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Unit Corporation (NYSE:UNT)

Q4 2011 Earnings Call

February 21, 2012 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

Phillip Jungwirth – BMO Capital Markets

Brad Evans – Heartland Funds

Operator

Welcome to the Unit Corporation Fourth Quarter and year-end 2011 Earnings Conference call. My name is Monica, 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 on this call that address activities, events, or 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 a 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 would now turn the call over to Larry Pinkston, President and CEO. Mr. Pinkston, you may begin.

Larry Pinkston

Thank you, Monica. Good morning everyone. We 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 fourth quarter results this morning. We reported net income of $51.7 million, and earnings per share of $1.08. This represents an 18% increase in net income and a 17% increase on EPS as compared to the fourth quarter of 2010. For the year, 2011 net income increased 34% and earnings per share increased 32%.

We invested $832 million in the capital expenditures during 2011 which included $16 million of acquisitions. We ended the year with a conservative 13% long term debt to total capitalization.

Our contract drilling segment had a very good fourth quarter and year. We began 2011 with an average of 70 rigs operating in January, and utilization increased very steadily during the year to finish the year with an average of 83 rigs operating in December. During 2011, we invested $162 million in new rig additions upgrades and refurbished bits to meet the continuing needs of our customers of horizontal drilling. We finished the year with 127 rigs, we’ve signed a contract to deliver a new 1,500 horsepower drilling rig to North Dakota during the second quarter of 2012. We are optimistic that we will have opportunities to build additional new rigs for customers during 2012.

The movement of drilling rigs out of the dry gas producing basins and to the liquid rich gas basins continues. We currently – we have only six rigs operating, near 7% of our operating fleet drilling dry natural gas wells. However, as the industry continues to adjust, we believe it might further constrain on increasing industry rig utilization and day rates. We think most of this adjustment should be completed by mid-year.

Our Mid-stream segment continues to achieve significant operational growth. Fourth quarter gas gathered volumes were up 13%, gas processed volumes increased 21%, and liquid sale volumes increased 14%; all as compared to the third quarter of 2011. Although operating profit increased 4% for the quarter, margin suffered from a 15% decrease in natural gas prices we received in addition to a 10.5% decrease in liquid prices. We continue to see good opportunities for new systems and expansions to our existing systems, as is evident in our 2012 budgeted capital expenditures for this segment. Our 2012 Mid-stream segment budget is $224 million as compared to 2011 actual expenditures of $79 million.

Our exploration and production segments had a great year. Our equivalent barrel production increased 23% and we replaced 203% of our 2011 production with new reserves. Our liquids production in 2011 increased 55% to an average of approximately 13,000 barrels per day for the year. In the fourth quarter of 2011, we averaged 14,800 barrels per day, and it was 42% of our total average equivalent barrel production. Since changing our focus to liquids at the beginning of 2009, our oil and natural gas liquid reserves have increased to 113%. Our focus for 2012 will remain the same with 98% of our CapEx budget in this division being directed towards oil and natural gas liquid prospects.

Our guidance for 2012 production is 13.2 million to 13.5 million barrels of oil equivalent, an increase of 9% to 12% over 2011. We will continue to monitor natural gas prices and may elect to shut in some of our dry natural gas production during 2012.

Brad and his group have achieved some very good results on new wells completed during the fourth quarter, and I’ll turn the call over to Brad, for more details.

Brad Guidry

Good morning everyone. I’ll start out on the Granite Wash, located in the Texas Panhandle. Our fourth quarter continued to yield consistent results including first oil and gas sales on two new operated horizontal Granite Wash wells with an average working interest of approximately 92%. The two wells completed with first sales during the quarter is lower than our normal four to five wells per quarter, and that was due to delays in the pipeline hook-up on several wells. All of the delayed wells will be brought online during the first quarter of 2012.

The net production from the Unit’s Granite Wash play for the fourth quarter of 2011, averaged 1,136 barrels of oil, 3,065 barrels of NGLs per day and 24.8 million cubic feet of gas per day, and that would have been an equivalent rate of 50.5 million cubic equivalent per day, and that represents a 2% increase over the third quarter of 2011, and a 59% increase over the fourth quarter of 2010. For 2011, we had first oil and gas sales on 16 new wells, which represent a 60% increase in new wells completed as compared to 2010.

The 30-day average production rate for the 16 wells range from 16.7 million cubic feet of gas, equivalent to 2.4 million cubic feet of gas equivalent with an average 30-day production rate of 6.8 million cubic feet equivalent, which is up 5% over 2010 new wells.

The production strain from Granite Wash is comprised of approximately 13% oil, 37% natural gas liquids and 50% natural gas. The Granite Wash laterals that we completed in 2011 targeted six different Granite Wash sands, with 44% of those laterals being in Granite Wash B interval.

The average ultimate recovery for our Granite Wash horizontal is estimated to be 4.6 Bcf equivalent and the average well cost is at $5.5 million.

Currently, there are four unit rigs drilling horizontal Granite Wash wells in our prospect. The drilling program should result in completing approximately 20 to 25 gross operated Granite Wash wells during 2012, at a net capital cost of approximately $92 million.

Moving to the Marmaton oil prospect which is located in Beaver County, Oklahoma. We had an outstanding fourth quarter which resulted in first oil and gas sales on nine new wells with a 30-day production rate ranging from 170 barrels of oil equivalent per day to 930 barrels of oil equivalent per day. The average 30-day production rate for the nine wells in the fourth quarter was 479 barrels of oil equivalent, which is up 40% compared to the third of 2011.

The net production from our operated Marmaton wells for the fourth quarter of 2011 averaged 2,295 barrels of oil per day, 321 barrels of natural gas liquids and 1,000,077 cubic feet of gas per day, which is a 46% increase over the third quarter of 2011, and its 176% increase over the fourth quarter of 2010. The production stream in the Marmaton consists of approximately 78% oil, 14% natural gas liquids and 8% natural gas. For the entire year of 2011, we had first oil sales on a total of 34 Marmaton wells, with an average 30-day production rate of approximately 308 barrels of oil equivalent per day, and that is up 34% as compared to 2010 completed wells. The primary reason for this increase was due to the strong results we achieved in the fourth quarter and the third quarter of 2011. Although the gross ultimate reserves from the second half of wells we drilled in 2011 exceeded our previous reserve projection, the wells that were competed in the first half of the year were below our reserve expectations which results in the projected ultimate reserves remaining unchanged from last year’s estimate of 130,000 barrels of oil of equivalent.

Since we are still in the early stages of drilling out this prospect, was approximately only 37% of our leasehold held by production, the very quarterly production results are to be expected. We do anticipate achieving more consistent result as the prospect matures.

In 2011 alone, we acquired approximately 41,000 net acres, which now brings our current leasehold position to 92,000 plus net acres and we are continuing to lease.

We are currently drilling our first extended lateral Marmaton well on a standup 640 acres spacing unit. The well is scheduled to drill a 9,000 foot lateral at a cost of $4.2 million as compared with our typical well which has a 4,100 lateral at a cost of $2.7 million. Current plans are to drill a second extended lateral well in the second quarter of 2012. For the year of 2012, we plan around two drilling rig program in the Marmaton and that should result in completing 30 to 35 gross wells at approximate net cost of $70 million.

Moving to our Wilcox prospected located in South East Texas; the play is continuing to grow with both productions in prospective new areas to explore. For 2011, we completed 17 wells with an average working interest of 97%, and a success rate of 59%. The net production from our Wilcox field for the fourth quarter of 2011 averaged 1,562 barrels of oil per day, 1486 barrels of NGLs per day and 24.5 million cubic feet per day, which is an equivalent of 42.7 million cubic feet. This is an increase of 34% from the fourth quarter of 2010. The production stream in the Wilcox during the fourth quarter was comprised of 22% oil, 21% natural gas liquid and 57% natural gas.

We currently have 26,000 net acres leased and we’ve entered into a development agreement along trend, with our original prospect covering approximately 47,000 net mineral acres, plus we have acquired additional options covering approximately 82,000 net mineral acres. For 2012, we plan to run one rig continuously in the prospect which should result in about 15 gross wells with approximate working interest of 87%, and an estimated capital cost of $41 million.

In addition to the three plays I just mentioned, we’ve also been acquiring leasehold in the developing Mississippi field located in Oklahoma in Kansas. We’ve now leased approximately 60,000 net acres which is located primarily in South Central Kansas, and we are currently drilling a vertical saltwater disposal well which will be followed by our first horizontal Mississippian well. The estimated cost for the Mississippi horizontal well was $2.9 million and it has projected measured depth of 8,200 feet which includes a 4,200 foot lateral. The current plans in Mississippi are to drill three to four horizontal wells from the next six months and evaluate the results before planning any future drilling.

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

John Cromling

Thank you, Brad. Our contract drilling segment experienced a good fourth quarter as demand remained constant. As Larry mentioned earlier, our average rate utilization during the fourth quarter was 82 rigs, which is approximately 4% increase over the third quarter. For all the year, Unit averaged 76 rigs operating.

Day rates were relatively flat during the fourth quarter. Average day rate for the fourth quarter was $19, 330 as compared to $19,309 for the third quarter. The average per day operating margin for the fourth quarter before elimination of end year company profit was $9,037, which is $624 per day increase over the third quarter or 7% increase. This was attributable to an increase in mobilization revenue and other revenue for a total of $773 per day.

The daily operating expenses slightly increased by about 1% for the fourth quarter over the third quarter.

Earlier this month, we had a wage increase in the Rocky mountain division which will be reflected next quarter in higher day rates and higher daily expenses.

One of our two most recent new builds was commissioned during the fourth quarter in Wyoming and the second one was deployed earlier in January of 2012. We have attained an additional long term contract for another new 1,500 horsepower electric rig scheduled for June delivery to the Bakken play in North Dakota.

Another highlight this quarter was rig 201, our 4,000 horsepower rig. We obtained a contract for ultra-deep well in South Louisiana and recently began drilling.

We also had opportunity to sell another small 600 horsepower mechanical rig which was not a good candidate for our refurbishment program.

As Larry mentioned, the rig utilization has shifted location quite a bit during the fourth quarter for various shell gas plays because of the lower natural gas price. The activity has dropped in the dry gas plays, most notably the Haynesville in the Barnett, and increased in the plays which origin oil and our NGL. The Unit has been able to deploy these rigs to other areas. Most of these rigs have moved to the Granite Wash and the Texas Panhandle and other horizontal plays in both Western Oklahoma and Northern Oklahoma. Also during this period, we have refurbished and contracted two more 800 horsepower rigs that went to work during January in the Mississippi play. We still are confident we will have opportunities to employ more of the smaller rigs in the shallow of our horizontal plays in Northern Oklahoma and Kansas.

In our drilling capital expenditure budget for 2012 is approximately $120 million. 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.

And I’ll now turn the program over to Bob Parks.

Bob Parks

Thank you, John. Our Mid-stream segment is very active in several key producing areas and continues to produce both strong financial and operational results. Mid-stream segment finished the year with record results mainly due to an increase in gas processed and liquids produced.

Operating profits as defined in our press release for 2011 compared to 2010, showed an increase of 3% from $32.4 million to $33.4 million.

2011 gathered volumes and processed volumes were up compared to 2010. Gathered volumes per day increased 17% compared to 2010. Processed volume per day increased 41% as compared to 2010. The processed volume increases due mainly to connecting 62 new wells and adding additional third-party volumes to our existing gathering systems.

In addition to the increase in gathered and processed volumes, our natural gas liquids sold per day increased 52% in 2011 compared to 2010. This increase was primarily due to an increase in volumes processed from new wells connected and improved plant processing efficiency.

During 2011, we incurred capital expenditures of $79.4 million as compared to $29.8 million in 2010. As previously mentioned, for 2012 we have budgeted capital expenditures of approximately $224 million.

I would like now to provide an update on our activities in Mid-continent and Appalachian areas. I’ll speak first about our activities in the Mid-continent. Our Hemphill processing facility in the Texas Panhandle, we are currently processing approximately100 million cubic feet per day. Our total processing capacity increased to approximately 115 million cubic feet per day after the successful installation of a fourth processing plant in completing the latest plant upgrades.

Due to the high level of activity around our Hemphill facility, we are again in the process of expanding the processing capacity at this facility by adding an additional gas processing plant. This new plant expansion project will add an additional 45 million cubic feet per day of processing capacity, and will increase our total processing capacity to approximately 160 million cubic feet per day. This new plant expansion project is scheduled to be completed in the second quarter of 2012.

At our Cashion gathering and processing facility in Central Oklahoma, we are continuing to connect new wells and are in the process of completing the installation of a new 25 million cubic foot per day processing plant. The installation of the new 25 million, high-efficiency turbo extender plant will be completed in the first quarter of 2012. Also at our Cashion, we have completed the expansion of the gathering system to the North, across the Cimarron River, to gather gas from new wells drilled north of the river.

We are continuing to be very active in the Mississippi Lime in North-Central Oklahoma. In 2011, we completed the construction of our first new system in the Mississippi Lime, which is located in Great County, Oklahoma. This new gathering system currently consists of approximately seven miles of high-paced skid-mounted gas processing plant. Also in this area, we have begun construction of another gearing of processing system located in Noble and Kay Counties in Oklahoma. This new system will initially consist of approximately 10 miles of high and a 10 million cubic foot per day gas processing plant that will be upgraded to a 30 million foot per day gas processing plant in the fourth quarter of 2012.

In addition to these projects, we are actively pursuing other opportunities in our Mississippi Lime play and are currently in discussion with various producers that may lead to potential new projects or expansion projects at our existing facilities.

In the Appalachian area, we have also continued to be reactive and are expanding our operations. In 2011, we completed the construction of a 16 mile, 15-inch gathering system and compressor station in Preston County, West Virginia. This system became operational in the fourth quarter of 2011 and is currently flowing approximately 6 million cubic feet per day of gas. Also in the Appalachian area in the fourth quarter, we connected the first well on a new gathering system in Alleghany and Butler Counties of Pennsylvania. This well is currently flowing approximately 5 million cubic feet per day. We are in the process of expanding this system to the North to connect additional wells and are currently constructing a compressor station required to accommodate additional volumes. We anticipate to putting this expansion in mid-2012.

We are optimistic as we kickoff 2012. We are looking to both expand existing facilities and to expand in the new areas as we continuing to see a lot of drilling activities in both the Mid-continent and Appalachian regions.

I’ll now turn the call over to David Merrill.

David Merrill

Thanks Bob and good morning everyone. For the year ended 2011, Unit had total revenues of $1.2 billion and EBITDA of $604 million each, an increase over 2010 of 37%. EBITDA for the fourth quarter of 2011 was $165 million, an increase of 3% from $160 million in the third quarter of 2011 and an increase of 24% from $133 million in the fourth quarter of 2010. For the fourth quarter of 2011, the oil and gas segment contributed 60% of EBITDA, contract drilling contributed 36% and midstream 4%.EBITDA for the fourth quarter increased from the third quarter in the contract drilling in Mid-stream segment and decreased in the oil and natural gas segment.

For the contract drilling segment, the increase was primarily attributable to a 4% increase in the number of drilling rigs operating from an average of 78.9 drilling rigs in third quarter to an average of 82.1 in the fourth quarter, combined with a 7% increase in operating margins per rig per day before elimination of intercompany rig profit.

For the midstream segment, the increase was primarily attributable to a 21% and 14% increase in process volumes and liquids sold volumes respectively. For the oil and natural gas segment, the decrease was primarily attributable to a 21% increase in operating costs per BOE, somewhat offset by an increase in equivalent production and realized commodity prices at 4% and 2% respectively. The increase in operating costs per BOE was primarily attributable to a $4.5 million refund of production taxes associated with high cost of gas wells received in the third quarter. Excluding the impact of the third quarter high cost gas well production tax refund, operating costs per BOE increased 5%, with the increase being primarily attributable to work over activity and salt water disposal costs.

DD&A for the oil and natural gas segments in the fourth quarter increased 9% from the third quarter, primarily due to increased production and an increase in the DD&A rate. The DD&A rate for the fourth quarter was $15.66 per equivalent barrel, an increase from $15 per equivalent barrel in the third quarter.

Depreciation for the contract drilling segment for the fourth quarter increased 7% from the third quarter, primarily due to the 4% increase in the number of drilling rigs operating. Depreciation per rig per day for the fourth quarter increased 3% from the third quarter to approximately $3000.

For the oil and natural gas segment, currently for 2012 we have had approximately 6100 barrels per day of oil production and 50,000 MMBPU per day of natural gas production. We also have some natural gas liquids production hedged, most of which is for the first and second quarters of 2012. The oil production is hedged at an average price of $97.55 and the natural gas production is hedged at an average price of $501. We also have some 2013 hedges in place for oil, the detail of which is included in our Form 10-K which will be filed this week.

Recapping the capital expenditures that you heard about from the various segments, for 2012 our operating segment capital expenditure budget is $801 million, an increase of 6% over 2011 excluding acquisitions. Budget and capital expenditures by segment are $457 million for the oil and natural gas segment, $120 million for the contract drilling segment and $224 million for the midstream segment. The 2012 capital program is anticipated to be funded using internally generated cash flow and borrowings under our credit agreement.

The effective tax rate for 2011 was 38.6%. We currently estimate the effective tax rate for 2012 to be 38.7%, all of which is anticipated to be deferred.

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

Question-and-Answer Session

Operator

Thank you. (Operator instructions). Our first question comes from Phillip Jungwirth of BMO Capital Markets. Please go ahead.

Phillip Jungwirth – BMO Capital Markets

Hey. Good morning guys. Could you provide an approximate breakout of the NGL components just between ethane, propane and others?

Larry Pinkston

Phillip, I don’t think we have that in detail.

Phillip Jungwirth – BMO Capital Markets

That’s okay.

Larry Pinkston

We’ll certainly look at it and get back with you. But I don’t think we have that with us in detail.

Phillip Jungwirth – BMO Capital Markets

Okay, that’s fine. And do you have an estimate of what percentage of the NGL volumes are going to Conway versus Mont Belvieu or just what you think your realization would be today as a percent of WTI?

David Merrill

Philip, about a little over 30% is Belvieu with the balance being Conway.

Phillip Jungwirth – BMO Capital Markets

Okay. And then how would the ethane rejection in the mid con impact the production volumes in 2012?

David Merrill

As of right now we’re not having much of an issue there. If they reject ethane that just increases the gas, the volume of gas and the gas in that stream.

Phillip Jungwirth – BMO Capital Markets

Okay. Do you have an expectation for midstream margins, how that should trend throughout 2012?

David Merrill

Yeah. It should be – our margins should grow obviously during the course of the year with a lot of the expansions and new plants that we’re putting in. The trajectory of that, Philip, has got to be more second half of the year oriented. The processing plants expansion that Bob had referred to out of Hemphill, that will be a second quarter event, probably later in the second quarter event. The plan – what’s going on out in the Mississippi end play. That will be somewhere in the second quarter, probably those volumes will ramp up over time. They won’t be an immediate item. So we should see certainly growth, but it will be second half oriented for the most part.

Phillip Jungwirth – BMO Capital Markets

Okay. And in the Wilcox play, are newer wells that you’re drilling achieving that similar commodity mix that you mentioned in the fourth quarter, 22% oil, 21% NGLs?

Brad Guidry

It varies a little bit, Philip. In general, we think about the Wilcox being about 50% liquids, 50% Wilcox. That mix is the actual production over the fourth quarter. But we see quite a bit of variety in the completions that we have out there from pure oil wells to probably that – what we reported in the fourth quarter is probably the low end and part of that was due – we drilled a couple of pretty big gas wells during the fourth quarter. So the gas production was up a little bit higher on those wells than what we would normally see.

Phillip Jungwirth – BMO Capital Markets

Okay. And then in 2012, how many of the wells are being drilled in that southern expansion area and then can you talk about the results that you saw in that area in 2011?

Brad Guidry

Just in the south part?

Phillip Jungwirth – BMO Capital Markets

Yes.

Brad Guidry

For 2012, probably it won’t be more than two or three wells drilled in the south expansion. We’ll have a new map as we come forward that’s kind of updating. One of the things that we’re really pleased with is that we’ve been able to really increase the amount of perspective acreage that we are going to get to explore on, almost equivalent to what our original footprint was out there and the southern area, we’ve had some success. In 2011 I think we had three completions down there. But we also had probably the same amount of dry holes in that southern region and the southern region appeared to be a little more difficult to prospect in. A little higher risk than what we’ve seen as we’ve gone to the North. So we really try to focus most of our efforts probably on the northern part of our original play area and that’s where these new trend areas that we’ve gained the right to explore on are located.

Phillip Jungwirth – BMO Capital Markets

Okay. And then last, you mentioned potentially shutting in production. What would prices need to get to for you to look at doing that and then which fields or plays would be potential candidates for shutting in production?

Larry Pinkston

Well, the fields would be mostly Arkoma basin. That’s the predominant dry gas area that we have and I think any time gas is down around $2 we have to take a very serious look at it and realistically we are looking at probably 10 to 15 million a day.

Phillip Jungwirth – BMO Capital Markets

Okay, great. Thanks guys.

David Merrill

Hey Philip, before you jump off, based on our fourth quarter NGL production, about 44% was ethane, about 30% was propane and then the balance is made up of the other heavies.

Phillip Jungwirth – BMO Capital Markets

Great. Thanks.

Operator

(Operator instructions). The next question comes from Brad Evans of Heartland Funds. Please go ahead.

Brad Evans – Heartland Funds

Thank you. Good morning everybody. So it looks like if you were to shut in that production – I mean the net effect on a revenue basis is what, about $10 million to $15 million in revenue?

Larry Pinkston

Well, it depends on how long we keep the shut in and I don’t imagine it would be hopefully more than two or three months timeframe. But again for us is – I’m feeling better about not seeing $2 gas prices, at least in the short term here with demand coming up with all the coal displacement. So I thought it was a pretty serious issue maybe 30 days ago. Hopefully now we may not see those come at low gas prices this summer. But it’s something we’ve got to keep monitoring it.

Brad Evans – Heartland Funds

I guess that’s the point that I was – even if you were to annualize it, it would be what, $5 million or $10 million of EBITDA worst case, right?

Larry Pinkston

Yeah. It will be a…

Brad Evans – Heartland Funds

It doesn’t really move the needle in terms of your runaway and cash flow?

Larry Pinkston

No.

Brad Evans – Heartland Funds

Okay. That’s good. Larry, your comments, I was intrigued by them in terms of your thoughts on the – I think you had indicated in your opening remarks that you thought the migration from dry gas to liquids richer oil basins would result in a flattish recount through the first half. Did you mean to imply that so long as liquids prices remain favorable that you would expect to see utilization move higher than in the second half of the year? Is that how you see the world presently?

Larry Pinkston

Yeah. The way I see the world today which could change this afternoon. I think we’re seeing some – in the last 30, 45 days and coming up over the next 30 days, we’re seeing some pretty rapid movement even with the gas rigs that are still left in the dry gas areas and moving out to different areas and the transitions, right now there’s demand for those rigs in other areas. But the transition doesn’t happen overnight. You may have a rig go down. It may be 45 days before it moves into the different area or a different operator and it’s not just us. The whole industry is going through the same transition and until the current rig count gets shuffled out into the liquid basins where you don’t have so much movement between operators and you have a 20 day period where rigs are available and then they’re gone. It’s just going to be tough to put additional rigs to work in the industry and I think the correspondingly to try to do anything on upping day rates until we’re through this period.

Brad Evans – Heartland Funds

Okay. And so would you expect to hope to – when you think about it on the drilling side, EBITDA per rig day, would you just hope to hold that flat then in the first half relative to what you saw in the fourth quarter?

Larry Pinkston

Yeah. I think if we can do that for the first – really the first half of the year, I think that would be a good position then for us to build on second half going forward.

Brad Evans – Heartland Funds

Okay. I’ll get back in queue. Thank you very much.

Larry Pinkston

Thanks Brad.

Operator

(Operator instructions). Our follow up question is from Brad Evans. Please go ahead.

Brad Evans – Heartland Funds

Okay, that’s great. Do you have any plans for drilling wells in West Texas this year?

Brad Guidry

We’ll probably drill a handful. It won’t be a whole lot. Pretty much our take on the Permian is we’ll wait when the plays come to us. We do have a stab that’s looking at our leasehold and working that and – but yeah, we’ll probably drill four or five wells down there that will be horizontal. We drilled two wells in 2011, two horizontal bone springs that really turned out very well, primarily oil wells. Good initial rates coming on and we’ll have opportunities with that. The Permian won’t be maybe a dedicated play for us, but it will certainly be an integral play that we’ll utilize to maintain production.

Brad Evans – Heartland Funds

Brad, can you just refresh our memory of the – what your acreage position is in the West Texas area right now?

Brad Guidry

We’re determining that as we speak. A lot of our Permian acreage came through acquisitions and we just don’t have a great handle on the acreage number and quite honestly we’re in that process right now of trying to get all that leasehold into our system. My expectation is it will probably be 20,000 or so.

Brad Evans – Heartland Funds

And that would be mostly prospective for the bone spring and the Wolf Camp shale or just mostly Bone Spring?

Brad Guidry

No, it’s spread all over. We’re seeing – our New Mexico portion of that which is where we drill the well flaps here, our position is really not that big. Our bigger position would be over in the Texas part of it and there will be upsides. But I can’t even venture to tell you right now with any confidence of what that upside would be.

Brad Evans – Heartland Funds

Okay. Thank you for that. Larry or Brad, why not accelerate the Marmaton program, 30 to 35 wells? The results have been – you seem like you’ve hit an inflection point in terms of the recent wells there. I know it can be volatile and it’s not uniform of course, but it seems like the recent wells there have been extremely favorable.

Brad Guidry

Yeah. The main reason at this point is we’re still in the learning stage of what we’re doing. We’re drilling our first 12 or extended lateral 9,000 foot lateral. If that works we’ll certainly try to develop more the feel in that direction. The other part, the manpower with drilling 35 wells a year requires quite a bit of manpower to stay in front of the land and everything else out there. When we first started out here we thought we would go to three rigs because the drilling days was taking us quite a bit longer to get done. But as drilling times have come down and things have become more efficient, we’re comfortable right now with what we know about the players. We’re still defining it to stay in this two rig pattern. We probably will drill a handful of wells, maybe get a third rig in there for a short period of time to meet some lease obligations. But we’re still learning. I think once we get to the point we consider it fully a development play then that will be a decision maybe to accelerate.

Brad Evans – Heartland Funds

Okay. And then just last question for Larry. Do you see the opportunity to sell non-core assets to perhaps to fill that say cash flow void relative to CapEx this year? Or do you – I know you said – I know David had indicated that perhaps borrowings might be used. But it seems like there might be an opportunity to divest non-core assets. Is that something you might pursue?

Larry Pinkston

Yeah. Brad, we’re definitely looking in that to see and it primarily would be in our EMP side, some areas. This Wilcox play is developing so big that it’s really hurting as far as looking at other areas, other acreage that we have in the area and if we’re not going to be able to focus on the other areas, the question is do we need to go in and try to sell those and assess whether we need to get out of those areas or what to do with them. But yes, we’re going through that process right now. I think sometime this year we’ll look at the rig inventory that we have to see if we want to do something. You were able to kind of sell them here and there, but are we at a stage where we just want to go ahead and do whatever to get rid of 10 or 12 or 15 of the lower horsepower rigs. So we are definitely going through that. It’s not for sure by any means that the deficit would be met up. We are definitely looking at that.

Brad Evans – Heartland Funds

Well, your balance sheet is the rock of Gibraltar. So it clearly can support a little more debt. Last question. David, what is the net book value of the less than 700 horsepower rigs within the fleet?

David Merrill

The overall group, I don’t have that handy. Like the rigs we just sold – the one we just sold was less than $400,000 net book value. I think most of that smaller category is somewhere around $14 million, $15 million net book value.

Brad Evans – Heartland Funds

In the aggregate?

David Merrill

In the aggregate, correct.

Brad Evans – Heartland Funds

Okay. Congrats to the team on a great year. Thanks very much.

Larry Pinkston

Thanks Brad.

Operator

(Operator instructions). We have a follow up question in queue from Phillip Jungwirth of BMO Capital Markets. Please go ahead.

Phillip Jungwirth – BMO Capital Markets

Hey guys. On the land drilling CapEx, how much of that is maintenance versus new build versus upgrades or how many rigs do you expect to upgrade in 2012 and potentially put back to work?

Larry Pinkston

Well, that’s a great question yeah is dependent on the demand for it. We only have several rigs that we are capable of upgrading that’s not in the 120 million that as demand is there we would look at these and upgrading more rigs and our plans are up now. Our day-to-day maintenance CapEx, Phillip that we use is – it runs about $700 a day per rig operating. Anything above that would be bordering on the line of upgrades. The new rig that we’re building is going to be $15 million, $16 million type of rig that’s going to North Dakota.

Phillip Jungwirth – BMO Capital Markets

Okay. And then on the rigs rolling off long term contracts in the first half of 2012, are those primarily drilling liquids and do you think you’ll be able to re-contract those at similar rates, higher rates, lower rates?

Larry Pinkston

Most of them are drilling liquids. I think there’s a few, maybe two or three that may be in some of the dry gas basins and they probably won’t be renewed in those basins. But it’s not easy. It’s not something we make one phone call and they go to work somewhere else. So far we’ve been able to maintain the utilization and it may not exactly be the same rigs. We may have a rig going down in Haynesville that we’re putting a rig to work – a different rig to work in the Mississippi end play. So it is quite a transition right now that we’re going through. But so far the demand for the liquids and the oil drilling is hanging in there pretty good.

Phillip Jungwirth – BMO Capital Markets

Okay. And then do you have any East Texas or cullen basin drilling plan in 2012?

Brad Guidry

The only drilling we would do there would be in an on off position. We still have a couple of operators that are proposing horizontal Woodford wells in the Arkoma and we’re most likely not going to participate. But we will not initiate any drilling in either of those areas this year.

Phillip Jungwirth – BMO Capital Markets

Okay. And last, do you have a PDP percentage for the breakout between gas and liquids?

Larry Pinkston

David is searching. Yeah, we do have.

David Merrill

Dialing for information. Hang on for a second, Phillip. Let me give it to you this way as far as what PUD. On oil our PUDs are 23%. On liquids it’s 25% and on gas it’s 16%.

Phillip Jungwirth – BMO Capital Markets

Perfect. Thanks guys.

Operator

(Operator instructions). I show no further questions in queue. I will now turn the call back over to Larry Pinkston for any closing remarks.

Larry Pinkston

Thank you, Monica. We very much appreciate the time you’ve given us this morning. As you can tell, we have a lot of exciting opportunities going on not only as Unit, but as the industry as a whole. We will be presenting at the EnerCom Conference in San Francisco tomorrow morning at 9:15 West Coast time and then we will be in Orlando on March 6th at the Raymond James Conference with a presentation time of 4:00 PM East Coast time. We hope to see many of you at those conferences or other places over the next couple of three months and we thank you for listening. Thanks.

Operator

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

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