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Executives

Larry Pinkston - COO

Brad Guidry - EVP, Exploration

David Merrill - CFO

Analysts

Jim Rollyson - Raymond James

Robert Christensen - Buckingham Research

Brad Evans - Heartland Advisors

Unit Corporation. (UNT) Q2 2010 Earnings Call August 3, 2010 11:00 AM ET

Operator

Good morning and welcome to the Unit Corp. Second Quarter 2010 Earnings Call. My name is Sheryl and I will be facilitating the audio portion of today's interactive broadcast. All lines have been placed on mute to prevent any background noise. (Operators Instruction) This event after features streaming audio which allows you to attend to the show through your PC speakers.

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 or may occur in the future are forward-looking statements.

A number of risks and uncertainties that could cause actual results to differ materially from these statements, including the impact that the current decline in wells being drilled will have on the production and drilling rig utilization, productive capabilities of the company's wells, future demand for oil and natural gas, future drilling rig utilization and dayrates, projected growth of company's oil and natural gas production, oil and gas reserve information, as well the ability to meet its 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, availability and timing of obtaining third party services used in the drilling or completion of its oil and gases, anticipated oil and natural gas prices, the number of wells to be drilled by the company's exploration segment, 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 like to turn the call over to Mr. Pinkston. Sir, you may begin.

Larry Pinkston

Thank you, Sheryl. Good morning, everyone. We want to thank you for calling in to our second quarter conference call. I have with me today are David Merrill, our CFO; Brad Guidry as the Executive Vice President of our Exploration Segment; John Cromling as Executive Vice President of our Contract Drilling Operations and Bob Parks as President of our Mid-Stream Segment.

I will spend a few minutes recapping our second quarter results including an update on a contract drilling in our Mid-Stream Operations, Brad will discuss the details of our E&P operations and David will go on some key financials facts. Then we'll take questions after our comments are complete. We released our second quarter results to the public this morning. We reported net income of 32.2 million and earnings per share of $0.68 per share, this compares to a net income of $36.2 million and earnings per share of $0.76 per share in the first quarter of 2010.

The reduction was due to lower operating margins in our oil and gas in Mid-Stream divisions that was somewhat offset by higher margins and our Contract Drilling segment. And our Contract Drilling segment, we achieved a 28% improvement in operating profit before depreciation as compared to the first quarter of 2010. Revenues for Contract Drilling increased 19% during the second quarter, driven mostly by 14% increase in average number rigs working during the quarter and a 6% increase in average dayrates.

We averaged operating in 58 rigs for the quarter as is up seven from the third quarter; demand for our drilling rigs continues to gain momentum especially the rigs that are equipped to drill horizontal wells. We are currently operating 65 rigs and have 71 under contract. We have term contracts in place that were initially for periods primarily of six months to one year on 42 rigs. We have relieved that we would average 66 to 67 rigs operating in the third quarter.

Average dayrates have continued to improve during the year. Our second quarter average dayrates was 49 per day, that's $500 a day from the third quarter since the beginning of 2010 our average dayrate is up $1,100 per day and we exited the second quarter with $15,100 a day. Our costs per day between the first and second quarter was relatively unchanged.

Effective early in July, we have a labor increase on our rigs, labor increase or increase on average operating cost approximately $300 across our fleet, our contracts enabled us to pass this cost increase through the operators, virtually all of our rigs.

Our refurbishment program for drilling rigs is progressing, it's mid December of '09, we've upgraded 23 rigs and still have 12 rigs remaining to complete by the end of the year. Of the 123 rigs that we currently have in our fleet, we have 90 rigs that we feel are or will be competitive once the upgrades in the horizontal drilling marketplace were completed.

We have an inventory, the major components to be on 1,500 horsepower rigs, we will continue to monitor demand in margins to determine if these new bills should be constructed.

Our Mid-Stream segments financial results continued to remain strong during the second quarter, even though the gross margins declined from the first quarter of 2010, which was primarily due to lower overall liquid process. Gross margins in the second quarter 2010 compared to the second quarter of 2009 showed an increase from 4.0 million to 7.4 million.

Both gathered and processed volumes were higher in the first quarter mainly due to connections in new wells through our existing systems, along with upgrades and expansions to our processing plants. Natural process volumes per day increased 8% and 10% during the second quarter of 2010 as compared to the first quarter of 2010 and the second quarter of 2009 respectively. Natural gas liquid sold per day increased 10% and 17% from the same period comparisons.

Our construction of the 50 million a day turboexpander style processing plant in the Texas Panhandle, we're constructing to process the Granite Wash production, is proceeding as planned, the construction activity is continuing in scheduled to be completed early in the fourth quarter of 2010. Construction is progressing on the new 6 million a day processing plant at our Osage County, Oklahoma gathering and processing facility. The construction of this processing plant is due to growth and volume from our producer and is scheduled for completion there in the third quarter of 2010.

In addition to these plants already under construction, we continue to evaluate several grassroots plant construction projects in Mid-Continent and the other geographical regions. We are continuing our activities in the Appalachian Basin with several existing projects, projects moving forward as planned. Our Center County, Pennsylvania project continues to progress with final round preparations in acquisition and right away. Also the project in Preston County, West Virginia, which consists of a 14-mile truck line is continued to be developed.

We are overseeing the process of obtaining permit, reforming environment assessments and obtaining or otherwise for this project. With our existing projects moving forward in various stages of development, we're still continuing to explore new opportunities beyond these I mentioned that arise in Pennsylvania and West Virginia.

In our exploration production segment, our revenues were down by 1 million during the second quarter compared to the first quarter, the reduction was due to primarily to lower commodity prices. Our realized prices, including the effect of our hedge production, oil was down by $0.40 a barrel, natural gas was down by $0.33 per Mcef and natural liquid process were down by $9.39 per barrel.

Our drilling program gained momentum in the second quarter. We drilled 39 wells in the second quarter as compared to 27 wells in the first quarter, was up 44%. We will continue to increase our drilling for the remainder of 2010 and we're still on schedule to meet our target of 175 wells for the year. We're continuing to see significant delays in getting wells fracked and on production.

Of the 39 wells we drilled in the second quarter, 46% of the wells are still awaiting completion in order for production to begin. A very good example of that is in the recently announced Marmaton play in the Oklahoma Panhandle. We have seven wells that are drilled and at the moment the earliest that we can get frac dates scheduled is in October. These delays should be minimized that we work our drilling schedule and to the frac company schedules, however, these delays are currently having a significant effect on our current year production. Because of these delays, we are reducing our production guidance for the year to range of 62 to 63 Bcf equivalents.

We are very excited about the momentum production in acreage acquisition that we announced in July, and acquisition provides over 300 potential locations that we've already identified. The production is predominantly oil with a very risk associated natural gas production, their acreage is very concentrated which will provide many efficiencies as we develop the field.

I'll now turn the call over to Brad, and he can discuss our drilling program in more detail.

Brad Guidry

Good morning everyone. I'll go ahead and start out with additional details on the Marmaton, we press released July 21st of the property acquisition and, as Larry mentioned, it is a horizontal oil play located primarily at the Beaver County, Oklahoma. The Marmaton zone is a fractured carbonate reservoirs approximately 300 feet think in the average step towards this zone is about 6,500 feet. The Marmaton has been produced vertically across a large portion of our leasehold for the last 30 years and they estimated ultimate reserve range from those vertical wells since from 10,000 up to 269,000 barrels per well. On average reserves it's over approximately 80,000 barrels per vertical well.

Utilize in this historical production from this vertical wells and the results from the recently drilled horizontal wells, a decline type curve is possible that projects an average estimated potential recovery of approximately 120,000 barrels of oil and associated gas of 120 million for horizontal well with a projected 4,000 foot lateral.

The horizontal wells will take approximately 20 days to drill and this total cost for a completed wells approximately $2 million. The initial first month of production after fracture stimulation has typically been about 300 barrels of oil a day, 1,200 barrels of water per day and 300 Mcef a day, with the projected first year annual decline of approximately 80%. The associated gas is very rich, has 1,500 BTU and that yield is about seven and a half galloon per NGLs per Mcef.

Since the acquisition we've drilled five additional wells, along with two others previously drilled wells that are all awaiting fracture stimulation. We currently have secured six frac dates in October and working on securing two to three frac dates per month on a continuous basis into 2011. Currently we have one unit rig working in the Prospect and we planned that second rig in a couple of weeks in mid August and then possibly a third rig at the end of this year.

We've identified approximately 300 potential gross well locations on our 56,000 net acre lease block. This acquisition complements the presence that we already have in the Anadarko Basin, which is one of our core areas of operations.

Through the second quarter in the Granite Wash play located in Roberts and Hemphill County, we completed one horizontal well and one vertical well. The Isaacs B-5H is the horizontal well that we have 35% working interest, it was completed in May of this year in the Granite Wash B interval and also represents the highest equivalent rate to date that we've had on our Granite Wash horizontal. The total cost rate as well as approximately $5.8 million which included 11 stages of frac simulation.

The Webb number two, which we have 83% working interest of the vertical Granite Wash well that is completed in June at the rates of 2 million cubic feet a day, a 100 barrels of oil per day and 230 barrels of NGLs per day from equivalent rate of 4 million and that was having approximate total well cost of 1.6 million.

Three other operated Granite Wash horizontal wells, the Brown B-13H which we have a 50% working interest and it's in the A zone, the Temple A-1H, 50% working interest in the B zone and the Webb 3H which we have 83% working interest which is also in the B zone, all three of those wells have finished drilling operations and are scheduled to be fracture stimulated in August and September. We currently have three unit drilling company rigs, drilling Granite Wash horizontals and we planned to add a fourth rig during September of this year.

The majority of the new Granite Wash horizontal wells are planned to target either the A or the B interval which appears to have the best world performance today. Our expectation is to keep these rigs operating in the Granite Wash play for the remainder of this year and all of next year. With these four rigs operating, we expect to bring on two to three horizontal wells each months starting in August of this year.

We also see the increase in some of our outside operated activity in the Granite Wash, we have a 12.5% working interest in the [Zibac] number 2-10H which is located in Wheeler County, that well was completed in late June by another operator at a production rate of 8 million cubic feet a day, 400 barrels of oil per day and 1,100 barrels of NGLs on equivalent rate of 17 million cubic feet per day. Also, we have a 17% working interest in Anna, number one 20H which is currently being drilled in the colony area of Washington County by another operator.

In addition to our Granite Wash in the Texas Panhandle, we've also drilled Laubhan B-3H, which we have 100% working interest that was completed in the equivalent formation. In June of this year, the well was completed following 2.9 million cubic feet of gas per day and 120 barrels of oil per day. Unit has approximately 19,000 gross or 11,000 net acres in equivalent play which will support approximately 120 gross horizontal wells.

We've also mentioned before we've spudded our first horizontal Atoka test in our Mile High prospect located in the Southeast Colorado, during the early June and that well has now finished drilling and is scheduled to be fracture stimulated in mid September. This is the area that's only perspective for the Atoka, but also the Cherokee and these are both oil areas that we've identified. In this play, we've accumulated about 50,000 net acres and the majority of leases in their have five-year terms.

Moving to the Segno prospect located in the Texas Gulf Coast, we drilled three new Wilcox wells during the second quarter. The BP Blackstone Gas Unit number one showed the very Blackstone Gas Unit number one and the Blackstone BP number one. The BP Blackstone Gas Unit number one was competed following 4.3 million cubic feet a day and 22 barrels of oil per day and that was going to sales prior to having to shut it in to run tubing, which is currently being done.

The Sugarberry Blackstone the number one is producing 375 barrels of oil per day and 700 Mcf a day to sales and then the third well of Blackstone BP number one is still waiting on completion operations. In addition we completed our third and final exploratory outlook -- exploratory obligation well in our joint venture area to the south of Segno, which we call our Koontz West Prospect.

The third well the BP number one L encountered several potential Wilcox pay sands and has been completed in beat of this sands testing at a pre-frac rate of 2.5 million feet a day and 90 barrels of oil per day. All three wells in the Koontz West Prospect are current shut in, awaiting pipeline connection. We anticipate keeping two unit rigs working in Segno and the Koontz West Prospect area for the remainder of this year.

In our Stockman prospect located in Shelby County, Texas was Smith number 1-H which we have 55% working interest was recently fracture stimulated in the Haynesville Shale, is currently flowing at rates of 3.5 million cubic feet a day with 5,800 pounds of flowing tubing pressure. The well is being curtailed due to pipeline constraints which we expected to be resolved in September this year. The well was completed from 3,300 feet of lateral and fracture stimulated in eight stages.

The second horizontal well is expected to spud with the next month with plans to drill a third well by year end. Unit owns approximately 16,000 gross, 11,000 net acres in this prospect. To the north, in our Longview prospect located in Harrison County, we've secured a frac date for mid August for the Lawrence number 1-H which we owned a 100% working interest and this is the pump the final four stages at the plant seven stage frac. We were successful in upping the first three stages in the Haynesville lateral in March but we were unable to pump the final four stages at that time due to downhole mechanical problems. The well tested approximately 2 million cubic feet a day at 4,200 pound falling tubing pressure following the fracture simulation of the first three stages.

In the Marcellus Shale play which located primarily in Somerset County, Pennsylvania, we owned a 25% working interest and approximately 190,000 gross acres. We'll continue and evaluate the production decline on the latest horizontal well that was completed in early April of this year at a rate of approximately 1.5 million cubic of gas per day and that well is currently still producing at 1.1 million cubic feet a day. The well was drilled with 2,600 foot lateral and frac stimulated in eight stages. The current plant in the Marcellus is to drill three horizontal well and this will begin in the first quarter of 2011 that has been delayed, originally we were taking about those wells been drilled in the fourth quarter of this year so it's been pushed back to the first quarter of '11.

In the Bakken play in North Dakota, Unit owns a 25% working interest and approximately 1,500 gross aces and our Stockyard Creek Prospect that is located in Williams County. In this Prospect, we originally drilled two horizontal Bakken wells, the first the Grasser number one had first production in mid-May and it was flowing at initial rates 2,000 barrels of oil per day and 1.4 million cubic feel per day. The well was drilled on a 640 acre spacing unit with a 5,700 foot lateral that was fracture stimulated in 20 stages.

The second well is Marty number 1-20H and it's in the early stages is a flow back after fracture stimulation in the early rates of approximately 1,500 barrels of oil per day and 1.6 4 million cubic feel per day. This well was also drilled on a 640 acre spacing unit with a 5,736 foot lateral and was fracture stimulated in 15 stages. There's one drilling rig scheduled to be operating in this Prospect during the remainder of 2010.

Also in the Bakken in McKenzie County, North Dakota, Unit owns a 16% working interest in the Dodge number 4-6/7 HR well which is a horizontal well that was recently completed at rates of 2,465 barrels of oil per day and 1.6 million cubic feel per day. The well was drilled on a 1,288 acre spacing units and it had a lateral wing of 8,846 feet and was fracture stimulated in 24 stages. In this Prospect, in McKenzie County we owned 27,000 gross and 5,400 net acres we call it our Antelope Prospect and we also anticipate one rig drilling in this Prospect during for the rest of this year.

With that I'll the call back over to David.

David Merrill

Good morning everyone. EBITDA for the second quarter of 2010 was 99 million, a decrease of 3% from 102 million in the first quarter of 2010 and an increase of 7% from 93 million in the second quarter of 2009. For the second quarter of 2010, the Oil and Natural Gas segment contributed 67% of EBITDA; Contract Drilling contributed 25%, and Mid-Stream 8%.

EBITDA for the second quarter increased from the first quarter in the Contract Drilling segments and decreased in the Oil and Natural Gas and Mid-Stream segments. For the Contract Drilling segment, the increase was primarily attributable to a 14% increase and the number of drilling where it's operating from an average drilling rig utilization of 40% in the first quarter to 47% in the second quarter, combined with a 15% increase in operating margins per rig per day before elimination of inter-company rig profit. Excluding contract termination fees, operating margins per rig per day before elimination of inter-company, rig profit increased 16%.

For the Oil and Natural Gas segment, the decrease was primarily attributable to lower realized commodity prices and production somewhat offset by lower operating cost. Realized prices including hedges for natural gas, liquids, natural gas and oil decreased 22%, 6% and 1% respectively and equivalent production decreased 1%. Operating cost per equivalent Mcef, decrease 3% from $1.77 to a $1.71.

For the Mid-Stream segments, the decrease was primarily attributable to a 15% decrease in blended frac spread margins, somewhat offset by a 10%, 8% and 2% increase in per day liquid sold, gas process and gas gathered volumes respectively.

DD&A for the Oil and Natural Gas segment for the second quarter increased 4% from the first quarter primarily as a result of the acquisition of Oil and Natural Gas properties that we had previously announced. The DD&A rate for the second quarter was a $1.87 per equivalent Mcef, up from a $1.78 per equivalent Mcef in the first quarter.

Depreciation for the Contract Drilling segments for the second quarter increased 19% from the first quarter primarily due to a 14% increase in the number of drilling rigs operating. Depreciation per rig per day is up 3% at $3,110 a day.

For the Oil and Natural Gas segment, we have had approximately 68% of our anticipated 2010 natural gas production at a weighted average delivered for approximately $6.29 and approximately 65% of our anticipated 2010 oil productions at a weighted average price of $67.28. Approximately 11% of our natural gas liquids production is hedge for the balance of 2010 at a weighted average price of $41.12.

In addition, we have hedged 15,000 MMBtu per day of our 2011 and 2012 natural gas production at a weighted average delivery point price of $5.42 and $5.62 respectively. We have hedged 2,500 barrels per day of our 2011 oil production at a weighted average price of $80.32 and 1,500 barrels per day of our 2012 oil production at a weighted average price of $82.49.

Total capital expenditure excluding acquisitions from our operating segment for the first six months of 2010 were 215 million. For 2010, our capital expenditures budget for all three operating segments combined, its 494 million, excluding acquisitions.

The 2010 capital expenditure budget is anticipated to be fully funded mainly from the internally generated cash flow into the lesser expense from borrowings under our credit facility. The effective income tax rate for the 2010 second quarter was 38.2% essentially unchanged from the first quarter and should approximate the rate for the year. The percentage of tax expense to be deferred and decreased from the first quarter primarily due to an increase in estimated taxable income for the year than we currently estimate the deferral rate to be approximately 85%.

Our debt-to-cap ratio at June 30, 2010 was 7% with 130 million of long-term debt outstanding that we have a $400 million credit facility of which we've elected to have current commitment amount available of $325 million and our current borrowing base is 500 million as determined by our lenders. Our working capital at the end of the second quarter was $47 million. We would now like to turn the call for questions.

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from the line of Jim Rollyson from Raymond James. Your line is open.

Jim Rollyson - Raymond James

Good morning guys.

Larry Pinkston

Good morning.

Jim Rollyson - Raymond James

Larry, you talked about the program for refurbishment to upgrade the rigs and the possibility that you have some new builds, can you talk a minute about the kind of customer interest there and just generally what you guys are seeing for rates on the new stuff give that you've got term contracts kind of rolling off over the next several quarters? How do you dayrates today, your margins today compared to some of those older contracts as well?

Larry Pinkston

Well, dayrates have continued to increase really since the early part of the year. We're not seeing any change in that momentum recently. The margins aren't quite to where we would want them to build a new bills but the dayrates are definitely higher, 30 days ago from 60 days ago from 90 days ago and the interest is getting rigs, they're capable of drilling in some these horizontal plays and operators are somewhat impatient on getting under there.

Jim Rollyson - Raymond James

So that we'll continue to see to see the sequentially margin improvements overall?

Larry Pinkston

Yeah, I think the third quarter dayrates are definitely going to be up excluding the impact of labor increase but I don't know -- to the magnitude they were up between the first quarter and second quarter. I'm not expecting you to be that kind of magnitude until we have some pretty cheap contracts that rolled off in this -- and earn some -- pretty cheap contracts that rolled off in the second quarter and matched up with some higher prices. And so, I don't know that magnitude, Jim, but let me get some in the third quarter versus second.

Jim Rollyson - Raymond James

That's very helpful and switching gears in the E&P side, you've obviously talked about the completion delays and the pipeline constraints as you look out second half and really into next year. Number one, any thoughts on visibility of where you're drilling and then how the pipeline capacity situation works. And number two, it sounds like completion delays, everyone knows the pressure from you guys got a lot of capacity now on order and that's start to come in the market, hopefully that starts to clear some of this sub. Just curious what you guys think with some of the well result you've had, how this all parleys into growth heading into next year would seem like if this all catches up that you've got some pretty nice growth rates on the production side for 2010, or do you that think this is kind of continued delays duration for a while?

Larry Pinkston

Our biggest problem is that, Jim, we came off of a very low year drilling oil last year and we're increasing our drilling program very significant early in the year and at the time, we were doing it well the frac companies, of course, had a whole lot lesser business -- I mean a lot lesser equipment in plays and they were pretty well contracted out. And for the companies that hasn't established drilling program and just to keep that drilling program going and fracs done, it really wasn't the problem, it was the ones that we are trying to go from doing one or two fracs a month to five or six fracs a month and giving that color the increase billed into to the service company schedule.

Once we're there with the level of fracs that we need, the problem will be alleviated a lot, I mean, a lot. The problem has been as I said increasing from two or three fracs a month, and try to increase to six to eight fracs a months and giving that work into the service company's schedules, I mean it's been a real problem. I mean real, real frustration force.

Jim Rollyson - Raymond James

They'll think you're alone on that one. Last question for me just on the NGL side pricing down quite a bit sequentially not a dramatic change in natural oil prices just kind of curious what you're seeing on pricing there and then how you think that goes forth?

Larry Pinkston

But what we're seeing most of the decrease so far has been in the ethane prices. The heavies have still which trade more along line of credit is still held up very significantly. As long as credit stays where it is I wouldn't expect that a big increase and the overall liquids price, ethane going, go down so much further before everybody quits processing ethane and starts rejecting it. So, yeah, I would look for a significant decrease in the liquids process where we are at now.

Jim Rollyson - Raymond James

Okay, thanks guys.

Larry Pinkston

Jim thanks.

Operator

(Operators Instruction). And your next question comes from the line of Robert Christensen from Buckingham Research. Your line is open.

Robert Christensen - Buckingham Research

Thank you. A couple questions. The Mile-High Prospect, has there been any other operator that's drilled within proximity to you that has had some production results?

Brad Guidry

Yeah, Bob, this is Brad. There's some vertical well drilled out there by Running Foxes. And Newfield has drilled one horizontal well out there and the best we have that was not successful but it was in a different zone and what we drilled in. We think the Atoka is the main zone our there and that's what we drilled lateral we have.

Robert Christensen - Buckingham Research

Did you have any kind of oil shows?

Brad Guidry

Yeah, we had some; we had some Mud Lock shows.

Robert Christensen - Buckingham Research

And it has to be fracture stimulated?

Brad Guidry

Yes, it does.

Robert Christensen - Buckingham Research

What's the timing of that?

Brad Guidry

Mid September.

Robert Christensen - Buckingham Research

Okay.

Brad Guidry

Yeah, we literally just got the well drilled here last week.

Robert Christensen - Buckingham Research

And how many zones or stages in that kind of --

Brad Guidry

No, we have not completely design that yet but I suspect that it will be somewhere six to 10 stages. But we have not highlight our frac design yet.

Robert Christensen - Buckingham Research

Can I shift over to; I guess land drilling, of sort of a broad industry question? Have you seen any producer shift towards the onshore in light of the moratorium offshore fiasco that's taken place? People have said they might shift a little more budget into the onshore, are you experiencing that or is it too early to say so in your land drilling segment? What's your field?

Larry Pinkston

The reasons for the continued increase in demand -- I don't know that we know whether it's the result of shifting but it's -- or what the reason driving it is. A lot of companies that are still asking for rigs or companies that were involved in offshore, demand is still increasing. The reason behind that, Rob, I don't know that we know --

Robert Christensen - Buckingham Research

I think I could think of 12 reasons why. One reason being the moratorium fiasco. I just wondered if you've seen any kind of direct evidence from your customer base that some dollars are being moved into the onshore.

Larry Pinkston

Nobody has told us that they've got $100 million more to spend onshore this year because of the moratorium.

Robert Christensen - Buckingham Research

Okay. The House and Senate energy bills, what's your intelligence on intangible drilling costs and the tax treatment? Have you seen any consultant view on that or rumblings out of Washington as to one way or the other in the two bills?

Larry Pinkston

It's somewhat of a contradictory in term of intelligence of the Washington.

Robert Christensen - Buckingham Research

I couldn't agree more, but what's the lay of the land, because that's a fairly important item to you in a couple respects?

Larry Pinkston

Our primary Senator that -- really those Senators have continued to say that nothing is going to happen this year. That could change tomorrow but there's been a lot -- convince that it will be next before it's seriously consider after the elections and but it's been probably 30 days since we've had any conversations with to answer this.

Robert Christensen - Buckingham Research

Okay. One more, if I might, just, Brad, steer to us where we should be most interested, if you will, in well results. If you could prioritize, because your description of so many good wells tends to diffuse, I think, where the successes are. But where should we focus as investors in, let's say, when the third and fourth quarter comes around? Where can the meaningful future production volumes and lower costs come from? Which areas should we look at?

Brad Guidry

Bob, I think the main growth you will see from us -- two drivers; it will be the Granite Wash and the Marmaton. If you look at the Granite Wash, we've essentially completed two horizontal wells in the first half of this year and part of that was, since the last year we really converted most of our drilling program from primarily a vertical drilling program to horizontal. So the time to get that converted and then coupled with frac delays has taken longer than we anticipated.

Now we have three rigs running in the Granite Wash drilling oil horizontal wells. We've talked about before in the Granite Wash, we've now test four different intervals in the Granite Wash. Three of those four look like they're going to be very good producers. The remainder of this year the three rigs running drilling horizontal, we're adding fourth in September. So with four rigs running we all be looking at completing a couple of wells per month and as we give the fracs secured in front of this which we're doing, if we can look bringing on two to three new well horizontal Granite Wash wells well per month, I think you'll see growth coming from there and our plan is to do that the rest of this and certainly into '11.

The Beaver County, we're drilling our well there. The wells there only take about 20 days to drill. We drilled on, we can complete them open hole for a short period but then we have to frac the wells and right now, I mean, we have seven wells that are awaiting on fracs that to October. So fourth quarter I think you'll see especially from a oil standpoint as we get our Marmaton wells frac and get that schedule operating with the second rig with two rigs running out there we can drill two to three wells per months. So, and those are both programs that we think we can maintain for several years from our inventory.

Certainly upside for us, Bob, is, we're drilling a lot of horizontal wells and other formations in the Mid-Continent and we don't have necessarily one formation in the Mid-Continent that we have a huge record position but if you have 5 to 10,000 net acreage out there and you combine those different plays, I think that will certainly add a low risk element of production growth for us. The upside exploratory type test that we talked about in Colorado could certainly add something that was the work, that was the acreage we're able to put together very low cost and we'll just have to see what happens with frac.

Robert Christensen - Buckingham Research

Turning it over. Thank you, gentlemen.

Larry Pinkston

Thanks, Bob.

Operator

Your next question comes from the line of Brad Evans from Heartland Advisors. Your line is open.

Brad Evans - Heartland Advisors

Good morning, everybody.

Larry Pinkston

Good morning.

Brad Evans - Heartland Advisors

Just, I have a number of questions. First on the drilling side, I think you've indicated that you would expect to end the year with 90 rigs that were capable of drilling horizontally. Is that correct?

Larry Pinkston

No, we have 90 and -- we have 90 in our fleet right now that we've identified as being good horizontal candidates. It would probably be in the -- about saving all those done by the end of the year, Brad.

Brad Evans - Heartland Advisors

Okay.

Larry Pinkston

Brad, that can end and flow as demand requires. If we're seeing more demand for wells, I mean for the rigs, we'll work faster. So, it can ebb and flow as we go forward.

Brad Evans - Heartland Advisors

Larry, could you just talk, you mentioned 67 to 68 rigs for the third quarter. Could you just speak to just recent tenor of customer inquiries for additional rigs and maybe just talk about your ability to respond and how -- what type of lead times we're looking at today for additional rig deployments if they were to materialize?

Larry Pinkston

Well, Rob, they will wonder, the biggest delays that we have is in getting new top drives and that's going to be anywhere depending on the size of the top drive. It can be anywhere from six weeks to four months. So that by itself is the biggest delay. There are still some capabilities of operators that have rental agreements to where they can rent top drives and put on the rigs until you can get one, until we can get one on the rig. But those are getting pretty limited. But some operations, they are willing to start the operations off without a top drive to give us a top drive but that's probably the single biggest limiting factor on how fast rigs can come out, is the delay on top drives.

Brad Evans - Heartland Advisors

Okay. And just in terms of leading edge dayrates for, say 1,000 to 1,500 horsepower rig, what are you looking at today?

Larry Pinkston

Estimates of that, Brad, it's depending on where it is and what all the rig equipment has on it. If we got 1,500 horsepower rigs ranging all away from 20,000 plus down to $16,000 range, it's just depending on how they're equip and again kind of where they are. In the Rockies, the leading is -- you're looking them $20,000 or higher number. South Texas is going to be in that, 16 to 17 or 18,000, $19,000 range. But again is less than anything is how their rigs are equip what it is on it.

Brad Evans - Heartland Advisors

What's your expectation that -- as you indicated before, dayrates should continue to move higher?

Larry Pinkston

I think they'll definitely be going to be higher in the third quarter and that's just from we already have in hand today. In the fourth quarter, right now, I see no reason why they won't. But that's more than two days from now. So I have my crystal ball, there's trouble out there and that is -- demand and demand is still strong and it's mostly again it's the oil, land or liquids that's driving most of the demand and of course, the Eagleford demand is quite brisk right now.

Brad Evans - Heartland Advisors

Just on the upstream side, based on your guidance, you're looking for a fairly sharp ramp in production into the second half of the year. Could you just give a sense of two things? What was -- what is your current production and where would you expect to -- what would your exit rate production before, say, December 2010 roughly?

Larry Pinkston

Well, if you just go through the map and where our guidance is and where we are to the first six months and then you'll see very significant ramp up. So, so far this year we got them very good about being able to -- the timing of when that production is coming on. So if our drilling schedule stays on schedule and with where our -- the wells are and the anticipation of the wells, we should be estimated 200,000 they range sometime over the next six or seven months but again whether that happens, the problem with the current year is whether that happens in September or whether it happens in late October. We'll get there it's just the timing of the deal that's been our biggest problem so far.

Brad Evans - Heartland Advisors

So, just to confirm what you said. The timing is uncertain, but you've got the inventory of wells drilled and, obviously, the program into the back half of the year that will get you over 200 million a day equivalent?

Larry Pinkston

We're seeing nothing in the results of our drilling program thus far that has disappointed us on where production can get to. It's just then the problem of getting the well completed in on line. So we're not disappointed in the wells we drilled. It's just been getting and hooked up and on sales as that's been very, very frustrating.

Brad Evans - Heartland Advisors

Just last question just on the rig side. Larry, does anything structurally impede from you getting back to rig -- EBITDA per rig day levels that we saw back in '08 timeframe? I mean, 7to 8,000 a day, is that something you think is achievable this cycle for you?

Larry Pinkston

I think definitely, Brad, on certain rigs. As to whether we'll get back to the ebb rigs for the 123 rigs in our fleet not to the EBITDA we were at two years and threes years ago. I mean it's kind of a different rig markets today. The real shallow rigs -- they're still very challenging. We're not -- we would not expect the 600 horsepower rigs to get back to the 8 to $10,000 the margin are like. Some of them we saw two to three years ago when everybody was drilling vertical Granite Wash wells.

That's -- for the 1,800 horsepower rigs to 2,000 horsepower rigs, they were already there on some of the rigs so --

Brad Evans - Heartland Advisors

Okay. Thanks very much.

Larry Pinkston

Okay, thanks Brad.

Operator

Your last question comes from the line of Robert Christensen from Buckingham Research. Your line is open.

Robert Christensen - Buckingham Research

Yes, a little more on the outlook for rigs, if I might question. What areas of the country or play types are you seeing the most producer interest inquiries, I guess, for new rigs or not new rigs, but your fleet?

Larry Pinkston

Yeah, I mean it's the Bakken, for sure, the Granite Wash you know for sure, the Eagleford for sure, the Haynesville I think is broad as aggressively seeing rigs as they were a year ago 18 months but those three plays are most definitely, the Permian industry are still looking a lot of rigs and just real shallow rigs and the bigger rigs, that's the market where we are not and yet, but and always -- some market we keep looking at.

Robert Christensen - Buckingham Research

What's happening in the Permian?

Larry Pinkston

It's just you know the different -- all the different -- it has liquid plays that are going on there, mostly oil driven but they have some very rich gas and they're also --

Robert Christensen - Buckingham Research

And of your rig fleet, I guess, how many are being used by your exploration affiliate right now?

Brad Guidry

We're right about eight to 10 rigs.

Robert Christensen - Buckingham Research

And are all the Granite Wash wells you're drilling unit rigs?

Brad Guidry

Yes, they are. The breakdown is we have four in the Granite Wash, two to three in the Marmaton, we have two down in Segno and then just -- the other ones are various Mid-Continent, rigs that we're running.

Robert Christensen - Buckingham Research

I guess we should conceivably think of that quite positively? That you're paying yourself in these plays a little bit?

Larry Pinkston

Of course. So it's is better to play yourself than somebody else. It gives us more control over the wells for sure; you don't have to get constrained by contractual obligations, et cetera, et cetera. But, it gives us more control and our drilling department, they walked over the wells along with our E&P and it definitely -- it's definitely plus.

Robert Christensen - Buckingham Research

Would you enter into any kind of multi-year contract for pressure pumping services in either the Granite Wash or the Marmaton? Some companies have entered into two-year deals. It's -- it seems to be on the table with pressure pumping companies that want to have more efficiency and knowledge of planning and to make margin with efficiency as opposed to pricing it up. Is something there for a producer like yourself?

Larry Pinkston

Yeah. In certain areas, Bob, I think that is very, very feasible. We want to be in the plays we're drilling or to be in drilling so many Marmaton wells and to enter into an arrangement out there with a frac company, I think, could make a lot of sense as to whether we can do it across the Board for a different plays. That's really not feasible because different companies have their strengths in different areas. It's -- one company use the Granite Wash, might not even be in Southeastern Oklahoma.

Robert Christensen - Buckingham Research

Yeah, I understand. But, I just think that if you got the guy who's strong in Granite Wash and the fellow who was strong in the Marmaton, those might be your areas. Is that conceivable that we can see something like that from you guys?

Larry Pinkston

Yeah, I mean that's something that we would definitely look at. We're doing to some extent, we're doing that they're just not under be in a long-term contract. I mean we use the same frac company for all the Granite Wash wells and we are -- plans thus far been to use the same frac company for the Marmaton wells. But if there's something that benefits us, and it very well could be with the limited equipment and to enter into the longer term contracts in those plays where we can see a long-term drilling program. Most definitely it's something we look at.

Robert Christensen - Buckingham Research

And, I guess, one final question, gathering, processing, marketing. Is there one or two very large potential projects in your horizon? Marcellus Shale, if you will. Is there something that really could move the needle on that business? Should we see a press release at some point in time? Is there something to noodle on there for us?

Larry Pinkston

The potential is that we're involved. In the Marcellus, because and primarily because the projects there when you're laying on the project, it's not a five or seven or $10 million project, it's a 50 or to $100 million project. So, yes it can move the needle and most definitely in our Mid-Stream operations and that are is going to need a tremendous amount of infrastructure and the panic is somewhat hitting the producers right now.

Robert Christensen - Buckingham Research

But, why should they choose Unit Corporation's gathering, processing, and marketing and not a big MLP? I mean, what do you bring to get a award of such a sort of large scale project?

Larry Pinkston

Yeah, our advantage right now is that we've been there for about three years and in several of the project we're well ahead of where somebody would be as they started right now and the environmental aspects is very significant up there. You have to do the test for the bats and those squirrels and the rabbits and they're only certain period of the year that you can do that in. And if you just missed that period, you can't even do that test for another year.

So, the producers are at the point now to where they're getting very aggressive there and they can't afford to wait another year before you even start a project. So we got that going forward in certain areas that has not all the cross in Marcellus that in certain areas, we're a couple of years ahead of where somebody would be if I walk in today and say hey we want to do this for you.

Robert Christensen - Buckingham Research

What's sort of the ground floor environmental work for a gathering project you've done?

Larry Pinkston

Environmental and permitting processes, yes.

Robert Christensen - Buckingham Research

Got it. Okay. Thank you.

Larry Pinkston

You bet. Thanks Bob.

Operator

And your question comes from the line of Brad Evans from Heartland Advisors. Your line is open.

Brad Evans - Heartland Advisors

Just a follow-up, if I could. David, I didn't catch capital spending for the quarter and for the full year. What's your expectations at this point?

David Merrill

Yeah, excluding the acquisitions, our spending for the first half of the year was 2015 million for the quarter. For the quarter it's about 120 million and for the year, where we have a change our overall capital budget for the operating spend which in total of 494 million excluding acquisitions.

Brad Evans - Heartland Advisors

Okay. And if I -- just, it looks like if I run strip pricing into the back half of this year, it looks like you could -- it looks like the first half of the year you did about $200 million EBITDA. It looks like you have the opportunity to grow EBITDA in the second half by over 50 million to maybe $60 million. Does that sound about right?

Larry Pinkston

Yeah.

David Merrill

It's reasonable.

Brad Evans - Heartland Advisors

Okay. Great. Well, it looks like things have turned a corner. Congratulations, and good luck in the second half.

David Merrill

Thanks Brad.

Larry Pinkston

Thank you, Brad.

Operator

There are no further questions at this time.

Larry Pinkston

Well, thank you everybody for joining us. We will be in Denver for the EnerCom conference on August 23 and 24. We're hosting a dinner on the evening at the 23 and anybody would like to join us, please we would like see you and we present at the conference at 9:15 on Tuesday, the 24th. So, we hope to see many of you there. If not it will be at about, quite a bit over the next 30 days and I hope to you sometime there. Thank you again for joining us.

Operator

This concludes today's conference call. You may now disconnect.

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Source: Unit Corporation Q2 2010 Earnings Call Transcript
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