Good morning, my name Chris and I will be your conference operator today. At this time I would like to welcome everyone to Unit Corporation’s first quarter 2010 earnings conference call. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks there will be a question-and-answer session. (Operator Instructions)
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 the 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 the current decline in wells being drilled will have on production and drilling rig utilization, productive capabilities of company's wells, future demand for oil and natural gas, future drilling rig utilization and day rates, 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, anticipated oil and natural gas prices, the number of wells to be drilled by the company's oil and natural gas 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 Larry Pinkston, CEO of Unit Corporation, please go ahead, sir.
Thank you, Chris. Good morning, everyone. We want to thank you for calling in and welcome to Unit Corporation's first quarter conference call. With me today are David Merrill, Unit’s CFO; Brad Guidry, Executive Vice President of Exploration Segment; John Cromling, Executive Vice President of our Contract Drilling Operations and Bob Parks, President of our Mid-Stream Segment.
I will spend a few minutes recapping Unit Corporations first quarter results including an update on a contract drilling in our Mid-Stream Operations, Brad will discuss of details of our E&P operations and David will discuss the key financials facts. We will take questions, then after our comments. We released our first quarter results to the public this morning. We reported net income of $36.2 million and earnings per share of $0.76 per share this compares to daily income of $28.5 million and earnings per share of $0.60 per share in the fourth quarter of 2009.
The increased was due to higher margins in our oil and gas segment and increase in other revenues and an increase in the utilization of our drilling rigs. In our contract drilling segment we achieved a 15% improvement in operating profit before depreciation as compared to the fourth quarter of 2009. The increase was due to 39% increase in the average member of rigs may utilized.
Demand for drilling rigs began increasing during late 2009 and continued through the first quarter. The majority of the higher demand is for the horizontal drilling which requires rigs in the 750 to (Inaudible) range. We currently have 79 drilling rigs in this size category.
The majority of the additional rigs operated have been contracted under six month or one year terms, we believe average rig utilization in the second quarter should be in the range of 57 to 58 rigs.
Day rates on rigs working the spot market increased in the $500 to $1000 per day range. However they generally were still below the average day rates of other rigs that were under contract. Average day rates for the fleet increased $581 per day between the fourth quarter and 2009 and the first quarter of 2010. Operating cost before elimination of intercompany drilling rig activity during the first quarter decreased $349 per day as compared to the fourth quarter primarily from spreading out our fixed cost over more operating values in the first quarter.
Operating margins before elimination of inter company drilling rig profit in the first quarter of 2009 were down $833 per day. However $591 of this reduction was due to lower contract termination fees received in the first quarter versus the fourth quarter.
Our refurbishment and upgrade program is progressing, so it's mid December we’ve upgraded 14 rigs and currently have 11 more either in progress or plan for 2010. These upgrades range from having top drives to rigs to changing at med fabs or to complete convergence on mechanical rigs to electric rigs well either on order or has received 20 top drives since December bringing our total fleet to 53. These upgrades will neighbor all rigs to be some of the most competitive in the industry for both vertical and horizontal drilling.
In our midstream segment, financial results remain strong in the first quarter of 2010, even though gross margins were slightly less than the fourth quarter of 2009, which is mainly due to the winter weather operating conditions and some scheduled facility maintenance projects.
Operating profit before depreciation and amortization in the first quarter of 2010 compared to the first quarter of 2009 show the sizable increase for $1.5 million up to $8.4 million.
[Thus] gathered in process volumes were slightly lower than the fourth quarter of 2009 results mostly due to the stakes of the winter operating conditions we experienced in January for 2010 our midstream segment as a capital of budget of $53 million.
We’ve previously announced the construction of $50 million cubic feet per day turboexpander style processing plant in the Texas Panhandle to process Granite Wash production, the construction activity is on target for the early fourth quarter of 2010 start up. The new plans kit is being constructed at one of our existing mid-continent systems due to the growth and volume from the producer, we are evaluating several grass roots plant construction projects in the mid-continent and other geographical regions.
We continue to review various pipeline and gas plant acquisition packages and become the market the company will maintain the conservative evaluation to approach these acquisitions that is well situated both operationally and financially the growth these acquisitions.
Late in the first quarter our memorandum of understanding was executed between [inaudible] Tenaska Midstream and another party for the construction and the gathering pipeline in Preston county West Virginia. This project is proceeding with initial construction activity, while final documents are completed and executed, we continue to evaluate and develop additional Marcellus Shale pipeline gathering projects in both West Virginia and Pennsylvania.
In our exploration and production segments we encountered several delays in the first quarter, mostly due to the unusually weather in the Texas Panhandle and Western Oklahoma regions. Wet conditions cause delays in getting locations built and delays in building rigs between locations, we also have to wait longer than anticipate for top grants to be installed on rigs added.
[inaudible] began to get extended about three to four weeks and that slowdown the completions on some of our wells, we were currently in the process of adding two additional rigs in Western Oklahoma and the Texas Panhandle help with getting it back on schedule, however that might not be enough remaining time in the year to make up for the production shortfall as a result of these delays, therefore we are revising our guidance for 2010 production to 64 to 65 Bcf equivalence.
I would like now to turn the call over to Brad, so he can discuss more details of our exploration programs.
Good morning. This morning I'm going to give you an update of the Granite Wash program as usual, but I'm also going to spend a little time telling you about some of our other mid-comment oil plays horizontal oil plays that we have been participating in that could have an impact on units’ production profiler into 2011 and later.
But first the Granite Wash. During the first quarter in the Granite Wash, we completed three vertical wells and one horizontal well. The water field 7H, our horizontal well was completed in the Granite Wash C1 interval which was a new interval for us to test, and that well had first sales on March 1, at a rate of approximately 1.8 million cubic feet equivalent a day and we have reserve estimates between 1.5 and 2 Bcf, while these results from this interval did not support further drilling at current gas prices we may be able to improve the economics by optimizing our drilling and completion techniques.
Previously completed horizontal Granite Wash wells include the Frank Shaller 7H which was drilled horizontally in the Granite Wash A zone and that well has estimated recovery up to 6 to 8 Bcf and still currently making about 5.8 million cubic feet of equivalent per day. The Isaac C4H was a horizontal Granite Wash C zone well that was drilled late 2008, the well is still currently producing about 1.6 million a day and it has ultimate recovery of 5 to 6 Bcf.
We're currently drilling one horizontal well in the A zone, we have another horizontal well that will be fracked or is in the process of being fracked this week and it’s in the B zone which will be a new zone for us to test.
We will increase from one rig that we had running during the first quarter to three unit rigs in mid-May and all three of those rigs will be drilling primarily horizontal Granite Wash wells.
We’ve identified about seven potential Granite Wash pay intervals and to date we have drilled horizontal laterals in four different intervals to evaluate which sands will generate favorable economics. Their early results indicate that three of the four sands are favorable for horizontal drilling and we have plans to test the fifth interval sand later this year.
Based on these results, we’ve identified approximately 200 gross and 110 net Granite Wash locations in the Texas Panhandle and that's based on 160 acre spacing.
About 65% of the locations are targeted for the three Granite Wash intervals that we’ve successfully tested horizontally and the remaining 35% of the locations in Granite Wash zones that we’ve planned to test over the next 18 months.
In addition, we’ve identified approximately 180 gross and 18 net potential horizontal locations in the Western Oklahoma portion of the play. This concludes the Granite Wash update. Now I'll give you a brief summary of some of the new horizontal oil plays we’ve been working to develop over the last several months.
In May of this year, we will spud our first horizontal Atoka test in our Mile-High prospect which is located in the Southeast Colorado, there is not only perspective for the Atoka, but also the Cherokee interval. We have accumulated about 50,000 net acres with primarily five year terms in this play, while the play is definitely risky, a successful outcome could have a positive impact on the company.
We have three horizontal oil intervals, Tonkawa, the Cleveland and the Cottage Grove that we will be targeting in Roger Mills, do in Custer Counties in Western Oklahoma.
Over the last 18 months, other operators have proven these intervals are economic to drill horizontally. We have a non-op position in five of these wells, two of which have been completed with favorable economics and three others that are been completed now.
We spudded our first horizontal Tonkawa well in Oklahoma Panhandle in March. We own about 15,000 net acres in these three various oil plays. We spudded our first horizontal Marmaton oil test, which is located in Oklahoma Panhandle in March and should have first oil production by the end of May.
Approximately 10 horizontal wells have been drilled by other operators within this play and their results have been positive.
Unit currently owns about 8,000 net acres in the play and we continue to add to this position. We’ve also recently drilled our first horizontal oil test located in the Texas Panhandle. The well was drilled with a 2800 foot lateral and will be fracked with eight stages in June of this year.
In addition to the Morrow there is also perspective for the Chester and the Granite Wash zones, we’ve accumulated about 6000 net acres in this play. We believe all of these plays that I mentioned we have stronger economics because of the high oil or liquids components.
Moving to our Segno prospect located in the Texas Gulf Coast, we have completed two wells drilling or completing three additional wells. The two completed wells are the fourth and fifth well that we drilled on the prolific Wing lease where we own a 100% working interest. The Wing number 4 was East extension of the filed that encountered three potential gas zones.
The initial completion in the deepest Wilcox zone resulted in a marginal gas test and we elected to move up to the second Wilcox zone which is scheduled to be fracked in mid-May.
The Wing number 5 was drilled in a new fault block to the South and encountered seven potential gas zones. The initial completion was from a new lower Wilcox sand that’s averaged approximately 1500 Mcf a day and 33 barrels of oil a day since first production in early April.
In our new joint venture area to be South of Segno, we drilled two of the three commitment wells required under the agreement. Both wells encountered several potential pay zones and we are in the completion process, but it's soon to determine that these well wills be economic at current gas prices.
The third well on the JV has spud and we anticipate keeping two unit rigs working throughout this overall Segno prospects for the majority of 2010.
In the Haynesville shale we have two areas of activity both in East Texas. First in Harrison County, we have a 100% working interest in (inaudible) 18 which we drilled in later part of 2009 after successfully fracture stimulate in the first three stages we had a down whole mechanical problem and when were unable to pump the final four stages of that time.
The earliest frac date for the final four stages was in July of this year, so we elected to flow the well to sales and its been flowing to sales at approximately rate of 14,00 mcf during the initial 47 days of production. To the South and Shelby County we are currently participating with 54% working interest and Chesapeake Smith number 1-H, which is first horizontal shale well in stockmen prospect
The well is currently at intermediate pipe point should be began drilling the projected 53,00 foot Haynesville lateral in the next couple of weeks. This area Shelby County has seen a recent increase in drilling activity filled by the strong reported initial, potential gas rate above to 11 million cubic feet equivalent to gas per day from other offset operators.
We anticipate participate in 3 to 4 horizontal Haynesville wells in Shelby County during the remainder of 2010. In the Marcellus Shale play located primarily in Somerset country Pennsylvania. We have previously participated in two horizontal wells that have both been completed in selling gas into the pipeline. The initial well was drilled with 35,00 foot lateral was frac expect with seven stages and the wells has been flowing approximately $0.5 million 500 mcf equivalent per day for the past five months with very little decline.
The second horizontal drilled the 26,00 foot lateral that was fact with eight stages and has been following approximately 1500 mcf equivalent per day since early April. Although these initial rates are lower than we anticipated the early production rates are showing minimal decline, which is providing the momentum to further evaluate the 190,000 gross acre lease block. The current plan is to drill five additional horizontal wells starting in September of this year it also should approximately 35 square miles of 3D seismic data.
That concludes E&P portion. I’ll turn the call back over to David.
EBITDA for the first quarter of 2010 was $102 million, an increase of 17% from 87 million in the fourth quarter of 2009 and an increase of 2% from 99 million in the first quarter of 2009.
For the first quarter of 2010, the oil and natural gas segment contributed 72% of EBITDA, contract drilling contributed 20%, and midstream 8%.
EBITDA for the first quarter increased from the fourth quarter in the oil and natural gas in contract drilling segments and decreased slightly in the mid stream segment. For the oil and natural gas segment, the increase was primarily attributable to higher realized commodity prices, realized prices including hedges for natural gas liquids, oil and natural gas, increased 64%, 9% and 3%, respectively.
The increase attributable to higher commodity prizes were somewhat offset by a 1% decrease in equivalent production. For the contract drilling segment, the increase was primarily attributable to a 39% increase and the number of drilling rigs operating from an average drilling rate utilization of 28% in the fourth quarter to 40% in the first quarter somewhat offset by a 16% decrease in operating margins per rig per day before elimination of inter-company rig profit.
Excluding rig termination fees, operating margins per rig per day before elimination of inter-company rig profit decreased 5%. Financial operating cost per day for the first quarter decreased $112 or 1% from the fourth quarter. For the midstream segment the decrease was primarily attributable to a 2% decrease in blended frac spread margin and a 4% to 1% decrease in per day liquid sold and gas profit volumes respectively.
For the oil and natural gas segment, we have hedged approximately 66% of our anticipated 2010 natural gas production at a weighted average delivery point price of $6.29 and approximately 62% of our anticipated 2010 oil production at a weighted average price $69.42
Approximately 15% of our natural gas liquids productions hedged for the balance of 2010 through 2011. In addition we’ve hedged approximately 12% of our 2011 and 2012 natural gas production based on anticipated 2010 volumes.
More detail on our hedges is disclosed in our form 10-Q being filed with the SEC today. Capital expenditures from our operating segments for the first quarter of 2010 of $105 million and by segment was $58 million for the oil and natural gas segments, $40 million for the contract drilling segment and $7 million midstream segment.
For 2010 our capital expenditure budget for all three operating segments combined is $494 million. Budgeted capital expenditures by segment for 2010 are $365 million for the oil and natural gas segment, 76 million for the contract drilling segment and $53 million for the midstream segment.
The 2010 capital expenditure budget is anticipated to be funded namely from internally generated cash flow into the lesser expense from borrowings under our credit facility. The effective income tax rate for the 2010 first quarter was 38.3% and should approximate the rate for the year and we currently estimate the deferral rate for the year to be around 85% to 90%.
Our debt-to-capitalization ratio at the end of the first quarter was 2% with $30 million of long-term debt outstanding. As of April 1, 2010, the lenders under our credit facility completed their re-determination of our borrowing base, determining borrowing base to be $500 million, well in excess of our current elected commitment amount of $325 million and also in excess of the maximum facility amount of $400 million. Our working capital at the end of the first quarter were $56 million.
Chris, I would now like to open the call for questions.
(Operator Instructions) Your first question comes from Marshall Adkins from Raymond James.
Marshall Adkins - Raymond James
Let’s start on the E&P side. It seemed like on most of the E&P areas where you have a major presence that the wells were somewhat disappointing. Was it can you walk through kind of I mean, I know you gave some specifics, but do you expect that to change going forward, I guess, number one? And number two, was it, like the Granite Wash, for example, was it just you drilled the bad zone and the other zones you’re comfortable with, given what other operators in the area are doing, because it seems like in the Marcellus and the Granite Wash, even the Haynesville, that other people in that same area seem to be have bigger wells with higher production. Or am I missing something?
Marshall, this is Brad. In the Granite Wash, as I mentioned we have a program. We are trying to test the different Granite Wash intervals, and well we happen to complete in the first quarter was in the Granite Wash C1 interval, which is the first well we are drilled in that interval the two prior wells that we have which we are very pleased with were in the A interval and then the C interval.
So, we didn’t except every interval we drilled out there to be economic although low we haven’t written that one but definitely the rate was less it was harder to drill, those are things were trying to find out.
It hasn’t soured us on the Granite Wash at all. We expect to have three rigs running out there. The zones were primarily we are going to drill for this year will be A, B and the C zones, which are the once we proven and have the best success. So, that’s the story for the Granite Wash and.
Marshall Adkins - Raymond James
So, don’t read too much into that one well just because it was it was at different zones.
It’s the only horizontal well, Granite Wash well we completed during the quarter and we wanted to report that but definitely it’s not indicative of how what we think will go forward in the Granite Wash. And once we have the three rigs running out there in mid-May. We should start seeing the production growth coming off of that as we get those wells completed. The Marcellus, no doubt we are disappointed in the initial rate but keeping in perspective we have a 190,000 gross acres and we’ve drilled two horizontal wells, both fairly short laterals and we are still in the early part of now the encouraging thing that we are definitely excited about and excited enough to commit to five additional wells out there is that even the first well, it’s been on five months now approached to six months the rate is still at 500 Mcf a day and although it’s not a great rate. It’s essentially when it came on it was at 500 Mcf per day. So there is obviously something for us to learn there and figure out which at this point, we don’t have a clear estimation of why the initial rate went better.
The second well it improved three fold coming in at 600 Mcf per day again, these are wells we drilled without the benefit of having 3D seismic out there. The wells we drilled without the benefit of having a lot of vertical information about where do land collaterals. So I am although we can't sit here and give you high rates at this time, I am not discouraged with the Marcellus I would like to certainly see higher IP rates, but I think as we are starting into that lease block I think we’ll see better results as we have seen in a lot of the shale plays as we get going. And the other thing to note in the Marcellus there you where in, there hasn’t been a lot of drilling so the step up curve here may take a little bit of time.
Marshall Adkins - Raymond James
Well, it sounds like you are just real early in the learning curve in the Marcellus?
Absolutely, in the Haynesville our well have been Harrison County from three stages the well came on I think its about $1.8 million, we averaged stock 1.4 over the initial period month-or-month and a half and we still have four stages to frac there, so again its still a little bit early as we are not sure about Harrison County yet this is our initial well we drilled out there. There is some offset production that appears to be encouraging, but again I mean its our first well that we drilled that we operated in the play so its just still too early to tell. To the Sauk and the Shelby County our acreage plot down there seems to be in the middle of a lot of activity with it map yesterday and there is 10 offset permits wells that are drilling or completed wells that are pretty much adjacent. Test these operators the block, they are drilling the first well right now, they should start drilling the lateral and the next week or two here. So certainly nothing negative there we are excided to see the lateral get conclude and to see to well get conclude and then we’ll have some results to talk about there.
Marshall Adkins - Raymond James
Obviously, they've got a lot of experience there, so you think they'd have as much insight as anyone?
We think they can get a frac day.
Marshall Adkins - Raymond James
Okay. Last question on E&P, you mentioned oil plays. A couple of questions there. You said the economics are good. Could you give me more specifics there and do you anticipate shifting spending away from some of these other areas into the Colorado, the Mills County and the Morrow areas?
Lot of these plays were in our initial well of drilling it, there is no doubt as we drilled these wells, the wells that have the best economics we may certainly divert more of our capital towards those plays.
In general the mid-continent oil plays we’re looking at we’re looking at maybe three to 4000 foot laterals well cost will be in the 3 or 3.5 million or maybe 2.5 million to 3.5 million typically looking between 150 to 250,000 barrels oil with some associated gas.
Colorado is kind of wildcat area for us certainly if we have success out there you could see us spending more money as we go out in that area as far as taking money away from other stuff, the only thing we've really slowed or postponed here for a little bit is the plays that appear dry gas so you don't see a lot of activity that we have in the Oklahoma base and although we have prospects there and we'll drill little bit, but we have definitely delayed some of that in favor of higher BTU or oil type prospects.
Marshall Adkins - Raymond James & Associates
That's a lot more clarity. I appreciate it. I'll turn it over to someone else and re-queue. Thanks.
(Operator Instructions) And your next question comes from Richard Tullis from Capital One.
Richard Tullis - Capital One
I joined a little bit late. I apologize if you've gone through any of this already. Looking at the Marcellus wells, where were those exactly located and what were the costs?
The Marcellus wells that are located in Somerset County, Pennsylvania which is in the South part of the play the two wells we drilled they are only wells we drilled were both about 5 to 5.5 million both of the wells had vertical core holes associated with them in be in the first two wells on a very large acreage [cloak] they would designed do a little bit of science and then also to come back and produce some of the new five wells that we are going to drill we have not seen the AFE that project is operated by large project company (inaudible) we had 25% interest and 90,000 acre block so I expect the cost to be somewhat below the 5 - 5.5 million, but I'm not sure what that cost would be.
Richard Tullis - Capital One Southcoast
Where will those be located, what ---
The block that we have is primarily in Somerset County.
Richard Tullis - Capital One Southcoast
Okay. So those will be Somerset as well. Looking at, I guess, the well flow data over the next few months, what are you expecting from some of these higher profile plays like Haynesville, Marcellus, Granite wash? What can we expect as far as well flow data, number of wells over the next, say, three months?
The Granite wash over the next three months we’re moving to three rigs in mid-May, so we are about a week or two weeks away from getting that drilled and you are talking 30 - 45 days and about time you get them on lines so I think the effects of the Granite Wash you’ll really start seeing more effects towards mid summer of the increase program from that the Haynesville well drilling in Shelby County offset wells there really the closest wells to the IPs that they are between 7 and 11 million that well ought to be down I would say in the next month or so and I don't know what the frac based situation is there we have a lot of wells that are waiting on frac dates right now, the Marcellus wells won’t be drilled to September so really want see a production increase from those wells I think that the greatest production increase although, we don’t have the offset wells yet we will be in the various oil plays that we’re drilling in Western Oklahoma as we bring those wells on line. That’s I would say we have seven rigs running between the Granite Wash and Western Oklahoma and then we have two rigs running down in the Gulf Coast and that’s a probably from four to five rigs and what we had in the first quarter.
Richard this is Larry. On our revised production forecast I mean basically what we, first quarter production was right on line with where our projections were for the first quarter a bit may be we had expected a pretty sizeable ramp up in the second quarter in our internal projections and because of these delays that Brad has been talking about waiting on the fracs, waiting additional weak or two here and there on some top drives.
The second quarter ramp up really has just kind of been its been moved to the third quarter so most of production increases are going to be back half of the year waited second quarter production will be up yet a little bit but not anywhere close to our initial ramp up was in the projections. So and we kind of at a quarter behind where we thought we would at three months ago.
Richard Tullis - Capital One Southcoast
What kind of growth do you think you might see in 3Q? What sort of range?
Obviously, what we’re thinking is we’re going to be somewhere probably in the 10% to 12% type range at quarter. The plans that we have in now are able to be carried out.
Richard Tullis - Capital One Southcoast
And then, just lastly, could you give just a broader review of the costs of these recent wells, like the Granite Wash and I guess the Haynesville well that I know has given you some problems, so it's not done, but what your expectation is there?
Well, Haynesville well, the well that we’re participating in with just a day, it’s about 8 million. The well we drill in Harrison County was 6.7 million. Our Granite Wash wells have ranged a little bit from a low of about 3.8 million on our Shallow well, and that’s when frac cost were quite a bit below where they are now. Current E&P on our Granite Wash well is about 4.7 million.
Your next question comes from Jim Rawlinson from Raymond James. Your line is open.
Jim Rawlinson - Raymond James
Just circling back to the drilling side, since we've spent so much time on the E&P, Larry, you guys talked about kind of where rates were for the quarter and it sounds like you've had a pretty big pickup and interest on signing contracts. I think you mentioned 62 rigs are contracted and 32 are a little bit longer term. Can you talk about maybe where the pricing is today for some of these contracts versus where the fleet average is or even where some of the older term contracts are rolling off? Just kind of give us some flavor for that?
Within our fleet, there is still a wide range between the individual rigs 18,000 – 19,000 a day down to 12,000 or 13,000 day. I think we finally we were still fighting the at quite a few term contracts ruling off in the early part of this year late December of last but I think its like production curve, first thing you got to do before you can increase production is talk to the client and I think we have done that on the rig side you know the second quarter I think overall average day rates can be up a couple of $100 a day so not only has the decline been stopped but we are back into a little bit of an increasing mode over that’s our average overall for our whole fleet but within rigs Jim that range is $500 a day to $2000 a day on some rigs depending on how the rigs are equipped.
Jim Rawlinson - Raymond James
Right. And if you think about your sales of eight rigs on a low end, and I think a while back you had said you have as much as, what, 30 rigs for candidates for upgrades, and some of those are going to get done this year, where does that put your fleet in terms of rigs that are horizontal capable and maybe come out on the higher end of that range versus the lower end of the range?
Once we get through the complete upgrade program and we are not saying we are going to go through the whole program this year that will just kind of depend on what demand is but we have in the range of 85-86 rigs in our fleet that we think are good candidates for it to be competitive in any horizontal drilling market, we’ve got 60 plus of them done currently we were able to get a lot of them done in the first quarter of this year. Some of the rigs always involve putting a top drive on them everything else on the rig was what we needed and some of the rigs are all away from converting it from being mechanical to electric so the range of upgrades is pretty broad across the spectrum.
Jim Rawlinson - Raymond James
So that will get you up to about, roughly, 70% of your fleet, once you're all said and done?
(Operator Instructions) Your next question comes from John Albert from Pritchard Capital Partners. Sir your line is open.
Ray Deacon - Pritchard Capital Partners
Yeah, hey Larry this is actually Ray Deacon I was wondering about the Granite Wash I guess, how many wells per quarter would you think you can put on with the current level of activities, I guess and are there any transportation constrains there?
What we get to three rigs running typically we were looking at on 45 days that right a problem we had is with getting the Fracs timely and we have had delays and being able to get the multi stage fracs out there and we going now, I mean essentially were fracs essentially when we start the well and get the date set out there so I think when we have the three rigs running and get the horizontal machine going I think we’re probably looking 60 days betweens spuds and getting the wells online.
Ray Deacon - Pritchard Capital
Got it. Okay, great. And was just, Larry well, I guess also on the E&P side, there was some talk about some horizontal oil projects you were involved in and I missed the very beginning of the call, but is there anything new to talk about there?
Yeah, there is a number of horizontal oil projects. Last year, we made an effort to focus more on oil, when we started looking around we liked the prospects that were in the Mid-Continent.
So we started prospecting, looking at formations out there that would lend themselves towards drilling horizontally. And right now this year for 2010 we will drill seven or eight different formations that our oil prospective or high BTU gas horizontally.
Some of those which has been drilled before some, which we have not been drilled before and formations are the Cleveland the Tonkawa the Marmaton the Morrow the (Inaudible) and I mean there is a number of those formations.
What we are trying to determine were buildings lease hold positions out there and as we drill these different ones we will reevaluate with the 12 we drill and as typical with the horizontal plays we will try to find that figure out which ones in excess economics and I think you will see us focus certainly more on those and no doubt we think there is a lot of potential for drilling horizontal oil plays out from the mid continent.
And you have no further questions at this time. Pardon me we did get Brad Evans from Heartland. Your line is open.
Brad Evans - Heartland
Thank you for taking the question. I’m just curious, Larry, you talked a little bit about seeing a little bit of improvement for day rates into the second quarter versus the first quarter. Would that also apply to margins as well?
Brad Evans - Heartland
I appreciate that. And then, if you could, could you just discuss on the land rig side, have you had any discussions with customers about engaging in new-build activity at this point? Or are you still more focused in terms of the top drive or other improvements to allow for the rigs to be horizontal capable?
No, there is not been any discussion new builds operators are still very vary assigning three year contracts for commitment a new builds as they were willing to sign up for three years we would be willing to build once they are not cooperating yet.
Brad Evans - Heartland
And then, may I just ask a question about M&A activity? Your balance sheet is obviously pristine. Can you just discuss maybe just how the acquisition environment looks today from an opportunity set?
We are finally starting to see more things, which was the big problem last year. There wasn’t anything out there to look at and some properties that have more producing characteristics to them rather than just big lease hold position.
So, little more optimistic we never which ones you’re going to be successful on, but at least we are now getting to participate in more opportunities to buy things than we have in over the last 18 months.
Brad Evans - Heartland
And let me just sneak one more in. If commodity prices were to surprise you to the positive, I guess, at this point, and you’d have more cash flow than you’re currently expecting, and maybe that comes on the rig side as well, but hypothetically speaking, if you were to be able to allocate additional capital to the upstream side of your business, where would the incremental dollar go at this point if you were to raise capital on the upstream side?
Well, if commodity prices is improve, which has been basically with the majority would be on the natural gas side now, then you are back in the situation where lot of the gas prospects that we put on hold become very economic and so all our gas prospects were still there, you they were just out on hold and should commodity prices come back then you will start seeing a lot more gas property being drilled again.
And we have no further questions at this time.
We want to thank you for joining us this morning. We will be on the road with the next couple of months and certainly different conferences and we hope to see many of you at some of those conferences or in meetings. I appreciate it, thank you again.
This concludes today’s conference call. You may now disconnect.
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