Arena Resources Inc. Q2 2009 Earnings Call Transcript

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 |  About: Arena Resources, Inc. (ARD)
by: SA Transcripts

Arena Resources Inc. (ARD) Q2 2009 Earnings Call August 7, 2009 11:30 AM ET

Executives

Tim Rochford – Chairman of the Board

Phil Terry – President and Chief Executive Officer

Randy Broaddrick – Vice President and Chief Financial Officer

David Ricks – Vice President, Operations

Analysts

Neal Dingmann – Wunderlich Securities

Philip McPherson – Global Hunter Securities

David Heikkinen – Tudor Pickering & Co.

Jeff Hayden – Rodman & Renshaw

Leo Mariani – RBC Capital Markets

Noel Parks – Ladenburg Thalmann & Co.

Mark Lear – Sidoti & Company

John Lane – Lane Capital Markets

Irene Haas – Canaccord Adams

Ronald Mills – Johnson Rice & Co

Mike Breard – Hodges Capital

Richard Tullis – Capital One Southcoast

Operator

Welcome to the Arena Resources second quarter 2009 earnings conference call. (Operator Instructions) I would now like to turn the call over to Tim Rochford, Chairman of the Board.

Tim Rochford

My name is Tim Rochford, Chairman of the Board. Along with me this morning is Phil Terry, our President and CEO, Randy Broaddrick, our Chief Financial Officer, and David Ricks, our VP of Operations.

Before we begin I'd like to make reference to any forward-looking statements which may be made during this call or within the meaning of the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995. For a complete explanation I would refer you to our release issued this morning. If you don't have a copy of this release, one will be posted on the company Web site at www.arenaresourcesinc.com.

Now today we will cover the financials and operations for the second quarter and the six months ended June 30, 2009. We will review our results and provide some insight into our current progress as we begin our third quarter of 2009. At the conclusion of the second quarter review we'll open up for questions that any of the listeners may have.

At this time I'm going to turn this over to Randy Broaddrick, our Chief Financial Officer. Randy, if you'd be kind enough to give us your overview please.

Randy Broaddrick

For the three months ended June 30, 2009, the company had oil and gas revenues of $27.6 million and net income of $14.4 million. This compares to revenues of $62.2 million and net income of $24.8 million in the second quarter of 2008. This represents a decrease of 56% in revenues and 42% in net income.

For the six months ended June 30, 2009, the company had oil and gas revenues of $47.8 million and net income of $20.9 million. This is compared to revenues of $107.5 million and net income of $43.1 million in 2008. This represents a decrease of 55% in revenues and 52% in net income.

On a fully diluted basis the earnings per share for the three months ended June 30, 2009, were $0.37 or $0.39 per fully diluted share excluding a $1.22 million non-cash charge for share based compensation. This compares to $0.67 or $0.70 per share excluding a $1.5 million non-cash share for share based compensation in 2008.

For the six months ended June 30, 2009, earnings per diluted share were $0.54 or $0.58 when excluding a $2.54 million non-cash charge for share based compensation. For 2008 we had $1.18 per share or $1.24 when excluding a $3.25 million non-cash charge for share based compensation.

Net cash flow from operations, adjusting for changes in operating assets and liabilities for the three and six months periods ending June 30, 2009, were $31.6 million or $0.81 per share and $50.5 million or $1.30 per fully diluted share. This compares to $48.5 million or $1.31 and $85.5 million or $2.33 per fully diluted share in 2008.

Our average commodity prices received in the second quarter 2009 were $55.23 for oil, $4.16 for gas for an average per BOE of $50.46. These represent a 54% decrease in the oil price, a 61% decrease in the gas price and a 55% decrease in the average per BOE.

Our lease operating expenses, including production taxes, were $8.62 during the second quarter of 2009. This is a 34% decrease compared to 2008. Our total depreciation depletion and amortization was $13.53 per BOE, which is flat compared to 2008.

Our G&A was $6.33 per BOE, which represents a 3% increase compared to the same period in 2008. We had $68 million in cash at the end of the quarter and no long-term debt. And our shareholders equity exceeded $496 million.

Our production costs, we saw a decrease in the production costs per BOE for the three months ended June 30, 2009, to $5.97 as compared to $7.66 for the same period in 2008. For the six months ended June 30, 2009, our average costs per BOE were similar with a slight increase from $6.68 in 2008 to $6.70 in 2009.

Costs for oil field related services and materials tend to move up or down in conjunction with commodity prices. Leading up to, during and after the first quarter of 2008 through mid-year 2008, commodity prices, and therefore prices for oil field related services and materials, increased dramatically with a time lag on the increase on services and material prices.

Since that time the commodity price has weakened significantly. The reduction in our cost per BOE during the three months ended June 30, 2009, has been expected as the time lag between commodity prices decreasing and a corresponding reduction in costs for service and material costs. We expect our production costs to remain around this level. However with the uncertainty regarding commodity prices, the actual expense that we will see in 2009 is difficult to predict.

Concerning production taxes, we saw a decrease in production taxes per BOE for both the three and six month periods ended June 30, 2009. For the three months ended, our production taxes per BOE decreased from $5.34 in 2008 to $2.65 in 2009. For the six month numbers, production taxes decreased from $4.94 to $2.29.

Most production taxes are based on values of oil and gas sold so our production tax expenses directly correlated to the commodity prices that we are being paid. Our oil and gas production taxes will continue to increase or decrease relative to commodity prices.

We saw a decrease in our overall DD&A for the three months ended June 30, 2009 as compared to the same period in 2008, and an increase in our overall DD&A for the six months ended as compared to the same period in 2008.

As has always been the case, depletion of our oil and gas properties is a primary contributor to our DD&A. A gradual increase in depletion costs is expected as we continue to develop our properties. This gradual increase is the result of our adding capitalized costs as we develop our properties and adding future development costs as we add additional reserves.

For the six months ended, the DD&A per BOE increased from $12.88 to $13.29 for the three months ended June 30, 2009. This increase is the result of capitalized costs for the development performed between the periods.

Under our currently projected development plan, which is largely dependent on commodity prices, we anticipate an increase each quarter in 2009 to ultimately average approximately $14 per BOE for the year, excluding the impact of any additional acquisitions throughout the year.

Our depreciation expense for the remainder of 2009 should remain fairly consistent with the first and second quarters. As has always been the case, depletion is the dominating factor in our overall DD&A calculation and will continue to be.

Our overall general and administrative expense for both the three and six month periods ended June 30, 2009, were slightly lower than the same periods in 2008. However, the components of those total costs varied somewhat. Stock based compensation decreased from approximately $1.5 million in the second quarter of 2008 to approximately $1.2 million for the same period in 2009.

We anticipate continued decreases in our stock based compensation announced for 2009 as options continue to vest. Any options granted during 2009 would cause further increases above the anticipated amount. We expect reductions in our overall G&A as we move forward.

Effective June 1, 2009, we decided to monetize the balance of a hedge in the form of a costless collar we had in place for 1,000 barrels per day, with a floor of $100 and ceiling of $197. This hedge would have continued through year-end 2009. We received payments through May 2009 production and received a lump sum payment of approximately $8 million for the remaining period of June 2009 through December 2009.

Also effective June 1, 2009, we entered into a new hedging arrangement. This hedge was also a costless collar and is based on the WTI index price. Our new collar is for 3,000 barrels a day, with a floor of $50 and a ceiling of $72.60 running from June 2009 through December 2009.

Subsequent to June 30, 2009, we entered into a new costless collar in relation to our Yates gas production. This hedge is for 5,000 MMBtu of gas per day and is based on the El Paso Permian pricing. This hedge becomes effective in January 2010 and runs through December 2010, with a floor of $4 and ceiling of $7.87.

Also subsequent to June 30, 2009 and issued today, which is why this is not disclosed in our 10-Q, we entered into a new costless collar for 2,000 barrels a day of oil. Similar to our new gas hedge, this collar is effective January 2010 and runs through December 2010. This collar has a floor of $65 and a ceiling of $93, all based on the WTI index price.

Going forward we will continue to evaluate potential hedging arrangements. We are prepared to add additional hedge instruments if and when the timing and pricing is right. Because we are not leveraged we are not forced to enter into hedges that may not be in our best interest over the long-term. We will continue to evaluate and may, or may not, place additional hedging instruments during 2009.

Effective as of June 30, 2009, the company entered into a new agreement for a credit facility of $150 million with a borrowing base of $75 million and an accordion feature for an additional $75 million. The new facility has an interest rate grid, which determines our interest rate based on our level of utilization.

The range for that grid is LIBOR plus 2.25% to LIBOR plus 3.25% with the total interest rate to be charged being no less than 4%. All other terms and conditions of the credit facility are the same as our previous facility.

With that, I'll turn it back over to Tim.

Tim Rochford

Now I'd like to ask Phil to give us a recap of second quarter operations if you would please?

Phil Terry

An operational recap will begin with our drilling activity for the first six months and specifically the second quarter. In that second quarter we drilled 33 new wells on our Fuhrman-Mascho properties in Andrews County. In addition, we continued to improve and upgrade our leasehold infrastructure.

In mid-May we deployed our second company-owned drilling rig to drill in our Fuhrman-Mascho areas, and as a result we added about $20 million to our 2009 CapEx, which totals about $85 million. We are still operating within cash flow with the two drilling rigs and we estimate that each of the drilling rigs, I'm sorry with the addition of that second rig we'll add at least 45 wells to our program for the year. We now anticipate that we will drill approximately140 wells this year. David Ricks will go into greater detail to discuss our rate of drilling and the increased efficiencies that we are seeing.

I'll point out that we are seeing some improvements in our oil price structure. As all are aware, we've come through a pretty drastic and volatile period. In January we received about $33.89 per barrel, moving forward by month, February was $31.72, March $41.66, April $46.71, May $54.15, June $65.79.

As a result of those increases, as we had told our investing committee, as we got better prices we would employ more rigs. So in late May, I'm sorry, about mid-May we deployed our second company rig. Those increased prices are allowing us to do some planning, which may result in our placing a third rig in operation before the end of this quarter. And some of our hedging activity is to protect that possibility.

Further to our oil price, I should point out to you that Arena's differential between NYMEX and the price it receives has continued to decrease over the past several months. The latest information that I can provide you is that NYMEX minus $4 is the net price that Arena is now receiving for its crude oil, and that includes deductions and corrections for gravity, transportation and all other deductions.

So as of today if NYMEX is at $71.50, we're going to be receiving about $67.50, which is a dramatic improvement. At one point in time that differential was north of $10. It has averaged between $6 and $7 for a number of years, so we're pleased that our marketing situation has improved in that regard.

I mentioned that we are anticipating adding a third rig. We are at this point in time fairly certain that we will do that. That activity would start probably in September, plus or minus September 1 with the idea that we would then have our two company rigs, plus a third contract rig for the remainder of the calendar year.

As we move forward we should be able to lock in better prices for that contract rig. We're also seeing our drilling and completion costs decrease. David will give you more detail about that. And we're seeing our lease operating expenses decrease also.

As Randy pointed out, we saw a pretty dramatic decrease in LOE on a per barrel basis from the first quarter to the second quarter. And that's in harmony with what we told you in the past that we were 26% to 30% decreases in drilling costs and similar decreases in our LOE.

In the second quarter of 2009 our sales as a result of production were 547,706 BOEs. Our average daily net production was about 6,019 barrels per day. The average sales price we received in the second quarter was $50.46.

The sales for the first quarter of 547,706 were slightly less than the first quarter. The first quarter of the year was 568,053. We should point out to you that during the second quarter we had a total of just over 19,000 barrels of production that was lost due to downtime. That downtime came in the form of electrical downtime and downtime associated with our casing head gas purchaser associated with the Fuhrman-Mascho.

Breaking that 48 days of downtime even further, 30 days were due to electrical days either associated with construction of new facilities or storms, and the remaining 18 days were due to down days of DCP, either plant days or system failures.

I should point out that we feel confident that we will see fewer down days associated with electrical failures, particularly system failures. Our electrical provider has spent a great deal of time in the second quarter building and re-doing its infrastructure. So many of those 30 days were directly associated with days that the field was down while the electrical provider was upgrading and building new facilities, so we're very encouraged about what we're seeing there.

We hope to see a pretty dramatic decrease in those system failures. Now the failures we cannot predict are those associated with storms. Late in the second quarter and now into the first quarter we've seen several days downtime as a result of some pretty severe electrical storms. We've had a couple of lightning strikes that are affecting our water facilities, so Mother Nature has not been terribly kind to us but that's just part of the operation procedure in West Texas.

Further to our production, we feel pretty strongly about the direction that we're headed. It should be pointed out that the first well that really resulted from deploying our second company rig came on line in the second week in June.

So even though we put that rig in operation in mid-May, June the 9th was the day that the first well, drilled by that well actually came on production, so we really didn't see a great deal of improvement or great deal of production increase as a result of that second rig. We will see the impact and the effects of that addition in quarters three and quarters four and, obviously, if we add the third rig there will an additive feature there.

For the six months ended June 30. 2009, our sales as a result of production were 1,115,579 BOEs, which is a 4% increase over the same period the prior year, the average commodity price for the first six months of 2009, 4579 for oil, 434 for gas. The average sales price for BOE received in the first six months was $42.87 that compares to $99.92 for the same period on 2008.

As we look further into 2009, you can gauge some additional activity and potential for growth based on our Yates Gas project development. We actually started selling some gas in late May. We have continued to re-complete wells, which David will tell you a little more about in just a moment. And the remainder of the year you'll see us continue to re-complete existing idle wellbores to grow that Yates Gas production.

Also in the future in addition to our third rig, which we anticipate coming onboard probably around the first of September, we will resume or refrac program. As you're aware, we've been quite successful refracing wells in the past. We are now seeing crude oil prices that are attractive enough to offer good economic incentive to resume our refrac program.

We've identified approximately 50 wells in which we own 100% of the working interest and these wells are in good areas that offer potential for 8 to 20,000 plus barrels of additional reserves per well, so we will gear up our refrac program also beginning in September, or as soon as we can get the infrastructure in place.

That concludes my recap. We'll talk in greater detail about some other things. First of all, however, I will turn this over to David Ricks for operations review.

David Ricks

In the second quarter of 2009, we drilled 33 San Andres wells, 29 of those wells were 10 acre locations, two were 20 acre and two were 40 acre locations. We'll continue to high grade locations drilling the wells with the best potential to provide favorable economics.

We currently have two company drilling rigs operating at Fuhrman-Mascho. We are in the process of drilling our 50 well of the year, putting us on pace to drill 45 wells this quarter. With both rigs drilling to year-end, we anticipate drilling 140 wells this year. This is more wells for the year than previously anticipated due to better efficiency of the drilling rigs resulting in faster drilling times.

The drilling plan going forward includes drilling two five acre wells in the third quarter and two five acre wells in the fourth quarter. The five acre wells will be drilled in our enhanced fairway of production and reserves where we encounter an abnormally thick section of Grayberg in addition to the San Andres.

Engineering is complete to install an oil gathering system at Fuhrman-Mascho to tie-in 11 commingled batteries to an existing pipeline. Surveying and the Right of Way acquisition has begun and upon completion, construction will begin. Anticipated time to finish the project is 90 days barring any pipeline contract delays. The crude oil gathering and pipeline connection will generate over $1.8 million in revenue in its first year of operation. We continue to look for every opportunity to reduce expenses.

A recent example is a negotiated agreement that will provide a $1.9 million savings for cementing and stimulation on the 90 new completions scheduled for quarters three and four, current AFE costs for each new well is $461,000. We're also working on gathering the data required to submit water flood utilization plants to the Texas Railroad Commission for Fuhrman-Mascho. We hope we will be able to get our water flood on the docket with the Railroad Commission for approval in 2009.

Hafton Pipeline completed the pipeline for our Yates Gas in late May and we began sales through the pipeline on May 27. We currently have 30 wells producing in the pipeline and we averaged 1.8 million cubic feet per day during the first month.

We are evaluating results and will continue to concentrate on converting more idle and low volume San Andres wellbores where the economics justify and we anticipate we will have 90 Yates producers by year end. Outside of Fuhrman-Mascho, we have completed geological and engineering studies for our Morrow properties in Oklahoma and at the East Hobbs San Andres unit in New Mexico.

In these areas we determined a need for improvements in our injection efficiency. At OMU in Oklahoma we have increased injection and are seeing a good response of about 20 barrels a day after only three months. We will continue to expand and increase injection in Oklahoma. At East Hobbs San Andres unit, we also plan to take a similar approach by increasing injection and changing injection patterns to improve water flood sweep efficiencies.

That concludes the operations report, so I'll turn it back to Tim.

Tim Rochford

Well in summary, we are now join our 546th well at our Fuhrman-Mascho lease since starting our development program back in 2005, that's with 100% development drilling success rate. As already mentioned, we have two rigs deployed at running at Fuhrman-Mascho and a third rig will begin in September.

Our Yates project is well on its way and once again we will be increasing our CapEx to reflect the additional activity, not only for the makeup wells that we're now paced with to reach 140, but the additional third rig wells that'll be drilled and the additional activity as it relates to the refracs. That CapEx will probably be reported to the Street sometime before the end of August.

As already mentioned by Randy and explained, our credit facility is complete and in place. And I'm happy to mention and I know we're proud, all management's proud that all the above activity has taken place this year within cash flow generated from internal operations as we stated it would with surplus remaining.

So good things ahead of us, I think we can - we've supported the fact that with the implication of the added third rig, with the additional wells will be drilled with the original two rigs, the added activity as it relates to refracs and the ongoing Yates project, along with some internal infrastructure support as well that continue the growth will take place within Arena's production and reserves as we finish up the remainder of this year.

We continue to look for opportunities for acquisitions, particularly in areas that complement our current operations, but we're also looking for that new core area project. So with that, this concludes the company's portion of the 2009 second quarter and six month financial and operational review.

We'll turn it back over to the operator. And operator, we'll open it up for any questions that are listeners may have.

Question-and-Answer Session

Operator

(Operator Instructions) Our first question comes from Neal Dingmann – Wunderlich Securities.

Neal Dingmann - Wunderlich Securities

Just one related question as far as down time, Phil, you addressed that pretty well. Wondering now with obviously the pipeline lighter in the year, if you could just sort of address kind of what your expectations or I guess you never really planned for downtime, but as we kind of look forward, how you think you can mitigate or what we can kind of expect on that side.

And then if I could sneak in one other towards, Tim, as far as I'm sure the natural question out there is with all this activity and I guess the economics that are out there, just wondering the natural question given the economics, why not bring on a fourth or fifth rig if you can hedge around that and just blocking these [returns]?

Phil Terry

Neal, as I said, we experienced downtimes due to both electricity and our electrical system and also to DCP on the gas gathering side. As I broke down those numbers, we were seeing about 30 days related to electrical downtime, we anticipate that that number will fall quite significantly. Obviously electrical storms play a part in that, but a good number of that 30 days of downtime for the second quarter was directly related to the electrical system being upgraded and new construction.

That process is either complete or very near completion. So we do not anticipate 30 days of downtime for the quarters three and quarters four. And another thing, just looking at the weather patterns in West Texas we're coming out of the spring and summer thunderstorm period. We should see less activity in terms of lightning and storms and quarter three and quarter four are a little calmer than the rest of the year.

So we obviously cannot plan or predict exactly how many down days we'll have but actually we figure if you can keep down time to somewhere around 10% to 15%, you're about right. So about three or four days a month would be accessible to us, which would translate to 9 or 10 days for the quarter as opposed to 30.

The DCP downtime has shown a good pattern of reduction. We had seven down days in April, eight in May and only three in June. Now again, we can't predict exactly how that's going to move forward but we have seen DCP apply some money to refurbishing and redoing some of the compressor facilities and hopefully we'll see a decrease in that downtime also.

Tim Rochford

Let me address the second part of the question, and I'll respond this way that I think the evidence that as Randy reported earlier, implementing putting that new hedge in place as of this morning gave us further assurance or insurance. And with that, we've made a commitment just very recently here to go ahead and deploy that third rig, that contract rig, which will begin sometime in September.

I can't give you the details as to whether it will be early in the month or latter part of the month but we feel comfortable that will definitely be sometime in September and will remain at the Fuhrman-Mascho through the remainder of the year.

Beyond that, let me assure all listeners that it's our mentality, it's our belief that with the infrastructure that's in place, with our staff of people that are at hand, not only from the drilling side, but of course but the core from the operation side, we're certainly capable of moving this back up to a higher level, whether it's a fourth or fifth rig.

That will depend on where we're seeing commodity prices. And if we continue to see a stability and strength in here, there's two things I think you can count on. One is that we will be looking to layer further hedging opportunities and secondly that you could expect to see yet another rig between now and year-end. And we'll just have to wait a little bit longer here, Neal and listeners to see how things unfold here.

Operator

Our next question comes from Philip McPherson – Global Hunter Securities

Phil McPherson - Global Hunter Securities

Two production questions, can you give us what daily production currently is at and then the follow up would be going from 30 wells in the Yates to 90, is it a linear kind of equation going from 1.8 to potentially 5.4 million a day?

David Ricks

As far as production, Phil, the first question you had, looking back at our second quarter just to reiterate, we averaged about 6,018 barrels per day net. The downtime was another 200 barrels, so we're 62 or so. We're seeing numbers thus far in the third quarter that are better than the second quarter numbers.

It's difficult to say right now, we've come through some more storm periods, we've had some downtime but we're between 6,500 and 6,700 barrels a day depending how much downtime you have. And we should see that continue to increase as a result of having our second rig for the entire quarter for the third quarter.

Just to give you an idea as to how our growth has historically been reflected, if you go back to our production numbers that we have published through the years, in 2005 we employed one drilling rig. In 2006 we employed two, in 2007 we added a third, and in 2008 we went to four and then ultimately five.

If you look at our graphs as to production growth on a year-to-year basis, you could pretty well correlate that production growth to a number of rigs employed during that year. And we anticipate that we will see those same kind of growth numbers in our production going from, keep in mind that we went from five rigs this time last year to one rig in January. We came back with the second rig in May, so we're starting back up that production growth ladder. But that correlation between the number of rigs running and the resulting production from that rig is pretty straightforward.

Tim Rochford

I think there was another part of your question, Phil.

Phil McPherson - Global Hunter Securities

Completion of the [inaudible], you said in the prepared remarks you were going to go from 30 wells online to 90 by the end of the year, and I was wondering if we could kind of look at it, production was 1.8 off of 30, so can we look at it as saying it should triple then?

David Ricks

I think we should see similar results out of the additional wells when we add. We are seeing varied results in the field and some of the wells are performing better than expected, some a little worse and as we get a feel for the proper areas to drill in, we're hoping to go and re-complete these idle wellbores, these San Andres wellbores in better areas of the field. So I would hope we would see the same results.

Phil Terry

I can add a little bit to that. Our technical group has realized that there is a definite structural position below which the wells make more fluid above that data point, they make more gas. And some of these things you discover as you start working through the field.

But we have certainly determined that the reservoir is a structurally bound reservoir in the top of it, it produces gas as you move off of that structure and down off the structure, you transition from gas to gas and oil and then further down you transition from gas to oil to water.

So what we're finding is that included in those 30 wells that we have producing are a number of wells that will make gas, but they also will make some oil and some will make oil and water, quite truthfully were not quite prepared for all of that as far as how this reservoir was going to react. So now we are in the process of going back to those wells that produced fluids and we're installing artificial lifts to dewater or to remove that fluid from the reservoir and we should see a correlating increase in gas as a result

We're seeing, as David mentioned, some of the areas are reacting even better and those areas are those that are above that structural band point that we identify, so those wells we're extremely pleased with. The ones down below we're still working on. The jury is still out as to what the ultimate gas production might be from those.

Operator

Our next question comes from David Heikkinen – Tudor Pickering & Co.

David Heikkinen – Tudor Pickering & Co.

Thinking through your oil recoveries and number of wells completed in the Fuhrman-Mascho of the San Andres, had 33 wells drilled in the second quarter and 21 completed, as you think about going forward how does that backlog of oil fields not completed play out and then as you add rigs, and then can you talk about number of wells completed per quarter as opposed to drilled.

David Ricks

When we went from one to two rigs it takes a little more labor, a little bit more getting organized for it. As we go forward with two rigs, if we stay two rigs this whole quarter, you would probably see the same number of wells drilled and the same number of wells completed. There's about a 17 to 20 day lag between when the well's drilled and when it's completed, so that accounts for some of that when you go from one rig to two.

But moving forward we'll probably see a little transition when we go to three rigs, but shortly thereafter we'll catch up and we'll be completing, if we were to stay at a steady pace with three rigs we'll be completing the same number as we're drilling with about that two and a half week lag.

David Heikkinen – Tudor Pickering & Co.

So what you're saying really, David, is that from spud to turning into the tanks you're probably averaging somewhere between 18 and 21 days? Yes, I'm just thinking through so first quarter you had 20 drilled and 13 completed, so you had 7 drilled but not completed, and then second quarter you drilled 33 but completed 21, so you had 12 that were drilled not completed, so just trying to walk through. Does that mean at the end of the second quarter you had 19 total that were drilled but not completed?

David Ricks

No.

David Heikkinen – Tudor Pickering & Co.

So how many wells did you complete then each quarter as you had a backlog maybe, not just the wells you drilled and completed, but total wells completed each quarter is what I'm trying to get to, wells maybe drilled in the previous quarter, previous year, whenever.

David Ricks

For the year, what we had completed at the end of the second quarter and what we had not completed would be all the wells drilled, which would be 53 wells for the year to this point, and then we had – I'm sorry what was it – 13 wells, is that what –

David Heikkinen – Tudor Pickering & Co.

In the first quarter and then 21 in the second.

David Ricks

Twenty-one in the second not completed?

David Heikkinen – Tudor Pickering & Co.

Completed is what you have in the press releases.

David Ricks

Okay, so that's 12 so we were at 53 wells drilled for the year and 12 wells not completed.

David Heikkinen – Tudor Pickering & Co.

Okay.

David Ricks

Does that clear it up?

David Heikkinen – Tudor Pickering & Co.

So looking forward then, as you go to 45 or so wells per quarter, how many do you complete in each quarter? Do you have a completion schedule that ties to that drilling schedule?

David Ricks

We will have these, like I say, we will drill 45 and over that 21-day period there may be 12 wells, we'll probably be about 12 wells behind at that point. We probably have at the end of the quarter we'll probably have about 12 wells waiting on completion.

David Heikkinen – Tudor Pickering & Co.

I just think about kind of 30, 35 wells or so completed each quarter and just kind of maintain a backlog or so of 12 per quarter.

David Ricks

That should be about right. It sounds like, David, in the neighborhood of 25% or 30% of wells drilled that will be still remaining to be completed.

David Heikkinen – Tudor Pickering & Co.

Exactly, it's kind of a continuous cycle, yes, so just as you ramp you might build a little bit of a bigger backlog.

David Ricks

Yes, we'll catch up with that too, but I think too, guys another thing that happens that we have to factor in here, is as we ramp-up here with going into this third rig and potentially even the fourth at some point in time that we will be adding service rigs, David, that will help with those issues as well.

David Heikkinen – Tudor Pickering & Co

Phil, you made a comment that you thinking 6,500, 6,700 barrels before downtime and kind of normal downtime is 10% to 15%, so that brackets your range of production for the quarter should be around 6,000 or so 6,100 barrels of oil a day, just assuming a normal 10% downtime.

Phil Terry

Yes, and we'll see a more than that, David, as a result of this second rig actually beginning to show up in our production. One of the things that I'll add to your previous question about the lag and completion versus drilling has to do with the service companies.

In this particular instance we have a strategic alliance with BJ Services and, as you know, BJ and all service providers in the Permian Basin have been tremendously adversely affected by the downturn in crude price. As a result of that they laid off probably half or more than half of their workforce.

As we ramp our activity back to previously existing points, we will communicate with BJ and all of the other people, our pipe providers, everyone to say here is our plan to give them enough lead time so they can have crews back in place to help us.

It'll take awhile, as David said, to affect that to get those people back out in the field and get an additional frac crew because, as we pointed out, our two rigs right now are turning out a well every three and half days. So we don't expect a contract crew to be quite that fast initially but on a four to five day schedule you have now increased your level of activity by 50%.

So we'll work with those service providers. It's going to take a little while but hopefully not terribly long for them to get back up to speed with some additional crews to support just what we're doing.

David Ricks

I can add one thing to that. I think in a way we're talking about it, David. I didn't realize it until we had this conversation. The 21 wells completed, we're just talking about the 33 wells that were drilled for the quarter. The wells that weren't completed in the prior quarter are the first wells that get completed in the second quarter.

So if we give a total number of wells completed, we would have to add what was hanging at the end of the first quarter what was left to complete to that 21. So I can kind of see from your question how it may have been a little misleading and we'll word it a little better in the future.

Operator

Our next question is coming from Jeff Hayden – Rodman & Renshaw

Jeff Hayden – Rodman & Renshaw

Just a quick follow up, wanted to make sure I heard that last comment right from one of David's questions. So Q3 production, I guess you guys are comfortable with kind of 6,100 barrels a day as far as production, did I hear that right?

Phil Terry

David came back and said he was saying about 61. I think we'll be higher than that, Jeff. With some downtime and everything included, as I said, we were at 6,000 we averaged 6,018 for the second quarter, which included that considerable downtime. Our production right now varies between 65 and 67, not accounting for downtime.

So I think we're probably going to be somewhere around averaging around 63 right at the current time without much influence from the second rig. We'll start to see that influence in July and August as we move forward.

Jeff Hayden – Rodman & Renshaw

Phil, correct me if I'm wrong but referencing the second rig, we only really saw results from about what two or three wells?

Phil Terry

Yes, the second rig spudded its first well May 15 and that well was completed, I believe if I'm correct, it was completed on either June 5 or June 9, so we saw only about three weeks of production from that well. And then there were three other wells that were drilled by that rig that were completed before the end of the second quarter.

So we only saw the benefits of about four wells for the second quarter. As we move through the third quarter conservatively modeling it so we would say that we would – each well – I'm sorry, each rig would generate seven wells in a month. So there would be 21 more wells added by that second rig or for all of the second half of the year.

And then if we add or when we bring on the third rig, you'll have similar numbers. I would say that particular rig, a contract rig will generate, I would use probably five days per well and somewhere around six wells per month that would be generated by a contract rig.

So it gives you an idea of kind of additions. Again if you go back to our rig activity versus production growth in '05 and '06 and '07 when you see us go from one to two rigs, those numbers are going to be fairly close as far as a correlation between the number of rigs employed and the kind of production you generate as a result.

Jeff Hayden – Rodman & Renshaw

And then you just answered one of my questions there with kind of the six rigs or excuse me, six wells per month on the third rig. I believe the number that was thrown out was about 560,000 – excuse me 460,000, I apologize, right now for the Fuhrman wells. Would it be similar to that with the contract rig?

Phil Terry

It should be, yes. It'll be a little bit higher but keep in mind that our – when we AFE we AFE as though we're hiring a rig and we – even though we have two contract rigs that are wholly owned subsidiary type of relationships, we still AFE and charge out those rig costs to the AFE.

David has found that the rig rates have decreased significantly in West Texas. In fact, the last time we had a contract rig running, I believe we were paying about $13,500 per day for that rig. And we're hearing now that rate might be around $9,000. So we feel like we're in a pretty good bargaining position and we'll go back to some of the contracts that we've used in the past and get them back out there hopefully right around the end of this month or the first of September.

David Ricks

Jeff, just to add to that as well relating to the cost with the differential between approximately 125 to 140 wells and then the added third rig probably bringing in between 15 or 20, and as I mentioned earlier we will come in before the end of the month with a revised CapEx and keeping in mind the additional activities as it relates refracs, you're probably looking at an additional $15 million to $20 million that will be added to CapEx in round numbers.

Jeff Hayden – Rodman & Renshaw

Just a quick clarification for Randy, when you talked your unit LOE expectation going forward you said kind of roughly flat, the current levels. Were you referring to current levels meaning second quarter or first half of the year?

Randy Broaddrick

The second quarter.

Operator

Our next question comes from Leo Mariani – RBC Capital Markets.

Leo Mariani – RBC Capital Markets

I just wanted to kind of clarify some things on the production side here. With respect to your [gain] Yates, you guys talked about having I think it was 1.8 million a day of production for your first month of operation.

And I know you've got currently 30 wells on line. If I understand you right, sounds like your first month in operation was June and I imagine a lot of those wells have come on. Are you guys still at 1.8 million a day in production in the Yates in 30 wells or is the number substantially different?

Phil Terry

David where are we at on that today?

David Ricks

Today we're about 1.6 but like Phil pointed out we're riding up some of these fluid wells and anticipate bringing it back up, but today was about 1.6.

Leo Mariani – RBC Capital Markets

I guess if I just use some simple math, say roughly 30 wells and if you guys have about 100% interest out there and I guess that implies somewhere around 70 Mcfs per day per well by factoring some royalties. I guess I thought that you guys were previously saying that these wells were going to come on you know a couple hundred Mcf a day. I know they have declined but it seems kind of like a lot lower number than you guys were previously thinking.

Phil Terry

One of the things that we have found is our model in the past was if we would see initial potentials of 300 to 400 Mcf per day and a decline of 40% for the first year and then tailing off on a straight line decline after that.

What we're finding now is that we're seeing a little higher decline initially. And we've been seeing some of our wells at the top of the structure actually have a little higher initial potential. Keeping in mind that part of that initial flow would have some treating gas in with it.

We treat with nitrogen and so some of that gas is coming back with the formation gas. What I'm saying is we're – our model is changing because of the fact that these wells are declining faster in the first 30 days and then leveling out faster.

So we're redoing our model as we speak to try to incorporate the numbers that we're seeing. Of those 30 wells that are producing some of them are below that critical structure and we're having them equipped with artificial lifts so we – we really can't use that information yet until we get that equipment in place.

But what we're seeing is that we are seeing some initial potentials going from 200 to in excess of 400, but the decline rates as opposed to going from 400 on a more or less straight line decline at 40% per year for the first year, they drop off a little quicker than that and then flatten out faster.

So we're redoing our model. I would say, however, for your modeling purposes I would use what you just said, just kind of ramp up based on what we're seeing now and in the first 30. Multiply that by 64 remaining wells, we certainly hope it will be better than that. We think it will but I think for your purposes it would probably be wise to model accordingly.

Leo Mariani – RBC Capital Markets

All right so we expect those declines to come up steeper – I mean are you talking about these wells coming on 200 to 400 Mcf a day and then dropping to 50 after a month or two or just can you quantify that a little better?

Phil Terry

Well there's a range. We've seen some of them that will come on at 300 to 400 that will drop to 100 to 150 fairly soon and then stay. We've got some wells that are higher on the structure that are leveling out north of a 100 MCF. Our own model basically was saying that eventually when you get to this decline, they're going to wind up at probably anywhere around 50 Mcfs somewhere around there. We're seeing that they come from this higher number, the initial potential number of around 400 Mcf.

We've got a couple of wells that are performing quite nicely and they have decreased to say about 150. Some of the others in the lower portion of the reservoir don't have as high an IP therefore and they don't decline quite as much, but the average for those might be 30 or 40 Mcf.

So again, it's hard for us to tell you exactly what the model well is going to be because it's changed a little bit from our original conception in that the wells in the top of the structure are acting considerably better than the wells below that critical data point. But we'll update that and obviously as we move forward we'll gladly provide that information to you as we go from month to month.

Leo Mariani – RBC Capital Markets

Kind of moving over to Fuhrman on the oil side of the equation here, you guys talked about your sort of current productions 6,500 to 6,700 barrels a day. I guess just curious as to what you see the kind of the progression sort of the oil piece of that and excluding the Yates, I mean it looks like your oil production was down somewhere around 7% sequentially in second quarter versus the first quarter.

Are these oil volumes going to grow? Sort of kind of a low single digit rate in the next couple of quarters sequentially or kind of what should we expect here now that you've got two rigs kind of fully running out in the third.

Phil Terry

You will see our production grow. As we talked about, we – most of that production decline that you saw – well, all of it; it was due to the fact that we went from five rigs to one rig. So you cannot stay up with the decline rate at one rig. With two rigs, you start to recover. At three rigs, you start to grow, so you'll see our production in quarter three, our production sales, I use those perhaps interchangeably, but you will see those numbers grow as we move forward.

For the end of the year, by the end of this year we anticipate that we'll see a positive growth number by the end of the year, as a result of two and three drilling rigs and perhaps more. We had estimated back in January that we could grow our production by somewhere around 15% this year. That number's probably going to wind up being somewhere around 10% based on what we're seeing.

Our reserve growth has potential of being somewhere in that 15% range, if everything continues and if it continues as anticipated with the three rigs and the PUDs that they prove as you drill. So that will give you a little bit of an idea, Leo, as to where we think we might be.

Operator

Our next question comes from Noel Parks – Ladenburg Thalmann.

Noel Parks – Ladenburg Thalmann & Co.

I guess I wanted to go back a bit to the Yates. Given what you've seen so far, and I realize it is early with the project out there, what's the range of options that you have on the table for proceeding with the play, if the decline is different or if you find a wider scatter in the variability of some of the wells out there?

And I mean, for example, would you be thinking about just concentrating on re-completing or drilling new Yates wells only in certain areas of the field, depending on where you find that structure or would it change your plans to, when you get to new drilling, pursue the Yates at a greater density instead of doing it more generally across the field?

Phil Terry

Noel, I'll address those points. You've correctly identified the process that we are working through and that is that we are hydrating as a result of our completion information that we're seeing. I don't want to belabor the point, but it is important to realize that we are dealing with a structurally bound reservoir and there is a substantial difference in performance as you move down the structure. What we have found is that the fluids that are produced from that reservoir have a direct effect on how much gas is produced, so we've got to remove that fluid and we're in the process of doing that.

As we continue to develop the field, you will see us concentrate on those areas above that 350 foot data point. And what we have found, and it's so far universally true is that the wells above that point produce only gas and they produce at a much higher rate than the wells below that point. So that steers us towards that structural position above that datum, and so you'll see us concentrate on re-completing only wells above that structural position.

As we start to contemplate drilling, we'll use the same model to determine where we drill. Now obviously, drilling is not nearly as economical as re-completing wells. We anticipate that it would cost us about $250,000 to drill and complete a new well and complete it as a slim-hole well. We're going to need a realized price of somewhere around 350 or so to make those economics work. Right now, our realized price is about 250, so we'll concentrate on re-completions.

So our costs to re-complete are somewhere around $115,000 and using those numbers and our realized prices and let's just take a 70 Mcf a day well. If you use that, it takes between two and two and a half years to pay out that re-completion cost. Those are not terribly attractive numbers, but it does allow us to build volume. It does allow us to provide some production growth, some cash growth and it fulfills our obligation to provide gas to that pipeline.

But what we will also emphasize from this point forward is working with our JV partner, which is a subsidiary of Aspen Pipeline. We will work with that JV partner, to secure acreage in areas where that structural position is at its most advantageous point. We already have some acreage. We've targeted a number of other tracts. We have an inside opportunity to pick up some additional acreage that is really critical to us. It's above the datum point and so you would see us drill with our JV partner at some point, when this price improves to accommodate and provide enough economics, good economics for us to spend that $250,000.

But we have a 50/50 JV; we'll explore that, and any drilling that you see us, which we right now don't contemplate until the latter part of this year if at all this year, but if we see some improvement and with our hedges in place and beginning in 2010 we can go out there and do some drilling.

At $4.00, we wind up at [audio gap] so we get about 70% of that, so we'd be about to 80 less our transportation. We can still generate fair numbers, but we really need to be a little bit bigger than that, in terms to justify drilling. But as we move forward you will see us do more drilling with our JV partner.

Noel Parks – Ladenburg Thalmann & Co.

Do you have a sense of the timeframe where you might know if this opportunity, I guess the one particularly you have in mind for picking up more acreage with the JV partner, you know when that might happen? Current quarter or at end of the year or –

Phil Terry

By the end of the year, we should have all of it papered and all of the contracts put together. We have a very aggressive group that are searching for JV opportunities and we're currently looking at a large acreage block in Gaines County, further to the north.

We have other opportunities within our area of operations, in and around Fuhrman-Mascho. We have some offers outstanding now to pick up some additional acreage both within the JV and within our area of Fuhrman-Mascho asset base. So we're very encouraged about where the project is.

There's still tremendous growth opportunity. We've got to be cognizant of where we are structurally. We will target our activity to be above that structural point and we'll continue to re-complete wells that are above that structural point. We'll also look for JV acreage that conforms with our structural idea and we'll continue to add to our acreage base and start to develop that acreage base. I would say it's going to be after the first of the year.

Operator

Our next question comes from Mark Lear – Sidoti & Company

Mark Lear – Sidoti & Company

In terms of 10 acre in-field locations, do you have a good handle on how many you have in the high-graded Grayburg and south Fuhrman-Mascho areas and then also do you have an idea of how many of your current idle, temporarily abandoned wellbores are suitable for Yates re-completions? Then also on the Yates, is your current acreage exclusive of the JV or do they get a 50% interest those wells you're re-completing on your acreage or is that all for Arena?

Tim Rochford

David, do you want to catch the 10-acre question?

David Ricks

Tim, I don't really have an answer for that. We acquired some acreage that we talked about in our last quarterly meeting that's right next to that and it was undeveloped. We just started drilling there and we may see the same type well, I mean it may be an extension of the Fairway, but I don't believe our reservoir group has put together a number on that 10 acres. Phil, do you know if that's correct?

Phil Terry

No. On that specific acreage block, no. But, Mark, just to give you a more general answer to your question, we have been hydrating our PUDs to drill only the more attractive PUDs at low prices. And our mid-year review, it's not complete, but it's at a very good point where we can speak somewhat comfortably. As of right now as of today, we've identified about 475 wells that have potential to recover north of 40,000 net barrels and that includes the 40s, 50s and 60s.

Kind of breaking that down, most of the wells are going to fall in that 40,000 range, which is about our average. We feel like we have probably between 75 and 100 remaining to drill in that sweet spot of 60,000 net barrels and greater, and then 150 or so plus or minus in the 50,000 range. So that kind of tells you where we are.

That 475, the actual number I think is 474, but that gives you an idea of the fact that we could drill for three to four years with three rigs running and still be in the high grade, the higher reserve categories. As the price of oil increases and goes north, all of our PUDs, and right now we don't have anything on our books as a PUD below 30,000 barrels, but at that, at $75 net to us, which would be about $79 NYMEX, at $75 net realized prices, all of our PUDs generate a nice rate of return being approximately 100%. So we'll continue to add as we move forward, but right now we're looking just at 40s, 50s and 60s, 60 MBO per well.

Tim Rochford

Let me add to that, if I may, Mark, and correct me if I'm wrong, Phil, but the number that Phil is making reference to, Mark, the 474 is truly in a category of what we feel at this time would be considered a PUD, whereas, in a broader picture, you're looking at an opportunity that's far greater than that as it relates to potential locations.

Mark Lear – Sidoti & Company

And then I guess looking at the other questions regarding the Yates, I just wanted to get an idea the production you're reporting from your current acreage, does that go into the JV or is that just Arena?

Tim Rochford

Our current footprint, Phil, is exclusive to Arena. I know that we have boundaries and we have an AMI that's been documented, but maybe you can give a little more detail or color on that.

Phil Terry

Right. Mark, all of the gas that we're talking about is 100% Arena. We have done nothing yet with the JV.

Operator

Our next question comes from John Lane – Lane Capital Markets.

John Lane – Lane Capital Markets

Most of the questions I had have been answered. I was more or less going to ask something more about the Yates and obviously the amount of time it took to get this all on stream and the prices coming down, it wasn't probably as advantageous as normal. But it appears that you've got a tiger there and I'm glad that you stuck with that. It appears that it's really going to have some good potential.

But to the questions that were asked today, too, as you know, we've been doing business for a long time, and whatever apprehension there is out there, you solve it every quarter by doing the exact right management choices. You weigh everything and you're more concerned about the long-term than you are the short and you're so quick on making changes in judgment and changes in decisions, and going from the high amount of wells slot down to one and then inching your way back up.

I mean it's the way you've run your business forever and there's no reason to think you're going to change it, so again kudos to a great quarter in a difficult time. You're putting a lot of the other competition to sleep here by doing what you're doing. I think that's fantastic.

Tim Rochford

Well, appreciate that, John, thanks for that. And, yes, we feel very positive about how things are starting to stack up again here and keep in mind, to just kind of add to all this is that we haven't talked about, at least on today's call, is that we're sitting there with some very nice resources, cash on hand, great credit facility and we are looking for opportunities beyond the immediate operational area that we're in. So we're looking for that next core project as well, so we're feeling pretty bullish and thanks for all the comments.

John Lane – Lane Capital Markets

Well, so many companies and banks are getting so strict again on the assets, so I think there's probably some opportunities out there that, if they're not here yet, they're going to be here pretty quick and I'm sure you'll make the right choices. And thank you again for the great performance.

Operator

Our next question comes from Irene Haas – Canaccord Adams.

Irene Haas – Canaccord Adams

Quick question on Yates, how much volume have you bought? I don't believe you have a whole lot. And then compared to your internal reserves, it looks like the Yates is structurally constrained now, the better parts of it. Has that number come down in your own calculation? And lastly maybe a little more color on the water flood project. Is it going to add much incremental volume in 2010?

Phil Terry

I'm making my notes, Irene, so I can answer your question. The Yates, we have not booked a great deal of Yates. I think if my memory is correct, we've booked 1,160 acre units and so we haven't booked a tremendous amount of reserves there. Obviously the change in structural position has – I'm sorry, the findings that we're seeing on this structural position have changed our opinions on some of the reserve potential.

It's perhaps a little too early to downgrade the positions below that 350 interval until we see what kind of production we get, when we get the wells de-watered or get the fluid pumped off of them. But obviously we are certainly mindful of the fact that the better position structurally seems to translate directly to better performance. And so at year-end, when we get our reserves put together, we will certainly be mindful of everything above that 350-foot interval and be very cautious and conservative about everything below that.

We feel, at this point in time, that we still have a nice position. We've got some locations that are going to require drilling. We still have a number of idle well bores that are available to us. We're in the process, David and his group, are in the process of continuing to test those wells to assure that they have mechanical integrity. We may eventually see this field being drilled from instead of 160 acres it may ultimately go to 40 acres in order to drain the reserves.

And we're already thinking, internally, that we're probably going to have to be on an 80-acre spacing as opposed to 160. Now, that reserve potential could translate to, say, 200 million on a per 80-acre basis, we're not really sure, but it would be roughly equivalent to the 160 acre, but we'd have to drill two wells, in order to get it.

So we're mindful of that. We're going to continue to fine tune our reserve picture. We will be very mindful of where we are structurally and we'll gear our efforts with the JV towards only those areas that have that attractive structural position.

And what was the third part of your question?

Irene Haas – Canaccord Adams

We're done with Yates. Just a little more color on your water flood project. It was something to implement next year?

Phil Terry

We won't see any direct results on water flooding until 2010 and then the water flooding results will be fairly minimal. As David said, we are in the process of finishing up our engineering and geological information and we're also doing land work on our Fuhrman-Mascho water flooding. We have retained a national engineering consulting group, an engineering group to come in and help us with this process by finishing up a water flood report.

We are in the process of coring wells on the Fuhrman-Mascho. We're going to core the Yates, the Grayburg and the San Andres and we'll do very detailed core analyses on those three intervals, which will allow us to gain much needed knowledge and information about what kind of flood performance we'll see. We'll be able to verify it based on those full core analyses exactly how this reservoir reacts when you put water through it.

So we're moving forward along those lines. As I said, this process or the review and study is to take place beginning immediately. We'll also use that same national firm to look at East Hobbs. We have discovered there we need to change our water flood pattern slightly. We'll verify exactly what the best scenario is for changing that water flood pattern. And we'll see results there perhaps a little sooner in 2010 but not until then.

Operator

Our next question comes from Ronald Mills – Johnson Rice & Co.

Ronald Mills – Johnson Rice & Co

Just one clarification, 140 wells that you now plan on drilling, I'm assuming – is that still just from the two rig program and then the third rig would be additive to that number?

Phil Terry

That's right.

Ronald Mills – Johnson Rice & Co

I think, Tim, you mentioned potentially this year kind of plus or minus 10% growth. I think Phil mentioned that as well or you all mentioned that in the last conference call as well, which would suggest a pretty significant ramp in the fourth quarter production. Am I looking at that right to be able to get to a 10% year-over-year growth?

Tim Rochford

Yes, I think that's exactly what we're talking about and I would suggest this, Ron that – not to keep beating a dead horse but again that second rig although we talk about that rig a lot coming on stream, it really didn't have that much effect in the second quarter as Phil detailed here a moment ago, there were maybe three or four wells that we saw as a result from.

So with that on full stream now and the fact that we're bringing that third rig in and the Yates program, even though we're still going through a pretty good learning curve on that Yates on the production side, we still feel pretty good about that 10% plus number. You know time will tell but we're still feeling pretty good about that. The reservoir picture I know we're feeling very confident about 15% plus on that as well.

And Phil if you have any further additional on that, please.

Phil Terry

No, you addressed it properly.

Operator

Our next question is coming from Mike Breard – Hodges Capital.

Mike Breard – Hodges Capital

Could you give us a little more color of the refrac program in San Andres? What maybe an average refrac would cost and how much additional production you might get and how many of those or how long it takes to do one.

Tim Rochford

You bet, Mike, and as you probably know we had a very aggressive refrac program taking place for years, not only added to the production stream but also to the reserve stream. Then of course, we eliminated that as we start this year with lower commodity prices. But now with the better prices, our guys have been really cherry picking the candidates. So maybe Phil or David could add some color on how many we anticipate and get some ideas on maybe production or reserve as a result of that.

Phil Terry

Mike, I'll talk about the number that we have and then David can give you some information on our current estimate for what it will cost and the results, but we started the identification process of refracs by identifying first of all the wells on leases that we own 100% of the working interest.

The reason we did that is given the time constraints involved in gaining partner approval, sometimes that approval process can result in serious lags in actual work. So we've identified 50 wells at our first pass of refrac evaluations.

We've identified 50 wells that are on leases that we own 100% of the work interest that have potential on the downside of adding 8,000 barrels of reserves and on the top side 22,000 barrels. Obviously we'll hydrate and stay with the better properties, the better opportunities and the better refrac candidates.

In the past we have been very successful with our refrac. We have seen production increases of as much as 35 and 40 barrels a day from the top side to an average to 15 to 20 barrels a day. They pay out fairly quickly. They perform in a little different manner in that they evacuate that the new frac system fairly soon so you get your production back quickly. So it is an acceleration process. And we've identified 50.

David can probably give you a better idea about what our costs estimate might be. We've not done a frac in quite some time or a refrac, but I know from our current fracs, our light [prop] fracs are now running about $60,000. So I don't know what else we would have to do. David can add a little more color to that.

David Ricks

That's basically it. We do a light [prop] frac similar to what we do on our new completions. Actually we're running about 56,000 on average right now. And for the rig time and other work associated to get it done, it'll probably be AFE'd at about 100,000 to do these refracs. They're done and on line in three days.

Tim Rochford

And it's about 20% to 30% lower than we were spending, I know, say, a year ago, David.

David Ricks

Right. We have seen them I believe at about 125.

Tim Rochford

Yes.

Mike Breard – Hodges Capital

So you could put on – theoretically you could put on 60 wells at actually 20 barrels a day but I assume that 20 would have a decline to it. I mean you're not talking about 1,000 barrels a day.

Tim Rochford

No as I said, they produce in a little mechanism in that essentially what we're doing is just extending an existing crack. So you're going to drain that new frac distance and once you drain it you essentially fall back to where you were before, maybe a little slight increase but the beauty of the refracs is it certainly accelerates recovery and that's the reason we didn't do a lot of them when the price was down around $30 because we felt like we'd just be giving away those reserves.

But we've got 50 right now. I don't know if we'll be able to get 50 done. That's pretty ambitious given the time that we have left this year but, again, as I spoke earlier about gearing the infrastructure of the – we kind of got to go back to BJ to say all right now we're going to have three drilling rigs running plus we're going to refrac and how soon can you get the crews needed to service that work?

Mike Breard – Hodges Capital

Then a quick question on the Yates field, when you hydrate that is it too early to say roughly what percentage of your acreage would be in better of the structure and what percentage not?

Phil Terry

Mike, it is a little early for us to do that. Pat McConn our VP of Geology and his staff are putting some information together now on that. Obviously it is kind of a dynamic situation as we complete these wells. But we're in the process of just making that determination. We're just not finished with it.

Mike Breard – Hodges Capital

And one last questions, with the oil price going up, I assume it's a little harder to make acquisitions but you have some prospects in mind that you're actually negotiating with at this point?

Phil Terry

We do. And we continue to add bits and pieces to our Fuhrman-Mascho puzzle, and I say that, it's not really a puzzle now but the asset base that we established as it continues to grow we are able to make some deals. And we've been able to secure some leases in the past nine months that we could not get bought before, that we were not able to buy.

We have offers outstanding now on two or three smaller deals. We've also identified some potential targets that we certainly are going to continue to work. I feel like and this is just my personal opinion, we're beginning to see a little bit of movement in the markets out there.

We're beginning to see perhaps some deals being made, some properties being listed for sale and we're positioned very nicely to pursue those. We've been very selective just as we always have been on not only what we look at but what we buy.

We want to buy things that have a good history, that have a future in terms of PDP and have potential for primary drilling, secondary recovery and tertiary. And we think there is some legacy out past that's in the Permian Basin that are similar to Fuhrman-Mascho.

We've broadened our circle. We've got approximately $70 million in cash reserve. We've got a fully available credit facility and zero debt. And so we will continue to diligently look for acquisitions that match our model and hopefully we'll be able to find one of those.

Tim Rochford

Mike, let me also add to that for you and the rest of the listeners, that just because you haven't seen a significant acquisition take place in the last six, seven, eight months, don't think for a moment that we haven't been breathing heavily over opportunities.

The point that Phil made, and was made earlier and to just to review again, is that we're going to be very picky. We're going to be very selective. We are continuing to add in the blanks as it relates to our existing core area. But looking beyond that as mentioned, to potentially a new core area is something that we're waiting patiently for. And we are seeing potential opportunities.

And the fact is that we haven't had to go out and pull the trigger because we've been able to continue to show that this company can grow with its asset base that we have in place now. So but I just wanted to remind everybody just the fact that we haven't closed on something or pulled the trigger yet, doesn't mean that we're not aggressively looking for that opportunity. We certainly are.

Mike Breard – Hodges Capital

You could do $100 million deal obviously if the terms were good. I mean you don't – you're looking at a wide range of prospects obviously.

Tim Rochford

Yes. No question, Mike. We could do that more if the right project comes along.

Operator

Our next question comes from David Heikkinen – Tudor Pickering & Co.

David Heikkinen – Tudor Pickering & Co.

So you started talking about EURs and just kind of curious as you think about the 5 and 10 and 20 and 40-acre spacing. And you talk about EURs and then across spacing, how you're seeing recoveries.

Phil Terry

David, we – on 40 acres, our average and what we've always talked about is 40,000 net barrels in the – 40,000 net BOE in the overall area, I mean for the majority of the acreage. I apologize for stammering a little bit. But that generally across the field is still a number that we feel confident with. We see that Grayburg Fairway, you know some of the 40-acre locations there would produce 80,000 to 100,000 barrels.

We have engineered those more conservatively. We basically are saying that we would recover 60,000 to 80,000 in those areas. We, for the most part across the field we don't see degradation as we go from 40s to 20s to 10s.

However in some areas, particularly in that really thick Grayburg area, we do see a slight degradation because of the Grayburg itself. A hundred feet of Grayburg acts more like a conventional sandstone reservoir as opposed to a carbonate and so we anticipate that there will be a slight degradation in EURs in that thick Fairway. But we've always tried to account for that instead of engineering them at 80,000 to 100,000 barrels. Our average in there has been about 60,000.

Now we've see the 10s in the other areas basically match up with the 20s and the 40s. We have not drilled a five, but we will as we mentioned earlier. We'll drill four five-acre locations before the end of this year. And we hope to get on the first two of those here fairly soon. So we'll have some time to evaluate them prior to year end.

But I really don't know. Range did a lot of work on fives and the information that they published was always very favorable. We quite truthfully, however, we're not quite sure. We have not booked any five-acre locations. We don't have any five-acre PUDs. But we want to drill and test that theory and we will do so before the end of this year.

David Heikkinen – Tudor Pickering & Co.

I'm trying to understand then how when you think about your economics of kind of $75 oil works at 40,000 barrel wells on average, how that links in to your hedging decisions to unwind hedges and then re-hedge at $50 floors where you're not going to have anywhere near that protection on a rate of return. And even $65 for next year. I mean is hedging not a link to economics? Or is it just purely a cash flow gain?

Tim Rochford

I think it's both. Phil, you may some point on that, but I think it's both, David. I think that the insurance on the cash flow is important to us. But I think the economics obviously play an important part.

David Heikkinen – Tudor Pickering & Co.

So a $50 oil drilling wells today gets what type of rate of return on 40,000 barrels of oil equivalent?

Tim Rochford

Yes, Phil, do you have those numbers handy? He's getting the graph.

Phil Terry

Yes, you said at $50 oil?

David Heikkinen – Tudor Pickering & Co.

Yes, that's where your floors are now.

Phil Terry

About 75% on a 40,000 barrel well.

David Heikkinen – Tudor Pickering & Co.

So from $75 oil down to $50, you only lose 25%. I'm trying to understand how the rates of return are working. I guess you're just getting higher IPs also, looking at the declines.

So then looking at where your production guidance is, you talked about big ramp into the fourth quarter; just struggling to get to a 10% growth rate for this year. Is that a year-over-year exit rate? Or is that your average rate?

Phil Terry

You'll be looking at an exit rate that winds up in that range. And I think overall, David, that we'll still have an opportunity to be around that 10% growth rate for the year-over-year numbers.

David Heikkinen – Tudor Pickering & Co.

Okay. So I'm just – I guess I'm stuck a little bit on how you get that big of a sequential growth with where you are currently. How many wells have you drilled with that second rig because you're at 6,500 or 6,700 barrels a day now and you think 61, 62, let's say even only 5% downtime for the third quarter. And you start having to average well above 8,000 barrels of oil equivalent in the fourth. I mean, that's a lot of wells to bring in.

Phil Terry

David, I tell you what we'll do. Rather than continue to burn time. If you'll give me a call, I'll be happy to go through our numbers with you. And go through that. And kind of show you where our thinking is...

Operator

Our next question comes from Richard Tullis – Capital One Southcoast.

Richard Tullis – Capital One Southcoast.

Hey, good afternoon. Could you review again the parameters for bringing on that fourth rig in Fuhrman-Mascho?

Tim Rochford

Yes, Richard. I think what we meant by the willingness to add a fourth rig is if we continue to see stability along with an increase as it relates to the price of oil and that and coupled with the fact that we'll layer on some additional hedging, that you shouldn't be surprised if we do add yet a fourth rig between now and year end. I'm not saying that we're going to, but that's something we've talked about. And that's something that we think as we get a handle here and particularly the economics show well, you can expect it.

Richard Tullis – Capital One Southcoast

Is the current price environment $70 or $75 oil with your $4.00 or so differential adequate to add a fourth rig?

Tim Rochford

Yes.

Richard Tullis – Capital One Southcoast

Okay. I hate to go back to the Fuhrman-Mascho. EUR is a gain. I just had a couple more questions there. Out of all the wells you've drilled so far, how many fall into the category of 50,000 barrels or above?

Tim Rochford

You mean the wells that we've drilled since the beginning of the project?

Richard Tullis – Capital One Southcoast

Yes.

Tim Rochford

Well out of 540 or 550 wells, Phil, what would you say the percentage would be? Probably not an easy –

Phil Terry

Yes. It is a rather difficult number to come up with off the top of my head. We're probably looking at somewhere around 75 wells so far. I think that's probably a pretty good number, Richard.

Richard Tullis – Capital One Southcoast

That's fine.

Phil Terry

I'll be glad to quantify that for you in better detail.

Richard Tullis – Capital One Southcoast

No, that's fine. And I know you had mentioned about 225 to 250 remaining locations at 50,000 barrels or above, or at least the way you see it right now. What's the spacing you're assuming on those?

Phil Terry

Ten-acre.

Richard Tullis – Capital One Southcoast

And I guess at this point, you're not positive on what the five acres of down spacing would do to the ultimate recovery.

Phil Terry

No. we're not. We're hopeful that we do not see a degradation. But at this point in time, we're proceeding very conservatively to wait until we get the results. We will drill those four wells in that Grayburg "sweet spot" Fairway, if you will, to get an idea about what kind of performance we'll get and if there is interaction between the existing wells.

Richard Tullis – Capital One Southcoast

Okay.

Phil Terry

We'll know before the end of the year.

Operator

Our last question comes from Jeff Hayden – Rodman & Renshaw.

Jeff Hayden – Rodman & Renshaw

Hey guys. My questions are actually kind of along the lines of David's so, Phil, if you don't mind, I'll try to catch up to you this afternoon as well.

Phil Terry

Be happy to.

Operator.

Thank you. There are no further questions. I'd like to hand the floor back over to management for closing comments.

Tim Rochford

Thank you, Operator. And we'd like to thank everybody for taking the time, and the continued interest and support of the company is well appreciated. And we know that it's a busy time so taking the time today for us is something we appreciate very much.

You all have a good day. And further questions can be followed up with either Bill Parsons, our VP of Investor Relations or of course, as Phil mentioned, with reference to Jeff or David or anyone else that have any specific questions, feel free to give management a call. Thank you and have a good day.

Operator

Thank you. This concludes today's teleconference. You may disconnect your lines at this time. Thank you for your participation.

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