the meantime the demand is increasing for the shallow or horizontal wells and it will just be a scenario as is the demand picking up fast enough to offset the lower demand on deeper horizontal drilling and on a quarter-to-quarter basis, it could go either way.

Brad Evans - Heartland Funds

Okay. Can I just ask you what kind of inbound call levels you are receiving right now for any rigs in the 1000 to 1500 horsepower class, where might those go if you are getting the calls today?

Larry Pinkston

Well, most of the demand request we are seeing is in the Mississippian play and we are not having extra operators to take over additional calls, it’s pretty steadily enable to call, so it’s….

Brad Evans - Heartland Funds

Your capital budget for the full year is still $800 million, is that correct?

Larry Pinkston

Yes; we always try to look at it mid year, on a quarter-to-quarter basis if that’s just too short of a timeframe to look at it. We look at it when we get through June to see where we are and what commodity prices and what they are looking like and make adjustments either up there.

Brad Evans - Heartland Funds

And I am curious, Brad could you just give us on that expanded lateral in the Marmaton, what was the cost to drill that and what was the EUR, your classification?

Brad Guidry

The cost was about $4.2 million as compared to $2.7 million for shorter lateral. EUR, it’s still too really, we don’t have a number on that well. Actually, it’s completed well, at the end that will be in the second quarter well; so we don’t know.

But we expect that, I am hopeful that it will be priced as much as what our average is for the short lateral. When we look at it to compared and short laterals in the area and where we drill this into lateral was in a pretty good area. We had fair well control in there when you compare it to the offsets.

In the call, I mentioned the daily rate was about 77% higher than what two offset wells are. Our expectation is that we will see a slower decline, because of the extended lateral in there; it is just too early to tell you at this point

Operator

(Operator Instructions) We do have a follow-up from Brad Evans. Please go ahead.

Brad Evans - Heartland Funds

I realize you don't give guidance, but based on what you see right now I am just curious where do you think your debt levels peak if you continue to execute on that $800 million CapEx program?

Larry Pinkston

Well, it depends on what commodity products assumptions you make, but at $3 gas, it’s a whole lot different than at $2.25. David?

David Merrill

Yeah, Brad where we, obviously Larry is right on it, we will see what commodity prices do, but based on our level of spend in Q1 and what we are anticipating for next three quarters, we would anticipate the debt levels to just increase gradually over the next three quarters. We wouldn't see a peak during Q2 or peak during Q3. It would just be gradual over that time.

Given the current outlook, when we meet mid year and kind of go back through and take a look and we will see if we make adjustments from there. But that's what I would anticipate as a gradual increase throughout the next three quarters.

Brad Evans - Heartland Funds

It does look like you have, without a lot of commodity help, it looks like you could do close to $700 million of EBITDA excess here, so your out spend is not huge versus your cash flows or your balance sheet?

David Merrill

Exactly, the way we look at it, given the strength of our balance sheet and the attractiveness of the opportunities that we are looking at for those capital programs in all three of our businesses, we are happy, we are not uncomfortable out spending cash flow by that level of magnitude.

Brad Evans - Heartland Funds

And just one last question on the rig side, has the inbound call volume for newbuilds is that dried up pretty much or you still seeing possibilities there?

Larry Pinkston

That’s slowdown tremendously Brad, with that manner I would expect the only possibility would be in the Bakken and I think that area is so constrained, total re-infrastructure wise that its not a question as to whether operators at locations; we just need to take any more rigs into the infrastructure that exist.

So, I think it’s going to be steady increase, slower increase in that area. There are certainly not any calls for meeting additional rigs in the lower producing basins. So right now, I don’t have much expectations for new rigs for the remainder of this year.

Operator

(Operator Instructions) We have no further questions at this time.

Larry Pinkston

Just to wrap thing up, John thank you for handling the call. We hope to see many of you all in the next few months at the various conferences or in one-on-one meetings. But we want to thank you again for joining us this morning and we will talk to you next quarter. Thanks.

Operator

Thank you. Ladies and gentlemen, this concludes today’s conference. Thank you for participating. You may now disconnect.

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