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Unit Corporation (NYSE:UNT)

Q3 2011 Earnings Conference Call

November 2, 2011 11:00 AM ET

Executives

Larry Pinkston – President and CEO

David Merrill – CFO

Brad Guidry – EVP, Exploration

John Cromling – EVP, Contract Drilling Operations

Bob Parks – President, Mid-Stream

Analysts

Jim Rollyson – Raymond James

Phillip Jungwirth – BMO Capital Markets

Brad Evans – Heartland

Operator

Welcome to the Unit Corporation Third Quarter 2011 Earnings Call. My name is John, and I’ll 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, developments that the company expects or anticipates will 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. We want to thank you for joining us this morning. With me today, as we’ve done in the past, are, David Merrill, who is our CFO; Brad Guidry, who is – who runs our Exploration segment; John Cromling, our Executive Vice President of Contract Drilling Operations; and Bob Parks, who is President of our Mid-Stream segment. Each of these gentlemen will be providing you with updates concerning their segments in a few minutes, and then we will take questions after their comments.

We released our third quarter results to public this morning. We reported net income of $53.4 million and earnings per share of $1.11. This represents a net income increase of 55% over the third quarter of 2010 and a 7% increase over the second quarter of 2011. Our net income through the first nine months of 2011 is 40% higher than the same period for 2010.

Our Contract Drilling segment continued to show strong results. Our number of rigs utilized during the third quarter increased by 8% and with the second quarter, averaging 79 rigs operating. Average day rates continue to increase, up $448 during the third quarter. We currently have two remaining rigs to complete, should be operating late in the fourth quarter, that’s out of the seven total that we constructed this year.

Midway through the third quarter, we experienced a slowdown in new inquiries for both existing rigs and new builds; however, inquiries started picking back up late in the quarter and has continued into the fourth quarter. Based on the level of inquiries, we feel the rig cap should remain strong through the remainder of the year and into the first part of 2012.

Our Mid-stream segment achieved significant operating growth during the third quarter as compared to the second quarter. Gas sold volumes were up 40%, gas processed volumes were up 45%. Natural gas liquids sold volumes were up 28%. The increase is a result of our installing of new plants and upgrades to our existing plants that we’ve completed over the last six to nine months.

We increased our capacity in our Granite Wash processing plant in the Texas Panhandle from 50 million a day to 120 million a day. The plant is currently operating near full capacity. We are again in the process of increasing the capacity of this plant which should be completed in the second quarter of 2012. We are continuing to see a growing number of opportunities in this segment as the oil and gas industry continues to drill for oil and rich natural gas.

Margins for this segment were down slightly for the third quarter compared to the second quarter of 2011 as a result of the downward pressure on commodity prices during the third quarter. Our exploration and production segment continued to achieve exciting growth. All natural gas liquids and natural gas production continued its growth trajectory. Our equivalent production during the third quarter increased 5% over the second quarter. Our year-to-date equivalent production for 2011 is up 23% over the same period of 2010.

We’ve achieved good results toward our goal of increasing liquids production. Liquids production for the nine months of 2011 is up 58% over the same period of 2010. Total liquids production for the first nine months of 2011 is 38% of our total production as compared to 30% during the same period of 2010.

Brad and his group have achieved some good results on new wells completed during the quarter in all three of our primary focus areas which are the Granite Wash and the Texas Panhandle, the Marmaton and Oklahoma Panhandle in the Wilcox in East Texas. We’ve continued to grow our acreage position in each of these prospects. That would be a good time for me to turn the call over to Brad for him to discuss more details.

Brad Guidry

Good morning. I’ll start out on the Granite Wash play. We continue to have strong consistent results during the third quarter of 2011. We completed five new operated Granite Wash wells with an average working interest of 79%. The 30 day average for the five wells range from 4.5 million of cubic feet of gas equivalent to 10.2 million cubic feet and that would average 30 day rate of approximately 7.2 million. Through the first three quarters of 2011, we’ve completed 14 operated Granite Wash horizontal wells with a 30 day average rate of approximately 6.5 million equivalent per day and that consist of 15% oil, 36% NGLs and 49% natural gas.

That number compares to three wells being drilled during the same three quarters of 2010 with average 30 day rate of 4.9 million cubic feet equivalent. Highlighting the third quarter for 2011 was the Granite Wash horizontal B zone completion in which we own a 83% working interest.

The well had first sales on August 30, 2011 at daily rate of 279 barrels of oil per day, 568 barrels of NGLs per day and 4.8 million cubic feet of gas per day and that equates to an equivalent daily rate of 9.9 million. The 30 day rate for this well was 8.6 million.

Also during the second quarter, we completed a Granite Wash A zone well where we own a 28% working interest. The well had first sales on August 7, 2011. The daily rate on that well was 400 barrels of oil per day, 755 barrels of NGLs and 6.3 million cubic feet of gas. The daily equivalent rate for that well was 13.2 million. The 30 day rate for the well was 10.2 million. The remaining two wells with first sales during the quarter were completed from the Granite Wash B and the C1 zones.

Anticipated reserves for our Granite Wash horizontal wells is estimated to be approximately 4.1 Bcfe per well. Since we end of the third quarter, we have one Granite Wash well that has recently been fracked, but has not been on line long enough for a 30 day average rate; however, the early flow rates on this well are very encouraging.

In addition, there are three Granite Wash wells that have finished drilling operations and are scheduled to be fracked in November and December of 2011. Currently, we have four unit rigs drilling horizontal Granite Wash wells and this drilling program should result in completely approximately 19 gross operated Granite Wash wells during 2011 at a net capital cost of approximately $85 million.

Moving to the Marmaton horizontal oil play located in Beaver County, Oklahoma, we’re continuing to run a two rig program in this play which has resulted in first oil sales on seven new wells during the third quarter. The 30 day rate for the third quarter wells range from 40 barrels of oil equivalent per day to 710 barrels of oil equivalent per day, with an average 30 day rate of 329 barrels of oil equivalent for the seven wells.

Through the first three quarters of 2011, we’ve had first oil sales on a total of 25 wells and the average 30 day rate for those wells was 242 barrels of oil equivalent per day, and the average working interest for the 25 wells was 81%. In addition to third quarter results, we have drilled four wells that have recently been fracked. They are in their early stages of flow back, plus there is three additional wells that have completed drilling operations and are scheduled to be fracked in November and December and then we have two wells that are currently drilling.

Our AFE cost is estimated at $2.7 million and the projected ultimate gross reserves for Marmaton and horizontal well is 130,000 Mboe which consist of approximately 78% oil, 14% natural gas liquids, and 8% gas. We anticipate drilling approximately 34 gross wells for 2011 at a net capital cost of approximately $70 million.

We are continuing to acquire leases in the Marmaton and our current leasehold positions has increased to approximately 84,000 net acres. We are scheduled to drill our first extended lateral horizontal Marmaton well in late December of this year or January of 2012. Current plan calls for drilling a 9,000 foot lateral at an approximate cost of $4.2 million.

Moving to Texas and the Segno Wilcox play, we’ve completed 13 wells at 69% success rate through the third quarter of 2011, which in part has contributed to a 9% production growth in our Segno area for the third quarter and that compares to the second quarter. Highlighting the completion is the 100% working interest well that had first sales on June 30th of this year. The initial rate was unstimulated of 6.7 million, 215 barrels oil and 780 barrels of NGLs per day.

The equivalent rate on that well was 12.7 million. The well was tested, that rate was at 7,500 of flowing tubing pressure. An offset well has been drilled, but it waiting on completion at the end of the third quarter. We anticipate drilling a third well in the prospect in the first quarter of 2012. In Segno, we anticipate having one rig drilling for the remainder of 2011.

In addition to the three prospects I just talked about, we’ve also been acquiring leasehold in the developing Mississippian [ph] play located in Oklahoma and Kansas. We currently have approximately 45,000 net acreage leased primarily in South Central Kansas. Our current plans are to spud the initial test well in the Mississippi and in the first quarter of 2012.

I’ll now turn the call over to John Cromling to discuss the drilling highlights.

John Cromling

Thank you, Brad. The Drilling division experienced a good third quarter as demand continued to increase. As Larry mentioned earlier, our average rig utilization during the third quarter was 79 rigs. At the end of the third quarter, we had 81 operating rigs and also have four additional rigs contracted that will begin operations later in the year or the very first part of next year. Two of these rigs are the two new builds and the other two are refurbished rigs.

Day rates have continued to increase during the third quarter. Average day rate for the third quarter was $19,309 before elimination of inter-company profits, which is approximately a 2% increase or $448 per day over the average of the second quarter.

Operating cost before elimination of inter-company profits were $108 per day higher in the third quarter as compared to the second quarter. The higher costs were attributable primarily to supplies and services increasing slightly due to the added demands of horizontal drilling.

Our average mobilization revenue per day decreased during the third quarter which lowered our total operating margins per day. This resulted in an increase of $43 per day between the second quarter and the third quarter of 2011. Our two new build projects are still on schedule to be completed during the fourth quarter. We continue to discuss additional new builds for 2012 primarily in the Bakken play.

The greatest area for additional growth in unit is to put stack [ph] rates back to service. During the third quarter, we activated two 800 to 1000 horsepower rigs and equipped them pad drilling. We continue to see opportunities in various areas horizontal plays that will require smaller rigs which fit our rig fleet.

We are currently refurbishing and converting an 800 horsepower mechanical rig to 1,500 horsepower electric rig which has a long term contract upon completion. Even though some operators have slowed down their exploration program in the last couple of months; in some areas, they experienced a reduction in the number of rigs operating, we’ve been able to secure additional work without suffering a decrease in day rates.

Our revised CapEx budget for 2011 is $174 million and through the third quarter, we have spent about $124 million. We will continue with our plans to build the remaining two rigs and refurbishment projects of several other rigs, not only to put additional rigs into service, but also to improve the operating rigs. These upgrades include new engines, pumps, mud pits, top drives and skidding systems.

And I will now turn it over to Bob Parks.

Bob Parks

Thank you, John. Our Mid-Stream segment continues to generate strong financial and operational results. For the third quarter of 2011, we had operating profit of $7.4 million, an increase of 11% over the third quarter of 2010. This increase is primarily due to an increase in volumes gathered and processed.

During the third quarter, we incurred capital expenditures of approximately $22 million as we continue to construct and complete various mid-stream projects in both the Mid-Continent and Appalachian regions.

Our third quarter processed per day volumes were up 54% compared to the third quarter of 2010 to 129,822 MMBtus per day. The processed volume increased due mainly to increased drilling activity resulting in new wells that were connected to our existing gathering systems.

In addition to the increase in processed volumes, our natural gas liquids sold per day increased 73% for the third quarter of 2010 to 449,000 gallons per day, and increased 26% for the second quarter of 2011. This increase is primarily due to upgrading our existing processing facilities and connecting additional gas to our gathering systems. Also, our overall gathered volume increased 20% compared to the second quarter 2011 up to 228,247 MMBtus per day.

I would like now to provide an update on our activities in the Mid-Continent and Appalachia. I’ll speak first about our activity in the Mid-Continent. At our Hemphill Processing facility in the Texas Panhandle, our total processing capacity is approximately 120 million cubic feet per day after the successful installation of a fourth processing plant and completing some other plant upgrades.

We are currently processing 110 million cubic feet per day and we will reach our maximum process capacity of the plant in the fourth quarter of 2011. As Larry mentioned previously in this call, we are again in the process of expanding the capacity of the plant and this expansion project should be complete in the second quarter of 2012.

At our Cushing gathering and processing facility in Central Oklahoma, volumes were at 17 million cubic feet per day, which is approaching our Cushing plant capacity. The installation of the new 25 million cubic feet per day high-efficiency, turbo expander processing plant is scheduled to be completed in the first quarter of 2012.

This new plant will replace our existing processing plant, simultaneously increasing our processing capacity and improving plant efficiencies. Also, our Cushing facility, our project to expand the Cushing system to the North to gather gas from new wells drilled in the area is well underway, and is anticipated to be completed in the fourth quarter of 2011.

As for new project development in the Mid-Continent area, we are continuing to develop various projects in North Central Oklahoma in the Mississippi Lime play. We have completed the construction of our first new system in the Mississippi Lime, the Spring Creek gathering system and processing plant located in Grant County, Oklahoma.

This new gathering system currently consists of approximately 7 miles of pipe and is skid mounted processing plant that will deliver gas in the Southern Star. Initial flow of gas began in October. We expect to announce commencement of construction on a second Greenfield System in North Central Oklahoma later this year.

In addition to these Greenhill projects, three of Superior's existing gathering systems and plants are able to access (inaudible) exploration areas, leading to potential expansion projects at those existing facilities.

Turning to the Appalachian region, we are continuing to explore, develop various projects in the region. Construction on our 16-mile – 16-inch gathering system and compressor station in Preston County, West Virginia, has been completed and we coordinating with the Interstate Pipeline to flow gas in November 2011.

This gathering faculty will have a capacity of approximately 220 million cubic feet per day and will deliver gas in Columbia. Also in the Appalachian area, we completed the first well connect on our Pittsburgh Mills gathering system in Allegheny and Butler Counties, Pennsylvania. The initial flow from this first well connected to our system is approximately 10 million cubic feet per day.

We are currently completing right-of-way and survey work as we finished construction of the first phase of the system, (inaudible) gathering system approximately six miles to the North.

We anticipate completing phase I of this project in the second quarter of 2012.

Activity in Pennsylvania and West Virginia continues to be strong for Superior. Our business development group continues to evaluate many other possible projects in Marcellus Shale.

In summary, we are continuing to see a lot of activity in the midstream and continuing to evaluate new business opportunities in both the Midcontinent and Appalachian areas. I’ll turn the call over to David Merrill.

David Merrill

Thanks Bob. Hi, everyone. As you recall, during the second quarter, we completed an underwritten public offering of $250 million principal amount of senior subordinated notes that were due in 2021 and the net proceeds were primarily used to repay borrowings outstanding under our unsecured credit facility.

During the third quarter, we entered into a new five-year unsecured senior credit facility that matures September 2016 and both the notes offering and the new credit facility concludes the financing arrangements we currently see as necessary for our near term operating plans.

We ended the third quarter with a debt to capitalization ratio of 14% and $55.4 of million borrowings outstanding under the credit facility which has an elected available commitment amount of $250 million.

Our current borrowing base associated with the credit facility is $600 million as determined by our lenders in their most recent redetermination which was completed in October.

For the oil and natural gas segment, operating costs per BOE for the third quarter of 2011 was $9.48, a 15% decrease from the second quarter of 2011. The decrease was primarily due to a $4.5 million reduction in production taxes for refunds of production taxes attributable to high cost gas wells. Excluding the impact of the high cost gas well production tax refunds, third quarter operating cost per BOE was $10.92, a 2% decrease from the second quarter. We anticipate operating cost per BOE for the fourth quarter to be more in line with the $10.92.

Our hedges for the oil and natural gas segments complement our strong balance sheet and during the third quarter, we added to our 2011 and 2012 positions for natural gas liquids. The detail of our hedges in included in our Form 10-Q to be filed with the SEC later this week. Total capital expenditures excluding acquisitions from our operating segments for the first nine months of 2011, were $552.1 million. For 2011, our capital expenditures budget as revised mid-year this year for all of three of our operating segments is $695 million, excluding acquisitions.

We are in the early stages of developing our capital expenditures budget for 2012, but currently expect it to be within anticipated cash flow for 2012. The effective income tax rate for the 2011 third quarter was 38.5% and we currently estimate no income taxes for 2011 – no current income tax.

And John, I’ll now turn the call over to you for questions.

Question-and-Answer Session

Operator

Thank you. We will now begin the question and answer session. (Operator instructions) Our first question comes from Jim Rollyson from Raymond James. Please go ahead.

Jim Rollyson – Raymond James

Good morning, everyone.

Larry Pinkston

Hi, Jim.

David Merrill

Hi, Jim.

Jim Rollyson – Raymond James

David, maybe going back to your last bit of commentary, on CapEx, you said you should be within cash flow which is something you guys would normally do, but just curious based on what you are thinking on the E&P front for production growth and given you’ve had a pretty nice ramp-up this year and what your price outlook, does that imply flat, up or down CapEx on the E&P side for next year?

Brad Guidry

Yes, on the E&P side, it’ll probably be – it will be in the ballpark of where we are this year, maybe slightly up, but we think that’s probably the direction that we’ll be seeing, excluding acquisitions, of course.

Jim Rollyson – Raymond James

Right. And from a production standpoint, you guys have had a pretty good year this year after being relatively flat last year for the obvious reasons, what are you thinking with the way things are trending and what your CapEx plan is, what are you thinking for production growth in 2012?

Larry Pinkston

Our minimum goal every year again is to, we want to replace at least 150% of our annual production. If we just do that, with just our [ph] – again, is our minimum goal, that should relate to somewhere in the 10% to 12% production growth year in, year out. It doesn’t always come out that way on a calendar year basis, but on a rolling 12-month basis, that’s pretty where we should be. And again, that’s our minimum goal. And the budget, we’ll start off with the budget (inaudible) last in early December and that’s kind of – and they are evolving budget as we go through the year depending on the results we see and what commodity prices are doing. So, it’s not something that would be (inaudible) for the full year, but at a minimum, the budget will meet our goals, replacing at least 150% of production and at a minimum that should be somewhere at least in the 10% plus range of production growth.

Jim Rollyson – Raymond James

That’s helpful. And on – switching to the rig side, revenue per rig per day was obviously up, but so were costs, as you think about that heading forward, do you think some of the things you mentioned in the costs were – is some of that going to be repeating or basically, do you think this is the new level costs and do you think margins will continue to improve kind of gradually over time?

Larry Pinkston

Well, one big component of the comparison with any quarter is, again, as John mentioned briefly, was the mobilization revenue, which – it was down on a per day basis, about $1,100 a day. I mean that’s typically part of the business that there is not the normal kind of margin on the mobilization that you are seeing on the day work basis, and mobilization revenue is really something we can never control, depends on the length of the moves and a lot of other factors. But excluding any – the impact on that caveat or on that part of our revenue stream, I think expenses are going to be – they’ll continually, gradually go up. The day rates, we are not going to see the kind of increases that we saw earlier this year in the day rate increases, but I think they’ll still continue to grow gradually as the utilization goes up.

Jim Rollyson – Raymond James

All right. And last question for me if I may is on the mid-stream side, it seems like you guys continue to put up very good growth and it doesn’t seem to be there is any shortage of opportunities to deploy capital for additional projects or expansions of current projects, what’s the limiting factor at this point, capital?

Larry Pinkston

Oh, probably people more than anything. Each one of these projects takes people and building and then operating and then of course, managing them, not much limitations on the possibility of manage which is getting them operating, but it depends on the capital we see. If we see several hundred million dollars of opportunities and that’s one thing; if it’s – where it was this year or say, double where it was last year, then capital is not going to be a constraining factor, but there is more opportunities right now with all this liquids driven drilling than any of our guys have ever seen and it’s time that they’ve been in the business; it’s amazing.

Jim Rollyson – Raymond James

Sounds pretty good. Thank you.

Larry Pinkston

Thank you, Jim.

Operator

Our next question comes from Phillip Jungwirth from BMO Capital Markets. Please go ahead.

Phillip Jungwirth – BMO Capital Markets

Hi, good morning, guys.

Larry Pinkston

Good morning.

Phillip Jungwirth – BMO Capital Markets

Can you remind us the terms of the completion contract in the Granite Wash and Marmaton that you secured about a year ago, I believe?

David Merrill

For the fracs?

Phillip Jungwirth – BMO Capital Markets

Yes.

David Merrill

It’s our – with BJ [ph] that’s our fracking business in there and its six-month contract, but we expect that to continue to go on indefinitely as long as we have our drilling programs intact.

Phillip Jungwirth – BMO Capital Markets

Okay. So, it’s a six-month market rate contract then?

David Merrill

Yes.

Phillip Jungwirth – BMO Capital Markets

Okay. Are you seeing any abatement of rising service costs or any cost deflation?

David Merrill

We’re still seeing a little bit rise in the pipe costs; the frac costs has been minimal. We have been seeing a little bit more availability of the fracs there, like in the Gulf Coast; more companies will actually for jobs now, but it hasn’t been anything drastic from an increase standpoint.

Phillip Jungwirth – BMO Capital Markets

Okay. And can you talk about your expectations for the horizontal display just in terms of spacing EURs and well costs?

David Merrill

The horizontal in this, we have acreage is primarily in Kansas and part of that in an area where there has been some drilling as part of the acreage and really, the majority of the acreage is in a area that’s really not been derisked yet. So, I’m not really sure, the expectations there until we drill a well and then find out. Right now, what we are basing it on is really what we’ve seen out in the industry from other operators who drilled wells and the Kansas part, it’s really shallow, about 5,000 feet, and we expect the whole [ph] cost to be somewhere $2.5 million, $3 million. We are expecting a couple of hundred thousand barrels of oil equivalent, so we are going in and looking at, but until we drill wells, that’s just a (inaudible).

Phillip Jungwirth – BMO Capital Markets

Okay. And then on the increased production guidance, was the Woodford acquisition, or was that added last quarter or has that been added this quarter?

David Merrill

We have one month in last quarter. Month of September, it led in there and it was about $7 million a day equivalent.

Phillip Jungwirth – BMO Capital Markets

So was the increase in guidance this quarter, was that acquisition related, or is it just better than expected drilling results, because I think the gross number of wells you expected to drill went down from 160 to 180, but the guidance went up?

David Merrill

Yes, a little bit above. Certainly, the acquisition will add about six-tenths of a Bcf into that growth, but no doubt, the wells we drilled in the Gulf Coast, the Granite Wash, Marmaton, all of those results have exceeded what we had modeled, and that’s also added to the improved guidance.

Phillip Jungwirth – BMO Capital Markets

Okay. And was there anything different in terms of the lateral length or the completion in the Marmaton this quarter versus the wells last quarter?

David Merrill

No, not at all. We’ve talked before about Marmaton being the statistical play and really didn’t do a lot different, just the results in the third quarter; wells we drilled were substantially better than what we have seen in the second quarter. As we drill more wells, there is no doubt, we’ll be able to refine the areas that are basically the sweet spots and we’ll focus more towards those areas.

Phillip Jungwirth – BMO Capital Markets

Okay. And would you look at adding another rig in the Marmaton or sometime ’12 [ph], or you are happy just running two rigs?

David Merrill

With the decreased drilling days that we had in there, we think we can manage our acreage position out there with the two rigs. We should drill somewhere 35 wells a year and we think with that – with the new longer lateral, we want to see how that comes out, the results from that, but right now, we don’t have any immediate plans to go to a third rig. The new rig that we will be adding next year will be in this (inaudible).

Phillip Jungwirth – BMO Capital Markets

Okay. And then last, do you have an estimate for number of locations in the Granite Wash?

David Merrill

Somewhere, we usually talk about 75 – yes, operated. We have been able to add a little bit of acreages here. There is – most of the Granite Wash acreage is HBP [ph], but we have been successful adding a little bit to that; each acreage we can add extends our inventory out.

Phillip Jungwirth – BMO Capital Markets

Okay, great. Thanks, guys.

David Merrill

Thanks, Phil.

Operator

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

Brad Evans – Heartland

Hey, solid quarter. Thanks for taking the questions. I had a question first on just the Granite Wash for Brad, I guess, in terms of whether you all are drilling within the Cottage Grove or the Cleveland or the Hogshooter formation there? Are you guys– do you have any plans to explore those formations?

David Merrill

2012, we will drill horizontal Cleveland. We’ve participated in some Cleveland wells; we’ve participated in some Hogshooter and we’ve actually drilled, operated Cottage Grove horizontal well that we are watching the results it's producing and still in the very early stages. So, plans for 2012 would be to use the rigs and drill some wells in the different formations that are out there, certainly the Cleveland, Cottage Grove, maybe the Doug [ph] was in – there is a number of different formations out there, but yes, we are definitely getting exposed to some of the good wells out there that are being drilled in those formations.

Brad Evans – Heartland

Okay, thank you. Your exit rate for 2011 oil and liquids would be roughly 1% of production on an exit rate basis?

David Merrill

Should be around 38%, Brad.

Brad Evans – Heartland

38%, all right. Just a question on the CapEx budget, I guess if you were to continue momentum in the business from – on the production side, additional higher levels of utilization on the rig side with day rate and margin improvement, I mean, you could actually – I mean, it wouldn’t be impossible for you to raise your CapEx say, upwards of maybe 10% or more next year and still be within cash flow, is that – is there some wrong [ph] with that analysis?

Larry Pinkston

(inaudible) I mean it comes down to commodity prices of use [ph] and we typically start the year off with pretty conservative commodity price assumptions and if we are going to be surprise, we’d rather be surprised of the upside and the downside. And so, it depends. Yes, it’s definitely within the range, it just depends on what commodity prices you enter the year with.

Brad Evans – Heartland

Okay. And then just, a couple of your competitors, Larry, have retired some rigs this year and scrapped them, I was curious whether you’ve had any plans on following that path?

Larry Pinkston

Not right now. It’s something we assess all the time, Brad. There is no doubt that there is always a few of our smaller rigs are – expect us [ph] whether they’ll go back to work, but we continually get surprised about some of the swallow drilling going on. And so, some of the rigs that we though wouldn’t work have worked pretty consistently this year. So, right now, we have no plans for that. We are continuing to drive the market and a few other rigs for sale, that’s somewhat slowed down recently, but we are continuing do that also.

Brad Evans – Heartland

Okay. I am sorry, and just to be clear, as we move forward here, we should expect gradual improvement in terms of – on the contract drilling side, further gradual improvement in terms of day rates and margins, is that correct?

Larry Pinkston

The market looks pretty strong right now (inaudible) the European community doesn’t blow up in our face, we feel pretty good about rig utilization right now and the day rates. They are going to be gradual, you are not going to see a $1000 a day increase between quarters, but somewhere around the range what we saw in the third quarter, might be a little less going forward for the next quarter or two (inaudible) for new rigs has started to pick back up again, as John mentioned, mostly in the Bakken, so that’s encouraging. It’s somewhat like the mid-stream segment. As much as anything, the leveling factor is people, especially in North Dakota.

Brad Evans – Heartland

Okay. Thank you very much and congrats on a good quarter.

Larry Pinkston

Thanks, Brad.

Operator

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

Larry Pinkston

All right. In closing, we very much appreciate the time that you’ve given us this morning. As you can tell, we have a lot of exciting things happening, not only at Unit, but also in the industry. We believe Unit is in a great position to capitalize on these opportunities and continue to provide good shareholder growth. Again, thank you and hope to see many of you in the near term future. Thanks.

Operator

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

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