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Unit Corporation (NYSE:UNT)

Q2 2012 Earnings Call

July 31, 2012 11:00 am ET

Executives

Larry D. Pinkston – President and Chief Executive Officer

Brad Guidry – Senior Vice President, Exploration-Unit Petroleum Company

John Cromling – Senior Vice President, Drilling Operations

Robert Parks – Manager and President, Superior Pipeline Company

David T. Merrill – Senior Vice President, Chief Financial Officer and Treasurer

Analysts

James Rollyson – Raymond James & Associates

Raymond Deacon – Brean Murray, Carret & Co.

Brian T. Velie – Capital One Southcoast

Phillip Jungwirth – BMO Capital Markets

Operator

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

This conference call contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act. All statements other than statements of historical facts included in this call that address activities, events, 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 potential that the acquisition discussed in this conference call may not close, the impact of current decline in wells being drilled will have on production and drilling rig utilization; the productive capabilities of the company’s wells, future demand for oil and natural gas; future drilling rig utilization and day rates; projected 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 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 will now turn the call over to Mr. Larry Pinkston, President and CEO. Mr. Pinkston, you may begin.

Larry D. Pinkston

Thank you, John. 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. We will take questions after their comments.

We released second quarter results this morning. We reported a net loss of $19.3 million, as a result of a $115 million pre-tax fuel cost ceiling write down on our oil and gas property book values. The write down does not impact cash flow. The write down was recorded as a result of the decline in natural and natural gas liquid prices. Excluding the write down, second quarter net income would have been $52.8 million or $1.10 per share, basically flat with the first quarter of 2012.

The substantial growth in oil, natural gas and natural gas liquid prices had a significant impact in all three of our segments during the second quarter. The unhedged commodity prices we received in the second quarter, which should be somewhat indicative for the industry, were down 11% for oil, 22% for natural gas, and 17% for natural gas liquids in the second quarter as compared to the first quarter.

Our hedges for oil and gas segment, somewhat mitigated the full reduction to our oil and gas revenue base. However, we did not have a 100% of our production hedge. The lower commodity prices started to have more impact to our drilling division in the second quarter with less demand for our drilling rigs, including three rigs that we’re operating under long-term contracts that were canceled.

The contracts had cancellation penalties, which we are trying to have acknowledged. In our Midstream segment, we received the same commodity pricing in the second quarter that we realized in the first quarter, our margins would have been about $7 million higher. As commodity prices rebound, the impact should reverse for all three of our segments. We released very exciting news from our oil and natural gas division over the last couple of weeks.

Our pending acquisition with the Noble properties will have very significant results for us over the next several years. It is an acquisition that we will realize significant benefits to all three segments of Unit. It provides 600 plus drilling locations that our E&P division will be able to develop for many years. For Midstream division, it will provide immediately one gas gathering operation and at the end of 2014, it will provide an opportunity to gather and process the Granite Wash production for the properties. As we ramp-up the development drilling in 2013, we will be using seven plus drilling rigs from our contract drilling division.

We will fund the acquisition through a combination of terms received from our $400 million bond offering, and we closed approximately two weeks ago, bank debt and property divestitures. We are optimistic at the possibility of selling $200 million to $300 million of oil and gas properties that do not fit with our long-term growth plans. As you can tell, we are very excited about the benefits from this acquisition and look forward to the closing of the acquisition in mid-September.

Our second quarter oil and natural gas production was up 2% over the first quarter. We averaged 36.7000 barrels per day equivalent with 44% of the production liquids. Our second quarter 2012 liquids production is up 26% over the second quarter of 2011. We announced the significant discovery on our Wilcox play this morning, the deeper Wilcox had not been a major focus area for us across our acreage block previously. The resource potential for us and its discovery, we currently estimate at a 160 Bcfe left to us, which is 23% of our year-end 2011 reserves.

Now I would like to turn the call over to Brad to discuss more about our Oil and Natural Gas division.

Brad Guidry

Good morning. We previously discussed most of the second quarter operation results on July 11, 2012 conference call. However, I will give an abbreviated update or summary of operations that have occurred since that day.

As Larry mentioned in our Wilcox play in Southeast Texas, the significant field discovery that we have, we estimated unaudited potential reserves of 229 gross Bcfe, which equates to the 159 net Bcfe to unit. The make-up of the reserves for this discovery is approximately 8% oil, 35% natural gas liquids, and 57% natural gas. This prospect was internally generated by our Houston staff utilizing 3D seismic data and the expertise gained by drilling over 100 wells in this general area. The current field extend its interpret to be approximately 1,000 acres, and has up to nine stack Wilcox plays at depth ranging from approximately 12,500 feet to 15,000 feet.

The average proved gross reserves for well is estimated or approximately 130,000 barrels of oil, 500,000 barrels of NGLs and five Bcf or an equivalent of 8.8 Bcfe proved reserves per well. In addition to the proved reserves, the average gross resource reserved potential per well as approximately 200,000 barrels of oil, 800,000 barrels of NGLs and 8.2 Bcf or an equivalent of 14.2 Bcfe per well. We have these two reserve categories together result in approximately 23 Bcfe gross or 16.4 Bcfe net of potential reserves per well.

The break-down by product on a per well basis and this is gross was 331,000 barrels of oil, 1.3 million barrels of NGLs and 13.2 Bcf per well. The average completed well cost was approximately $6.3 million. The fourth well that we drilled in the field is currently being completed and is now flowing up seven inch casing at a post-frac rate of approximately 80 barrels of oil per day, 200 barrels of NGLs and 1.9 million cubic feet, which is an equivalent rate of 3.6 million. This is flowing at that rate with 8,700 pounds of flowing casing pressure on 8/64 choke.

The production test rate for this well is being curtailed until the pipeline connection is completed in early August. This rate as well was drilled and completed for approximately $5.4 million as compared to the $6.3 million average for the first four wells. We find to drill two additional step-out wells this year and anticipate drilling approximately four infill development wells in 2013, and this should complete the initial phase of development for the field.

Moving to the Marmaton located in Beaver County, Oklahoma. We’ve recently completed the drilling operations on a second extended lateral well that is located approximately half miles for the east of the first extended lateral well that we drilled. The second well was drilled to total depth of 16,360 feet and it was drilled in 23 days, which is an approximately 30% reduction in drilling days and equates to the cost savings of approximately $600,000 as compared to the first extended lateral well. The well drilled approximately 9,700 feet of Marmaton lateral and is scheduled to be fracture stimulated on August 7, approximately 700,000 pounds of sand in 32 stages. The initial extended lateral well was completed on April 14, 2012 and that well produced 50,000 barrels of oil equivalent in the first 69 days of production, which is an average of 725 barrels of oil equivalent per day. Our preliminary reserve estimates for the well is in the range of 400,000 barrels of oil equivalent and completed well costs of approximately $4.2 million. The current plans already drilled two additional extended lateral wells in the fourth quarter of 2012.

Just to note on the Noble acquisition the due diligent process is in progress and today there has not been any significant issues identified. The closing date is scheduled for mid-September 2012. The acquisition is excellent fit with Unit’s current production and leasehold in the Mid-Continent region provides us with many potential drilled – horizontal drilling locations for many years primarily in the prolific Texas Panhandle Granite Wash play. We have identified approximately 600 Granite Wash horizontal locations on about 25,000 net acres and this more than triples our existing inventory of Granite Wash locations and more than doubles our net Granite Wash leasehold.

In addition to the Granite Wash, there are approximately 60,000 net acres that are mostly held by production it’s located in the Anadarko Basin of Oklahoma. This acreage has numerous potential low-risk drilling opportunities and formations such as the Cleveland, the Marmaton, the Skinner, Red Fork, Morrow, Springer and the Cana Woodford.

This concludes my portion of the call. I’ll now turn it over to John Cromling for an overview of drilling operations.

John Cromling

Thank you, Brad. Our contract drilling segment experienced a good second quarter. Day rates increased slightly during the second quarter. The average day rate for the second quarter was $20,128 before elimination of intercompany profits as compared to $19,838 for the first quarter.

The average per day operating margin for the second quarter before elimination of the intercompany profits was $11,130, which is $1,716 per day increase over the first quarter or 18% increase. This is attributable to over $15 million in early termination fees on three rigs, which were released. This would equate to $2,188 per day. And daily operating expenses increased by about 4% for the second quarter over the first quarter. These increases were primarily due to higher indirect cost, direct expenses and G&A expenses. A large portion of the increase is due to an adjustment for personal property tax, which is based upon the value of the rigs.

The last of our plan new builds was commissioned during the second quarter, and it's presently operating in North Dakota under a three-year contract. We do continue to sell surplus equipment, which will not be needed in our future plans and have the potential to sell additional small mechanical rigs, which are not good candidates for refurbishments.

Our average rig utilization during the second quarter were 76.7 rigs, which is a 6% decrease from the first quarter. We have experienced a decrease in demand for the 1,500 horsepower rigs, but have been able to offset this somewhat with additional 700 horsepower to 1,000 horsepower rigs been employed.

The interest and activity continues to increase in the Mississippian play in Northern Oklahoma and Kansas. We recently added two additional rigs to this area. We’re presently refurbishing another 750 horsepower rig that will operate in this region. As the work has completed on this rig and assuming the activity continues, we will begin refurbishing another rig to be available during the third quarter. It is our expectation that increased activity in this market will allow us to maintain approximately the same rig utilization during the remainder of the year.

Unit Drilling’s capital expenditure budget for 2012 has been revised downward at mid-year from $120 million to $109 million. At the end of the second quarter, we have spent about $54 million on CapEx side. Since we do not have any additional new builds planned at this time plus the remainder of this portion of our budget will be applied to have rigs and refurbishments.

And I will now turn it over to Bob Parks.

Robert Parks

Thank you, John. The Mid-Stream segment continues to be very active, and we are producing record segment results for gathered volumes and liquid recoveries. In the second quarter of 2012, we increased our process volumes per day by 96% over the second quarter of 2011. Process volumes in the second quarter of 2012, were 177,407 MMBtus per day. Also our liquids sold volume increased 77% compared to the second quarter of 2011.

Liquids sold volume in the second quarter of 2012, increased to 629,000 gallons per day. While we have produced record segment volumes, liquids prices have fall under very low levels for the second quarter resulting in lower operating profits. Our segment operating profit was $7.4 million in the second quarter, a decrease of 3% from the second quarter of last year, and a decrease of 24% from the first quarter of this year.

During the second quarter 2012, we incurred capital expenditures of $34 million, which increases our year-to-date capital expenditures to $58.6 million as we continue to construct and complete various Midstream projects. We continue to be very active in the Mid-Continent and Appalachian areas.

At our Hemphill facility in the Texas Panhandle, we have recently completed the installation of our fifth processing plant. This new 45 million cubic foot per day processing plant increases our total costs and capacity of this facility to 160 million cubic feet per day. With the addition of this new plant and the increased processing capacity, we are positioned to handle the expected additional volumes from the drilling activity in the area.

At our Cashion facility in Central Oklahoma, we started up a new 25 million cubic foot per day turbo expander plant during the second quarter, increasing our processing capacity to 50 million cubic feet per day. With this additional plant, we are positioned to handle increasing volumes of gas from new drilling activity, and we will be recovering liquids at a higher recovery rate as well.

In the Mississippian play in North Central Oklahoma, we continue to be active and this area remains a key area of focus for the Midstream segment.

During the second quarter, we began flowing gap on our second gathering system in this area, the Bellmon system located in Noble and Kay counties in Oklahoma. This gathering and processing system consists of approximately 10 miles of pipeline and a 10 million cubic foot per day processing plant.

We anticipate upgrading the processing plant to a 30 million cubic foot per day turbo expander plant by the end of the year. Also in this area, construction is underway on our Maryland extension. This extension will connect our existing Remington system to the Bellmon system and will require 26 miles of pipe to complete the connection of these two systems.

We anticipate completing this project by the end of 2012. Also this area we’re constructing a 14 mile extension from our Bellmon system to a third party producer to connect new and existing production. We expect this extension to be completed in the fourth quarter of this year as well. This active area we’re continuing discussions with numerous producers that mainly to potential new projects or expansions.

Turning to the Appalachian area, we are continuing to have success. During the second quarter, we selected five new wells to our Pittsburgh Mills gathering system, which contributed to the increase in volume from last quarter. We recently received all the required permit and have satisfied all the environmental requirements; we continue extending this system to the north. This extension of the pipeline to the north will allow us to connect additional wells, which producers in the processes of drilling. Producers plan to maintain a steady drilling schedule for the rest of this year and into 2013.

In summary, as we reach the midpoint of the year, we are setting segment records for gathered volumes and liquids recovered. As prices recover, we’re positioned well for continued success and looking forward to continuing to expand our Midstream business.

And I will now turn the call over to David Merrill.

David T. Merrill

Thanks Bob. I wanted to briefly update you on the financing arrangements associate with the announcement we made earlier in the month of the Noble Energy oil and natural gas asset acquisition.

On July 24, we completed a private offering of $400 million of principal amount of senior subordinated notes due 2021, and a coupon rate of 6 and 5.8. The notes were sold at 98.75% a par plus accrued interest from May 15 of 2012, and the net proceeds are to be used partially finance the pending acquisition, if the pending acquisition agreement is terminated or not consummated by certain dates, the notes are subject to a special mandatory redemption. Also in conjunction with the pending acquisition, we intend to increase the elected commitment under our existing credit facility from $250 million to up to $750 million. The borrowing base associated with the credit facility is also anticipated to increase from the current $600 million to $800 million.

We ended the second quarter with the debt to capitalization ratio of 14%, and had $82.9 million of borrowings outstanding under the credit facility. We completed our mid-year review of our operating capital expenditures budget for 2012 during the quarter with our original overall segment budget remaining unchanged at $801 million, excluding acquisitions and including anticipated capital expenditures associated with the Noble acquisition subsequent to closing.

The effective income tax rate for the first six months of 2012 were 39.2%, and we currently estimate the rate for the year to be approximately the same, and the current portion of income taxes is estimated to range between 0% and 3% for the year.

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

Question-and-Answer Session

Operator

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

James Rollyson – Raymond James & Associates

Good morning, guys.

Larry D. Pinkston

Hi, Jim.

James Rollyson – Raymond James & Associates

Larry, if I did my math roughly correct, excluding the Noble volumes that you’ll add hopefully in September, you are somewhere in the 50% to 60% ballpark of your 2013 oil production being hedged at this point? And just kind of thinking out loud, but wondering especially when you add in Noble, how you feel about hedging? Where you want to be in terms of positioning and pricing and what have you just – how you are thinking about hedges on the oil side going into next year?

Larry D. Pinkston

Jim, as you know, we’ve always kind of been (inaudible) we’d like to be somewhere in the 70% area hedged going into the current production year. So going into 2013, we like to be somewhere in that 70% of our estimated production for that year, both on natural gas and on oil. We’d like to have opportunity to do that on liquids, but it’s pretty tough to hedge out liquids very far in the future. But we will be increasing both hedging on oil and natural gases as we see opportunities to do that.

James Rollyson – Raymond James & Associates

Sure. And since you brought up liquids, is it still kind of out about six months is about as far as you can go?

Larry D. Pinkston

Pretty much, Jim, pretty much it’s – it gets pretty illiquid and you think a pretty good [hickie] on prices if you try to go out beyond that.

James Rollyson – Raymond James & Associates

Given your kind of stepped up position to an NGL related markets particularly with the Noble acquisition, does that bother you all going into next year?

Larry D. Pinkston

It’s a bigger concern that we – I think we get through this period that we are in right now through this shoulder period and the natural gas storage looks like it’s going to get somewhat handled. We’re not going to have run out of places forward. And assuming we have a winner this year, I mean and moreover expecting ethane process at $0.70 now that I think is a good likelihood that we can get back up in that – in the $0.40 to $0.55 range.

James Rollyson – Raymond James & Associates

Okay, that’s helpful. And on the rig side, you had three rig contracts bought out in the quarter and if I remember right, the last call you guys had right after the Noble deal, you mentioned there might be a couple more. Can you kind of give us an update on customer conversations on that front and maybe prospects for giving those rigs signed up somewhere else?

Brad Guidry

Right now, (inaudible) we are going to have two more release. Beyond that, we don’t have any indications of any other. So far, the rigs that came off those contracts, we’ve not got those re-contracted anywhere. We had some possibilities as nothing is worked yet for.

James Rollyson – Raymond James & Associates

And on the rigs you have going into the Mississippian, the 750 horsepower to 1000 horsepower type rigs, can you give a little comparison on the margins for that type rig versus the ones that are going down?

Larry D. Pinkston

That will be a little bit less of course because of the size of them, but those rigs should be around $9,000 a day margins.

James Rollyson – Raymond James & Associates

Okay, not too far often.

Larry D. Pinkston

No, not really and most of those contracts will be ranging from six to 12 months in lease.

James Rollyson – Raymond James & Associates

All right. And David last question from me, with the write-down on the E&P valuations kind of thoughts on forward expectations for DD&A rates.

David T. Merrill

Yeah, they ought to be down in Q3 from Q2, they ought to be down somewhere in the 2% to 3% range from what was in second quarter.

James Rollyson – Raymond James & Associates

Okay, helpful. Thanks guys.

David T. Merrill

Obviously we have to continue to watch what prices do to the 12 month average for the SEC numbers we use for the impairment calculation, but that’s what the impact is going into Q3.

James Rollyson – Raymond James & Associates

Perfect. Appreciate it guys.

David T. Merrill

Thanks, Jim

Larry D. Pinkston

Thanks, Jim.

Operator

Our next question comes from Ray Deacon from Brean Murray. Please go ahead.

Raymond Deacon – Brean Murray, Carret & Co.

Yeah. Hi, David, I was wondering if you could say what the impact was of the rig cancellation from the cash margin during the quarter or you said I’m sorry, you did say that the $2,200?

David T. Merrill

Price, it’s just under $2200 per acre.

Raymond Deacon – Brean Murray, Carret & Co.

Right. And so that is just a one time impact, I guess what’s the outlook for 3Q I guess versus 2Q adjusted?

David T. Merrill

You’re right, that is a one time deal. Larry alluded to couple more that we – it looks like we may have in the third quarter. But you would do the same thing with those that you’re doing with the three that we’re talking about for Q2.

Raymond Deacon – Brean Murray, Carret & Co.

Got it

David T. Merrill

Margins will probably be down a little bit from Q2, nothing significant. But with the change and mix of rigs that Larry and John were alluding to, there will be a little bit of change at the bottom line too.

Raymond Deacon – Brean Murray, Carret & Co.

Okay, got it, got it. And you said that the $801 million CapEx budget includes some increased capital for the Noble properties I guess in the fourth quarter. I guess could you just talk about what you’re going to be doing there other than the increase in the Granite Wash? Are there any other zones you’ll be testing or I’m just curious.

Larry D. Pinkston

No, Ray, there is not.

Brad Guidry

Ray, we moved them I think around in our budget to take into account, you are not going to do a whole lot this year with the Noble properties, that’s mostly the startup in 2013, but…

Raymond Deacon – Brean Murray, Carret & Co.

Right.

Brad Guidry

We didn’t increase our budget any because of the Noble.

Larry D. Pinkston

And what the anticipation there is on the Noble side for the acquisition economics that we put together is that, Noble activity is self funding essentially on the CapEx side with the cash flow that we have.

Raymond Deacon – Brean Murray, Carret & Co.

Okay, got it. And I was just curious on what kind of rate of returns on this extended Marmaton lateral you think you'll be able to achieve given 400,000 barrel EURs you think you're getting, and with the next two wells be a bigger step out, I guess.

Larry D. Pinkston

When you run the parameters on 400,000 barrels, the rate of returns are 100% or greater. So in that asset 90 oil, 250 gas, and I guess 40 NGLs. Going forward, the second well we’re drilling is a half mile east to the first well. So basically if it was a 640 section, it would be in the same section. That well has been drilled; the frac is coming up here in another week or so. So we’ll get a better idea, if there will be any drainage issues with the wells being that distance part or if the reserves are looking about same that we see in the first well.

The other wells we’ll drill, the other two wells we have in the fourth quarter will be in a different area. So we'll get another look at it in a different place. In general, the area we drill this first one and has been a good area, I mean we’ve – it was the first well in that section, but the offset sections, even the short lateral wells probably averaged more in a 175,000 to 200,000 barrels equivalent.

Raymond Deacon – Brean Murray, Carret & Co.

Got it. Great. Hey, thanks Brad.

Brad Guidry

Yeah.

Operator

Our next question comes from Brian Velie from Capital One Southcoast. Please go ahead.

Brian T. Velie – Capital One Southcoast

Good morning guys.

Larry D. Pinkston

Good morning, Brian.

Brian T. Velie – Capital One Southcoast

A couple of quick questions, first in the Mississippian, I know there is an increased level of interest, it seems like that’s going to benefit the midstream and drilling and I know that you haven’t spoken much about the E&P side of things, but can you comment maybe on where you stand currently on acreage there and where you intend to go in terms of the total acreage position before we might get a little bit more information?

Larry D. Pinkston

Yeah. our current acreage for this is about 75,000 net acres, and we’d certainly like to get to the 1,000 mark or so.

Brian T. Velie – Capital One Southcoast

Okay. Any anticipation on when we might start to hear a little bit more about individual roles, also expectations in terms of size and pricing cost?

Brad Guidry

We’ve just drilled the one well up there thus far, and the reason we’re wanting to a get a lot of cap side is in part, the plays where you have submersible pumps on them to produce them, it just takes time to really get a good feel of the decline that you’re looking at on these wells. and then of course, that gives the EUR. So, in general, I don’t think we will be talking about results from that well, certainly not before end of third quarter and possibly end of the year.

Brian T. Velie – Capital One Southcoast

Okay, great. Thank you. And then the two rigs that you think you might be releasing here in the near future, can you comment on where they would be coming from?

Brad Guidry

They will be in the Bakken and North Dakota.

Brian T. Velie – Capital One Southcoast

Okay. And the penalties for the canceled contracts are they similar in terms of scope about 5 million per?

Brad Guidry

These will be a little bit less, because they have less days remaining on the contracts than the prior ones did.

Brian T. Velie – Capital One Southcoast

Okay, great.

Larry D. Pinkston

Close to 4 million of fees.

Brian T. Velie – Capital One Southcoast

Okay, thank you. And then finally, the Marmaton long lateral wells are sounding extremely promising, and I know that there is a little bit more concern maybe in the Marmaton area for repeatability or the absence of national fractures in that area. is that a big concern or is the longer lateral make it a little bit less concerning for you than maybe the vertical for it?

Brad Guidry

As we are drilling out the play, I mean there’s definite sweet spots in areas that are with less fracture. I mean if you are in a area that didn’t have a lot of fractures whether you drill short lateral or long lateral probably and going to make a whole lot of difference.

Brian T. Velie – Capital One Southcoast

Okay.

Brad Guidry

And as I anticipate it, helping is in those areas where maybe a mixture. the more lateral you can put out there, the more opportunity you get yourself to intersect the fracture pattern, and yeah it should help. I mean it should reduce the risk of drilling the marginal wells to some extent.

Brian T. Velie – Capital One Southcoast

Okay. And then the – but it sounds like the real help will just come from the amount of wells that you’ve drilled to date.

Brad Guidry

Correct, yeah. there is no question that there are areas that whether you drill long lateral or short lateral, it will be a pretty good well. But the overall economics of long lateral certainly looks promising. I mean that’s the way, we would want to go forward. but the land portion of that it’s been a little bit of a complication to overcome, but we’re working towards that. If all things were the same, we would certainly prefer to drill develop the field on a long lateral basis.

Brian T. Velie – Capital One Southcoast

Okay. so maybe it’d be a good way to think about it is there is more money at risk, because these wells cost more than the verticals. but with the 100% rate of returns, we got a lot of room to play where it doesn’t have to be absolutely perfect as long as you come across some natural fracturing. You did better than you probably would have done the verticals?

Larry D. Pinkston

Sure, I mean to think about it. we see some changes from section-to-section. So if you drill a single lateral in the section that may not be as good as the offset section if you drill the extended lateral, you’re going to penetrate both of those. So it almost has a little bit more than average in effect with in a statistical type play, that’s a good thing.

Brian T. Velie – Capital One Southcoast

Okay, great. That’s all I’ve got. Thanks guys.

Larry D. Pinkston

You bet.

Operator

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

Phillip Jungwirth – BMO Capital Markets

Yeah, good morning; I just had a couple of quick questions on your well cost discovery. I was wondering if you could tell us what the key motive first year production has been for the original discovery well that came on line in July of last year.

Larry D. Pinkston

I can get that for you, I don’t have it in front of me. But I’m thinking it’s somewhere around 3 Bcf. The original well we drilled out there has been producing about 6 million a day since that time.

Phillip Jungwirth – BMO Capital Markets

Okay. And then have you seen much of a decline yet?

Larry D. Pinkston

No, it’s actually still flowing with 5,000, 6,000 pounds in tubing. I mean, we the well is capable of falling at a higher rate than that, but we do the commodity pricing, we’ve just held that as that 5 million or 6 million a day.

Phillip Jungwirth – BMO Capital Markets

Right, okay. and do you have an estimate of when you think that well will start to decline?

Larry D. Pinkston

I’d have to look at the curve. but I mean at this point, it’s a little bit unknown. I mean the data that we have, I mean it has not showed a decline at this point and the pressure has been, it’s come down some, but it is not anything significant. So it’s typically Gulf Coast wells with really good wells like this you may see fairly flat production over first three to five years. and then you’ll start seeing the decline, but that's just I mean that’s a guess at this point.

Phillip Jungwirth – BMO Capital Markets

And then, how many locations are in your resource potential estimate?

Larry D. Pinkston

10 totally.

Phillip Jungwirth – BMO Capital Markets

Yeah. So that we drill four plus to two plus to four...

Larry D. Pinkston

Correct. and the only thing that I will change of that is with there are so many stack payees in this field, but there may be some point certainly, if quantity price comes up that we may want to accelerate the recovery of the reserves in there. one well may have seven or eight different payees in it, and the strength of the payees that we're in doesn't really – weren’t leaving that or the complications of commingling. So there is possibility after we get the 10 wells drilled, we’ll come up with the development plan to maximize the value basically.

Phillip Jungwirth – BMO Capital Markets

Okay. And then as the $5.4 million well cost reasonable estimate on a go-forward basis with that…

Larry D. Pinkston

Yes, it is. Yes.

Phillip Jungwirth – BMO Capital Markets

Okay. And is it a quarter royalty?

Larry D. Pinkston

Yes.

Phillip Jungwirth – BMO Capital Markets

Okay. And then last, can you tell us what your current rig count is?

Larry D. Pinkston

For the petroleum or the drilling county?

Phillip Jungwirth – BMO Capital Markets

Drilling.

Larry D. Pinkston

That I guess 73.

Phillip Jungwirth – BMO Capital Markets

Okay. That’s everything I had. Thanks guys.

Larry D. Pinkston

Thank you.

Brad Guidry

Thanks a lot.

Operator

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

Thank you, John. This could conclude the meeting. We will be presenting at the intercom in I could say mid-August. and hopefully we’ll get to see many of you there. we’re looking forward to discussing many of these things in much more detail and we very much appreciate you hearing the conference call this morning and that concludes our remarks. Thank you.

Operator

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

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