Whiting Petroleum Corp. Q2 2008 Earnings Call Transcript

| About: Whiting Petroleum (WLL)

Whiting Petroleum Corp. (NYSE:WLL)

Q2 2008 Earnings Call

July 31, 2008 11:00 am ET

Executives

John Kelso - Director of IR

Jim Volker - President and CEO

Mike Stevens - CFO

Doug Lang - VP of Acquisitions and Reservoir Engineering

Mark Williams - Vice President of Exploration

Dave Seery - VP of Land

Chuck LaCouture - VP of Marketing

Analysts

Larry Busnardo - Tristone Capital

Eric Hagen - Merrill Lynch

Scott Hanold - RBC Capital Markets

Nicholas Pope - JPMorgan

Jack Aydin - KeyBanc Capital Markets

Eric Kalamaras - Wachovia Capital Markets

Wayne Andrews - Raymond James

Dave Tameron - Wachovia

Dave Kistler - Simmons and Company

Chris Gold - Lehman Brothers

Operator

Good day, ladies and gentlemen, and welcome to the Second Quarter 2008 Whiting Petroleum Corporation Earnings Call. My name is Akeya and I will be your operator for today. At this time all participants are in a listen-only mode. We will conduct a question-and-answer session towards the end of the conference. (Operator Instructions).

I'd now like to turn the presentation over to your host for today's call Mr. John Kelso, Director of Investor Relations. Please proceed, sir.

John Kelso

Good morning and welcome to Whiting Petroleum Corporation's second quarter 2008 earnings conference call. Thanks for joining us. On the call for Whiting this morning is Jim Volker, our President and CEO; Mike Stevens, our CFO; Jim Brown, Senior Vice President; Doug Lang, VP of Acquisitions and Reservoir Engineering; Mark Williams, Vice President of Exploration; Dave Seery, VP of Land; and Bruce DeBoer, Vice President, General Counsel and Secretary; Rick Ross, VP of Operations and Chuck LaCouture, VP of Marketing. So, we got a big repo here today.

During this call, we will review our results and the second quarter of 2008 and then discuss the outlook for the remainder of the year. This conference call is being recorded and will be available for replay approximately one hour after its completion. Both the conference call with an accompanying slide presentation and our second quarter 2008 earnings release can be found on our website, at www.whiting.com. To access the call and webcast, please click on the Investor Relations box on the menu, and then click on the webcast link.

Please be advised that our following remarks, including answers to your questions, include statements that we believe to be forward-looking statements within the meaning of the Private Securities Litigation Reform Act. These forward-looking statements are subject to risks and uncertainties that could cause actual results to be materially different from those currently anticipated. Those risks include, among others, matters that we have described in our earnings release, as well as in our filings with the Securities and Exchange Commission, including our Form 10-K for the year ended December 31, 2007. We disclaim any obligation to update these forward-looking statements.

In this call, we use the terms probable and possible reserves, which are unproved reserves that we do not include in our SEC filings. Please refer to the news release or our website slides for more information on probable and possible reserves.

During this call, we will also make references to the discretionary cash flow, which is a non-GAAP financial measure. A reconciliation of this non-GAAP measure to the applicable GAAP measure can be found in our earnings release and on our webcast slides.

With that, I'd like to turn the call over to Jim Volker.

Jim Volker

Thank you, John. Good morning, and welcome everyone to Whiting's second quarter 2008 conference call. We are extremely pleased with our second quarter results and even more importantly the outlook for the second half of 2008. We look forward to discussing the results and our plans with you and we will try to answer any questions you may have following the presentation. We are going to try to move smartly through our presentation here this morning so we can get to your questions.

All of our production growth in the first half of 2008 was organic, our net production from the Middle Bakken formation more than doubled from March to June to a rate of more than 8,400 barrels of oil equivalent per day. Our net production from Boies Ranch in the Piceance Basin ramped up to more than six million cubic feet of gas a day in net to Whiting from only about 740,000 in the month of March. In addition, combined production from our two CO2 projects increased 3% to 11,700 BOEs a day in June from 11,400 BOEs a day in March.

We expect the momentum established in the second quarter to continue in to the second half of the year and on in to 2009. We've raised our production guidance for 2008 to a range of 16.5 million BOEs to 16.7 million BOEs. The midpoint of that range would represent a 12.9% increase over our 2007 production of 14.7 million BOEs.

Total production in the second quarter of 2008, reached a record 4.02 million BOEs of which 70% was crude oil and 30% was natural gas. This second quarter 2008 production total equates to a daily average production rate of 44,200 BOEs and represents a 7.5% increase over the first quarter of 2008 daily average of 41,120 BOEs.

June 2008, average production of 47,100 BOEs per day represents a 12.7% increase from the March 2008 average daily rate of 41,800. The primary contributor to our production increase in the second quarter came from new wells drilled in the Middle Bakken formation in the Sanish and Parshall fields in Mountrail County, North Dakota.

Since our last earnings release we completed six significant single-lateral Bakken oil and gas producers in the Sanish field. Initial production rates from these six wells range from 1,719 BOEs per day to 3,245 BOEs per day with an average of 2,550 BOEs per day per well. We hold an average working interest of 81% and an average net revenue interest of 66% in the six new Bakken producers.

We plan to test the somewhat deeper three Forks formation in the Sanish field late in the third quarter of 2008. In the partial field we participated in 11 new Bakken wells during the second quarter. The new producers brought our net average production from Parshall to 5,000 BOEs per day in June up from approximately 3,000 BOEs per day in March.

Moving out of the Williston Basin and down into the Piceance at Boies Ranch prospect in Rio Blanco County, Colorado, 13 wells were producing at an average combined net rate to Whiting of 6.1 million cubic feet of gas per day in June 2008.

In addition two wells are being drilled and eight wells are being completed or waiting on completion. Of these eight wells we expect five to be completed and producing into the sales line by the end of August 2008 and the remaining three by the end of September. By year end 2008 we expect to have an estimated 24 wells, oil and gas at Boies Ranch.

We recently completed the three mile, 10-inch diameter pipeline that has a total daily capacity of approximately 80 million a day at Boies Ranch. Start-up of pipeline facilities occurred on May 13th, 2008. The new pipeline connects to a enterprise supply trunk line feeding an enterprise three quarters of a Bcf per day treating and processing facility connected to the Rockies Express pipeline. That gives us multiple interstate and intrastate markets.

We are also pleased with the performance of our two CO2 projects. Combined production from the Postle and North Ward Estes fields has risen from 10,900 BOEs per day in December of 2007 to 11,400 BOEs per day in March 2008 and again to 11,700 BOEs per day in June 2008. So, as you can see both those floods are responding, obviously Postle is further along the North Ward Estes, but we expect to see continued response from those especially as we approach year end and into the first quarter of next year.

Turning to the Uinta Basin, we recently began drilling our first well in the Flat Rock field in Uinta County, Utah. The Ute Tribal 1-30-14-20 in which Whiting holds a 100% working interest and is schedule to test the Entrada sandstone at a depth of approximately 11,500 feet. We expect to drill four additional 100% owned Entrada wells by year end 2008. 49 square miles of 3D seismic in this area support the current plan of up to 59 additional wells to more fully develop the Entrada and other formations on the 22,000 and 29 acre gross 11,533 net acres we hold Flat Rock.

We have increased our exploration and development budget by $85 million to $850 million for 2008. The increase is due to additional exploration and development activities across all of the company's regions. Company wide, we are currently running 14 operated drilling rigs, five in the Sanish field, two at our Boies Ranch prospect, two in the Permian Basin, two in the Postle field and one in North Ward Estes field, the Gulf Coast region and the Uinta Basin. So, again that’s one each at North Ward Estes, the Gulf Coast and the Uinta.

We are also participating in the drilling of 10 non-op wells, most of these are in the Parshall Field, Middle Bakken oil play. In addition, we have 34 operative work over rigs in service, 13 of those are in the North Ward Estes field and 5 are at Postle.

So, I'd like to turn it over now to Mike Stevens our CFO to discuss some of our key financial highlights.

Mike Stevens

Thanks, Jim. In the second quarter of 2008, we set company records in net income per share, discretionary cash flow and total revenues just as we did in the first quarter of 2008. Our net income the second quarter was $80.4 million or $1.90 per basic and diluted share on total revenues of $345.8 million.

As a result of rising commodity prices, we recognize the non-cash after tax unrealized loss on the commodity derivative contracts at $12.9 million or $0.30 per share in the second quarter of 2008.

Discretionary cash flow in the second quarter 2008 totaled $216.3 million more than double the $100.2 million reported for the same period in 2007. The increases in second quarter 2008 net income discretionary cash flow, compared to the second quarter 2007 were primarily the result of a 67% increase in our realized oil price, a 44% increase in our net realized gas price and an 8% increase in our totally equivalent production.

During the second quarter, our company-wide basis differential for crude oil compared to NYMEX was $10.72 per barrel, compared to $8.38 per barrel in the first quarter of 2008. We expect our oil price differential to remain between $10 and $11 in the second half of 2008.

During the second quarter, our company-wide basis differential for natural gas compared to NYMEX was $0.92 per Mcf compared to $0.60 per Mcf in the second quarter of 2007. We expect our gas price differential to be in the range of $0.50 to $1 in the second half of 2008.

We have received questions regarding our exposure regarding crude oil sales to SemCrude. Whiting's exposure is estimated at $400,000. We understand that SemCrude has petitioned the court to allow for the payment of outstanding amounts owed to producers in exchange for a commitment to continue to esquire crude under existing contracts. As a result we expect our losses to be minimal or none.

Turning to our guidance for the third quarter and full year 2008. Our production guidance is a midpoint range of 4.35 million barrels of oil equivalent. Our production guidance for the full year as a midpoint is 16.6 million BOEs, which as Jim mentioned will represent an increase of 12.9% over the 14.7 million BOEs reported for 2007. The production gains in 2008 are expected to come primarily from our drilling programs in the Bakken and Piceance Basin as well as our two CO2 projects.

I will turn the call back over to Jim Volker for some additional comments on our operational activity.

Jim Volker

Thank you, Mike. A quick review of our drilling budget before we move on to the slides. If you are taking notes, first I will review the number of gross wells per region in total for the year that secludes those that have already been drilled of course.

In the Gulf Coast its 13 wells; in the Mid Continent its 73 wells; and those are broken up essentially 36 in Michigan, and 37 at Postle. In the Rockies it's a total of a 197 wells and I'll kind of slowdown here and provide a summarized list and somewhat of a breakout within the Rockies for you.

So about 22 wells in the Piceance. There is about 32 wells elsewhere in the Rockies, 66 wells in total at Parshall, 24 at Sanish that would be non-op, 36 at Sanish that would be operated and 17 elsewhere in the Rockies were a total of 197 gross wells.

In the Permian 20 wells and those would be, and this is aside from North Ward Estes of course, so that’s a 20 gross count outside of North Ward Estes for a total of about 303 gross wells.

Breaking that down dollar wise for you by region, It's about $33 million in the Gulf Coast, $107 million in the mid continent and of that $107 million, $80 million is directed at Postle and about $25.5 million in Michigan.

In the Rockies the grand total is $483 million. Broken out approximately as follows; about $53 million in the Piceance, $66.5 million elsewhere in the Central Rockies, about $81 million at Parshall, $81.5 to be more exact, $27 million at Sanish non-op, about $219 million at Sanish operated, all that $219.9 million, and then the Northern Rockies elsewhere about $35 million for a total again of $483 million.

In the Permian the total is $222 million of which $178 million is directed towards the North Ward Estes CO2 project, and about $45 million elsewhere. So, again that will get you to just under $850 million. I hope that is helpful to you.

With that, I'd like to now review the slides on our webcast to provide some color on our primary operating areas.

First of all, I'd like to direct your attention and with that direction complement our Northern Rockies and Bakken team for everything that they are accomplishing up there. Including what you see here on the front cover of our slides, which is a brand new plant, with initially about a 3 million a day capacity of gas here at our Robinson Lake gas plant rising to a little over 30 million a day we believe by the end of the year. What you see there on the right hand of the slide is the plant itself under construction and also on the left hand side the line that just before it was put in the ground, that's our residue and NGL line going north to our market.

Moving over to the next, slide 2. I'd just like to again remind you that we're going to making a number of forward-looking statements, so please review carefully the forward-looking statement disclosure reserve information and non-GAAP measures shown here on page one, and give particular attention to the risk factors cited in the reference documents.

Moving to page 2, as you can tell here our market cap is based upon $91.73 a share for footnote one to the $3.9 billion mark, the long-term debt of $1.1 billion for footnote two is composed of $500 million of bank debt and $620 million of senior sub-notes both as of June 30, 2008. The reserves are still based upon year end 2007 at $250.8 million BOEs, and production is updated to June 2008 of 47,100 BOEs a day.

On pages 3 and 4, moving quickly there, there is your $1.90 per share in the second quarter up from $1.47 in the first quarter and of course up smartly from the $0.72 in the second quarter of 2007. Discretionary cash flow up also to $216.3 million or as most of you calculate it I believe about $5.10 a share.

Moving on to our map of operations, nothing changed there as everything here is as of December 31, 2007. There is your 250.8 million BOEs with PV10 value on those proved reserves only of $5.8 billion as of December 31, 2007.

Moving to page 6, concentrating quickly on items 3A and B. Certainly, we think item B here is what's responsible for our significant growth in production. Year-over-year and quarter-over-quarter and that is production coming from the Williston and the Piceance and in those two areas we certainly see several years of production growth ahead of us. And of course the moderate risk organic growth from Postle and North Ward Estes as those two CO2 projects continue to perform as scheduled and as ingenuity.

In addition there is exploration potential coming on in other areas of the Rockies the Permian and the Gulf Coast. We have of course our continued commitment to financial strength. As you will see even with this vast growth and increase in our drilling budget we're still at approximately 40% debt-to-total cap.

Moving to page 7, just a reminder that this is Whiting's strategy here; acquire, exploit, explore and from time-to-time monetize some reserves. We'd remind you that we recently monetized some reserves in the sale of our royalty trust of about 8 million BOEs and in total realized a net sale price on those BOEs of $31.17 per BOE, and that is a price per BOE that is burdened by operating expenses. So it is not comparable to a typical production payment type of arrangement.

Page 8, I think there are two important numbers on here, first of course the 250.8 million BOEs of proved reserves, but then looking at the column of the probable and possible reserves, which gives us I think substantial upside all of which are independently engineered, the another 242 million BOEs of probables and possibles.

Moving on to update of our net asset value slide on page 9. I would simply call your attention to the right hand column please and note that if we were to deduct all those numbers and prans i.e. the negatives there at 06/30/08, and apply the prices that where in existence at 06/30/08 for foot note two which was 140 per barrel and 1335 per MMBtu NYMEX prices. The PV10 of our proved reserves would have risen to 10.4 billion as you can see there in the fifth line down.

Net of that 1.5 billion, which is the total of all of the numbers in prans are breakup value per share for proved alone would have been about $208 bucks per share. As you can see with the addition of the PV10 of the probable and possible reserves I would underline on un-risked basis here, the net asset value for share rises to over $415 per share. I don't think I need to say anymore on that topic.

Page 10 please. We've highlighted some numbers in green across the top three lines here just to show that in '04 and '05 we were obviously very active with acquisitions of proved reserves, investing $525 million and $906 million respectively of those two year's.

Then of course in 2006 and 2007 the emphasis changed as we begun to put more into the development of the reserves we bought, that is the proved and developed reserves through both our CO2 projects as well as now in the Bakken and the Piceance and as a consequence you can see that the acquisition dollar amounts here over this 5-year period of 1.48 billion are being closely approximated now by the development expenditures of $1.24 billion.

Thus, over this five period drawing your attention to the totals three lines, three underscored lines on the bottom of the page here, the $12.27 all in acquired and developed cost here for our proved reserves to-date. Then looking at the next number down which adds in the remaining year end estimate of CapEx for the proved reserves, which would raise the acquired and fully developed cost to $17.17 per BOE. Then, drawing your attention to the bottom line there, wherein if we add the additional capital estimated for the development of the probable and possible reserves of $1.76 billion and adding the $242 billion of unrest probable and possible reserves would drive that cost back down to about $12.21 per BOE.

On page 11, just at the far right hand column there, summarizing the 207 million BOEs that was acquired, the 45.8 million that was developed, reserve revisions of about 11 million barrels getting you to the 242, and comparing that to production of 56 million for a 433% reserve replacement percentage.

On page 12, as of year end the percentage of our 250 million BOEs that was proved developed was 67%. The proved reserve by core areas show that combination of the green, the blue and the yellow totaling 90% of our reserves are in the big three areas of the mid continent the Rockies and the Permian. Our net daily production by core area again concentrating on the yellow, the green, and the blue total about 85% of our net daily production as of June.

Moving on to our expenditures by reserve categories, as you can see here not only have we have raised our drilling budget looking at those dark blue boxes of both the pie charts from 556 million in 2007 to now 850 million in 2008, but importantly concentrating on the light blue sections here as you can see we've essentially doubled the portion of our cap budget going for non-proved reserves. So, again trying to add production and reserves in that manner.

On page 14, concentrating on the right hand pie chart here as you can see. The biggest portion of our CapEx budget is now the Rockies 57% of that, 850 million up from 35% in 2007.

Moving on to page 15, here we've created a slide for you that shows you the 41% debt-to-total-cap as of June 30. And on page 16, based upon a price per BOE meaning factoring in as well and our natural gas prices, you can see that our margin after lease operating expenses, production taxes, G&A, and exploration expense is running at 66% or almost $52 per BOE.

On page 17, ladies and gentlemen, I think there is an important number in the lower right hand corner here and that is a number of net undeveloped acres that Whiting controls. Its over 400,000 and looking at the Rockies square there in the center of the United States, 300,000 of that in the Rocky mountain region.

Couple of important numbers on page 18. In the Bakken, the second bullet point from the bottom there in the Bakken section; 33 wells drilled in the Bakken in '07, approximately 36 operated wells and 20 to 24 non-operated wells planned for the Sanish field in 2008, and approximately 60 to 70 non-ops and where we are participating with BOG at Parshall.

Also put in a punch line here for our Red River team, which as you can tell from the bottom line on page 18. This 10 out of 12 terms of successful wells out of wells drilled in the period 2005 through 2007 and we have got four more wells planned for 2008.

I like these next slides developed here by Mark Williams and his team. As you can see on page 19, where Sanish and Parshall are and what we call the zone of active oil generation here in the Bakken. So we think it's very well located and again thanks to our team for getting this in early. I'd like to remind people that Whiting's net cost breaker here is only about $100 an acre for our net acres here in the Bakken, in Sanish and Parshall area.

So moving on then to page 20, as you can see what we are doing here is we are driving our well bores down to about 10,000 feet and then we go horizontally in the middle Bakken, for about 10,000 feet in Sanish and that's working well for us as you can tell by page 21, where in these bubble map show that Sanish and Parshall IP rates are generally larger and therefore better then other wells drilled in the middle Bakken since 2000.

We like slide 22, not only because it gives you the IP rates in the little boxes there of wells that we drilled in Sanish. This is our operated portion of the area but in the lower left hand corner of that slide, we call your attention to the current status as of July 31 wherein you can see that we have 21 producing at Sanish, Parshall is 53. We are completing 5, Parshall is completing 8, we are drilling 8, 8 are being drilled at Parshall and there are obviously plans to drill in total for the year 50 to 60 at Sanish including operated and non-operated and 60 to 70 all non-operated in the Parshall area.

Thinking about our plans going forward, we have plans to drill at least what is shown in the lower left hand corner of page 23, wherein you can see in total over the next three years '08, '09, 2010 plans to drill 128 wells. Most of these are single laterals drilled across a 1,280 acres spacing unit and within ultimately each spacing unit two of those single laterals driven across two square miles, so horizontal sections in those wells of approximately 10,000 feet.

In addition, there should be at least around 52 non-operated wells in which we will participate in Sanish again. This is basically just what's on the left hand side of the map here are for the most part therefore our operated area.

Calling your attention to the upper right hand corner on page 23, I'd just like to point that we now have over 118,000 gross acres in the Sanish portion of the field, that's 83,000 net and at Parshall about 14,980 net acres to Whiting. I think John created a great slide here on page 24, showing you the Whiting operated Bakken completions in Sanish alone and as you can tell here by those in my opinion 30 day rates as well as the IP rates in the first 24 hours, these great wells with those great average over the first 30 days.

So, moving on then to page 25. This is a sort of pie chart on the right, summarizes in a percentage format where our budget is being invested. Of the $850 million, as you can see, the Bakken is getting almost 40%, the $329 million, North Ward Estes and Postle 36%, Flat Rock, Piceance and other portions of the Central Rockies 14%, Mid-Con and Michigan outside of Postle 3%, Gulf Coast 4% and in general the Northern Rockies in total 43%. So, as you can tell most of the Northern Rockies is going in to Sanish and Parshall.

Moving on to Boies Ranch and Jimmy Gulch. Great slide here showing IP rates on all the wells drilled to-date and giving you a good status update here. Just to remind you, we plan at least a 110 total wells to be drilled at Boies Ranch and Jimmy Gulch over about the next 36 months and the current status as you can see in the lower left hand corner of page 27 of two drilling, two completing, six waiting on completion, and 13 producing.

Moving on to our recent acquisition of the Flat Rock field in Uinta County for $364.4 million, acquiring 115 Bcf of proved reserves. The production coming predominantly from 7 Entrada wells and this includes gas gathering and processing facilities and a purchase price. 22,000 gross acres and net production of 18 million a day, 97% of which is from the Entrada. As we say in our news release, we expect in addition to the one well currently drilling we expect to drill four more between now and the end of the year all of which would be 100% working interest wells.

Good map for you to know were Flat Rock is in the Uinta Basin on page 29. On page 30, just a reminder in the upper left hand corner in the dark blue box that currently are two large CO2 projects Postle and North Ward Estes, represent 49% of proved reserves and 27% of our June production.

On page 31, again a quick summary of our fully developed cost per BOE on these two projects wherein we have taken in the left hand column what we paid for them, that's $802 million. What we expect to invest in 2008 and beyond, that's another $900 million. Plus what we have put in '05, '06 and '07 getting us to $2.27 billion for 134.5 million BOEs of proved reserves for acquired and developed cost of $16.93. Adding in the nominal amounts of additional capital really in comparison only $150 million of additional CapEx to direct towards the probable and possible reserves there of another $94.4 million BOEs would drive our cost down if successful to $10.62.

I'd like to show the lower right hand corner please on page 32. Where you can see especially at Postle we are over what I call hard CapEx hump and the curve here and that going forward of our $259 million of estimated future capital only $107 million is hard CapEx rest is directed for buying CO2.

Some good pictures of two plant facilities there. We've essentially doubled the capacity of the plants since we took over. Moving on to North Ward Estes on page 34, where we are up to now injecting 100 million cubic feet of CO2 of gas a day into the ground everyday. The start-up began in May of last year, we had a 100 million in January of this year currently have 91 injectors and we are putting over 120 million Btu CO2 into the ground everyday.

So get a schematic diagram on page 35, of what happens i.e. the CO2 comes out of the ground along with the hydrocarbon gas versus the inlet compressors. CO2 is recovered and the residue hydrocarbon gas is then stripped of liquids. The liquids and the stripped gas is than sold. CO2 is re-compressed and sent back to the field.

On page 36. As you can see our schedule here for project timing goes all the way through 2015 in five different phases. Again we are now slightly past the mid point with a lot of the CapEx behind us. Going forward the bulk of the CapEx being directed towards two purchases, which we have in both cases at Postle and North Ward Estes and are currently under long-term contract.

On page 37, just a reminder to you that the proved reserves here from this CO2 project at North Ward Estes totaled almost 74 million BOEs of proved reserves and with the probables and possibles it rises to 162 million BOEs, which is essentially about double what we thought the whole combination of Postle and North Ward Estes had when we brought it.

Production is rising at both projects as you can tell up from June of '05 just prior to our acquisition of Postle and North Ward Estes at about 4,200 BOEs a day at Postle. Currently up to 6,300 BOEs a day and we think on its way to between 8,000 and 9,000 BOEs a day by 2012. Just starting to see the buzz at North Ward Estes its up to about 5,400 BOEs a day, but we believe its on it way to between 10,000 and 13,000 BOEs a day.

Reviewing our hedging, since we've got two more quarters, Q3 and Q4 when we've hedged at using costless callers and prices that are below, what the current NYMEX price is of currently about $124 NYMEX, and so we're paying on our hedges and that's been reflected in our financial statements. But that will end net to Whiting from these particular hedges shown on page 39, as of year-end 2008.

We do own 24% of the hedges from the Trust and those hedges are shown on page 40 and other than a minor payment that will occur for the second quarter of 2008, currently with gas and oil where they are the prices are below the ceilings and obviously above the floors. So, if they were to stay where they are right now, no payments on those hedges nor would any cash be received during the quarter.

In summary, therefore on page 41, Whiting I think is hitting on all cylinders. We've got activity in all five core regions. The acquisitions that we did in '04 and '05 have provided the cash flow necessary to develop the multi-year development and exploitation projects that we own, including our CO2 projects and even more importantly act and execute on the discoveries we made in the Williston and the Piceance. We'll also be testing some other exploration ideas in the Permian, the Gulf Coast and of course the Rockies.

Page 42 is just a good reconciliation for you of net cash provided by operating activities to discretionary cash flow. The same thing on page 43, this one here goes all the way through all four quarters of 2007.

With that I want to thank you all very much and operator now I'd now like to open up the conference call for questions. Thank you very much.

Question-and-Answer Session

Operator

(Operator Instructions). Your first question comes from the line of Larry Busnardo of Tristone Capital. Please proceed.

Larry Busnardo - Tristone Capital

Hey, Good morning Jim.

Jim Volker

Hi, Larry.

Larry Busnardo - Tristone Capital

I guess first, in the Bakken, in regards to the increase in the rigs, can you just give a little bit more detail and when those would be coming, and when, from going to the 5 to 9 rigs this year?

Jim Volker

Sure. We've got two that will arrive in the October, November time frame, and two more that will arrive in December.

Larry Busnardo - Tristone Capital

Okay. And then on the last six wells or so that you drilled there, can you just provide a little bit more detail in terms of the length and laterals on those, number of frac stages, completed well costs on those wells?

Jim Volker

Completed well cost is in the range of $6 million. The link of the lateral was out there approaching 10,000 feet, and the number of fracs within each one varied from typically 9 to 11.

Larry Busnardo - Tristone Capital

That's how they are typically done, so would this be a typical well model if we wanted to build something out to use these kind of parameters?

Jim Volker

Correct Larry.

Larry Busnardo - Tristone Capital

Okay. In regards to Sanish, issue identified where you have a 128 identified locations there, and I think you say those are going to be drilled over the next 36 month. Is that solely the Bakken formation?

Jim Volker

That is solely the Bakken, there is nothing in there for the Three Forks.

Larry Busnardo - Tristone Capital

Okay and that is based on the spacing is 1280?

Jim Volker

That's correct.

Larry Busnardo - Tristone Capital

Okay and at what point do you think, or I guess, have any down spaced wells been tested yet?

Jim Volker

Down spaced wells have been done over at the Parshall. I'd let EOG respond to that. I would say in terms of our thinking on down spacing, we are thinking that if you kind of go back and look at that slide, probably number 23 would be the one to go to. We are thinking that we will at some point put another horizontal between each of those 1280 acre units.

If you took that roughly 128 wells and divide it again by two that would give you the upper end of the range -- roughly another 60 wells or so that might be possible. And just do the spacing, not prepared yet to say exactly how many of those roughly 60 might actually get done as wells that would cross the two, cross the unit lines and produce from two units there. But we think it will be significant for us and then of course we have high hopes for really another oil field underlying this field in the Three Forks.

Larry Busnardo - Tristone Capital

Can you give us a sense of the timing? At what point do you begin to look at that, looking at the down spaced opportunities. Is it more a matter of drilling it all up on the initial space and then you are going down, or do you plan on testing that in a certain area initially?

Mark Williams

Mark Williams, here. We are starting to do that infill drilling in the Bakken this year. We've got one scheduled, if you look on the map here on page 23 in the south central part of our Sanish field you can see as a blue line right there; that's a well that we have scheduled on our drilling schedule. So that will be the first actually down space of the, the second well in 1280 that we'll that's getting [impairment in a month].

Larry Busnardo - Tristone Capital

Okay, all right, and then just in regards to numbers, maybe this for Mike, just on the deferred tax rate going forward. Can you give us a sense what that's going to be in the second half of the year?

Mike Stevens

Well, the overall effective tax rate really courses around 37% and right now we are not expecting to pay any Federal taxes, so basically everything is going to be deferred the way it looks. We will be paying some state taxes and other things, so its going to be pretty small cash taxes this year.

Larry Busnardo - Tristone Capital

Okay, all right, good. Anyways, thanks a lot guys.

Jim Volker

Thank you, Larry.

Operator

Your next question is from the line of Eric Hagen of Merrill Lynch. Please proceed.

Eric Hagen - Merrill Lynch

Hey good morning a few questions. First starting off in the CO2 first Jim, just wondering what were the pud bookings there as of year end 2007 and what's kind of a time frame for seeing those converted in to PDP?

Jim Volker

I'll let Doug answer the volume question, but I will go ahead and move onto part b of your question. In general we think that over roughly the next five years, first is we implement what I would call on the proved section here, moving the proved and developed reserves in to proved developed reserves, then watching that response which I'll characterize for you as being good and at/or maybe slightly above our expectations at this point. I would expect that over that five-year period, we will be seeing reserve adds from the independent engineers of the probable and possible reserves into the proved category.

Eric Hagen - Merrill Lynch

Okay. So maybe roughly at 50 year or so, is that the good sort of [realisms]?

Doug Lang

Close enough, I guess I'd have say that it might start off at somewhat lower than 20% and end up greater than 20%, simply because they will first be concentrating on the conversion of undeveloped and proved developed producing and after we see more performance -- more performance there and get a better idea of the overall recovery factor. We are hopeful that we'll get those extra barrels.

Eric Hagen - Merrill Lynch

Hey, great. Then, second question, I'm sorry.

Doug Lang

That's okay, go ahead.

Eric Hagen - Merrill Lynch

Yeah. Second question was in the Sanish field, EOG set an impartial about 8,000 BOE per well, is that a good do you think ballpark for your Sanish as well? And in terms of bookings will you get to standard sort of two offsets or do you think it will be more conservative on reserve bookings this year?

Jim Volker

Doug, you want to take a crack at it -- why don't you talk about the reserve bookings and I'll handle the EURs.

Doug Lang

Reserve bookings is essentially we're doing, yes, two offset per produce, it's the parallel offsets to the horizontal well. So we are...

Eric Hagen - Merrill Lynch

Okay.

Doug Lang

So we're not counting anything end-to-end or diagonal. It's mainly just the parallel offsets -- picture that, and of course it depends on how of cours your producing wells are, if they are closing up then you don't necessarily get two puds for every PDP, you may have some overlap there.

Eric Hagen - Merrill Lynch

Got you, okay.

Jim Volker

I don't want to do anything here to the spirit what EOG has said, but I will say I think they've done a great job over there and I think we've learned a lot, they've been very forthcoming about what they are doing and we've tried to reciprocate on our part. And I can only underscore that I think they are doing the right thing over there, where they are dealing with the somewhat thinner section of Middle Bakken but it's a somewhat more fractured section of Middle Bakken. So I'll only say that we have agreement with everything that they are doing. I will say that our model Sanish started out at only about 570,000 BOEs per well. Now, that gave us -- that was sort of based on first month, average production of about 650 BOEs per day. And as you can tell from our slide we are doing much better then that.

Eric Hagen - Merrill Lynch

You did about double that?

Jim Volker

Right, right.

Eric Hagen - Merrill Lynch

Okay.

Jim Volker

But we haven't changed our type curve yet, and before we raise that or differentiate it from one portion of the field to the other, we'd like to have about another six months of production before we answer that, we will directly for you. So, I'm only prepared at this point to say, I think we are doing somewhat better than our initial type curve and our initial type curve was 570,000 BOEs.

Eric Hagen - Merrill Lynch

Great. Thanks Jim. And the final one was in Flat Rock have you distinct idea of dry whole costs completed well cost, and the sort of the range of EURs and IPs for dozen drought of wells?

Jim Volker

Mark's been wanting to answer that one, thank you for asking.

Mark Williams

The dry wells, we have four in plans, we talked about before our EUR range in there is fairly broad depending upon where those wells are drilled, and I can pitch in there the average for the puds is about seven Bcf, it varies little bit depending on where we're drilling and where we are expecting it to depletion out.

Eric Hagen - Merrill Lynch

Okay. And then just the…

Jim Volker

…the equation cost I don't think he answered for drilling.

Eric Hagen - Merrill Lynch

Yeah.

Mark Williams

Those are about 3.5.million per well.

Eric Hagen - Merrill Lynch

I'm sorry, 3.5 million per well?

Mark Williams

Yes.

Eric Hagen - Merrill Lynch

So seven Bs were 3.5 million is that kind of the goal whether?

Mark Williams

That's right.

Eric Hagen - Merrill Lynch

Okay, great thanks again.

Jim Volker

All the best. Thank you. Operator?

Operator

Next question comes from the line of Scott Hanold, RBC Capital Markets.

Jim Volker

Hi, Scott.

Scott Hanold - RBC Capital Markets

Yeah ,its Scott Hanold here, with RBC. How you are doing?

Jim Volker

Good.

Scott Hanold - RBC Capital Markets

You are looking at the Bakken and I guess you'll be testing this three fours concept here? If that actually comes in you know pretty strongly and look similar to, or I guess some of other industry participants and seeing. What are the thoughts on using either increasing your rig count from where you're looking at right now and/or I guess shifting some rigs from the Bakken to continue to test the Sanish?

Jim Volker

Okay. I'm trying to say that we are working on a well board design that we might test both the Three Forks and the Middle Bakken from the same vertical well; in other words we'll have horizontal in each zone. So we feel that we could do that obviously with the rigs that we have out there, or at lease those with the larger horse power rigs, and so that's nine rigs and we could do that with at least four or five of those particular rigs in the area. So we are not currently planning to add more rigs until we test our theory there about the Three Forks, if we did we could increase the number of rigs. And stay tuned because that test will occur this year and we hope to have some results by year end. That will help us, in fact we hope to test it a couple of times by year end.

Scott Hanold - RBC Capital Markets

Okay and is that something you look like doing that is, is that something that you -- is that part of what you're testing with [sodium] or is that something that you are thinking serving concept at this point.

Jim Volker

I'm not sure I understand the question, but we are going to drill it over ourselves, going to be operated wells, and that will be drilled in areas where we have an average 80% working interest and about a 66% net revenue interest. So what we intend to develop in the Three Forks actively if the initial tests confirm what have been indicated by other tests in the area. I don't think I have to tell you that there are been rates there, I'll speak in terms of BOEs per day up in the Northwest quarter of our Sanish acreage position of about 800 BOEs a day, and then roughly be about 25 in one case and 30 miles for the Southwest of our acreage position there’ve been wells that have tested between 650 and 1,100 BOEs per day. And then, way down to the south another well, that's roughly about another 60 miles away, there been another well down there at a pre frac flow rate of little over 150 barrels of oil equivalent per day.

Scott Hanold - RBC Capital Markets

Okay, And so your first Three Forks test will be a just a straight single lateral one, but then a follow-up one might be where you try to do own, is that correct?

Jim Volker

Correct, Scott.

Scott Hanold - RBC Capital Markets

Okay, great. And looking at your just other acreage holdings up in sort of the Williston Basin, is there anything else that you have outside sort of Sanish and in Parshall areas that could based on, obviously, we're seeing a lot of step out activity by industry, that's been successful in both the Three Forks and to a certain extent in the Bakken. Do you have other acreage out there that is prospective for either those zones?

Jim Volker

I am happy to say we have about a 179,000 gross and 167,000 net acres in that area, down there to the extreme southwest. And we've done enough on it, I would say that roughly half of that amount is in area that we do like because it has a what we'd call a key element, which is a higher pressure cell in that particular area. I don't want to go too far on that right now, because I want to go into exactly where it is because we're still in the process of acquiring more acreage. But I am pleased to say we have about a 167,000 net acres that we believe our perspective for the Three Forks.

Scott Hanold - RBC Capital Markets

For the Three Fork. Okay, no I appreciate it, and great quarter.

Jim Volker

Great, thanks Scott.

Operator

Your next question is from the line of Nicholas Pope of J.P. Morgan. Please proceed.

Nicholas Pope - JPMorgan

Good morning.

Jim Volker

Good morning Nick.

Nicholas Pope - JPMorgan

And quick question there is a comment in the press release about kind of a work around with wrecks being out in September. So if you can expand a little on that and what the impact and what the impact might be to the Piceance production and is there going to be any impact on the Flat Rock area in terms of production in September?

Chuck LaCouture

This is Chuck LaCouture. We have anticipated this curtailment, if you wil,l for pressuring of wrecks, and we are working with our current markets to get redelivery into other points who which will not be curtailed and minimize the effect.

Nicholas Pope - JPMorgan

And might there been any impact on – does any of the Flat Rock production go up to there at this point?

Chuck LaCouture

Currently it is not.

Nicholas Pope - JPMorgan

Okay. And also as I want to know about acquisition opportunities like what you all are seeing, what you all thinking about right now, I guess what the market looks like, what kind of opportunities there you all are seeing?

Jim Volker

So, obviously we've looked at a couple of opportunities, I think everybody knows that encore has been out there. At any rate, I don't think we were aggressive enough to become involved in the encore deal. I think there are probably still 4 or 5 players there actively pursuing that one. We've looked at a number of private or smaller publicly offered, or what I would call sort of active bid situations, and have not seen anything that really makes us want to move at this point.

As I always say, we are always looking. We have a team of reservoir engineers and other GS scientists here that are directed towards our acquisition activities at all times. But we're always comparing, but we could do the acquisition dollar, and versus what we can do and are doing with the drilling dollar, and right now anyway the drilling dollar is taking precedence because of I think it excellent results that we are getting in Parshall and Sanish in the Bakken.

And frankly we've been acquiring some other acreages you can tell by that 300,000 net acre number in the Rockies where we hope to apply the expertise that this year in our GS science team to coming up with some other areas that overtime will allow us to have couple other exploration plays to work for us.

Nicholas Pope - JPMorgan

Okay, very helpful thanks. And one last thing I was wondering -- I guess there is any issues getting steel or any other services in drilling right now, I mean, and the costs are going up a lot, what are you all seeing there?

Jim Volker

We have seen costs go up significantly, however thanks to the planning activities of both our operations and our drilling department, we have been able to get our hands on all of the casing that we need to execute on our drilling programs, and also all the pipe we need to lay these lines that have become so important to Whiting here, especially out of the Sanish area, that 70 mile line up to our oil market to the north. So we hope all those things are going to work for us.

I will underscore here before I give you this number, but I am not trying to tell you that we think our production will definitely be 115,000 barrels a day well outside of this area, but we sized our oil line there to handle that much oil. Not only our production from the Bakken, but also we hope some production out of the Three Forks, and we may handle some third party bills there too. So, I hope that indicates our optimism for the area.

Nicholas Pope - JPMorgan

That's great. All right and thanks a lot, that's all I had.

Jim Volker

You are welcome and all the best.

Operator

Your next question is from the line of Jack Aydin of KeyBanc Capital Markets. Please proceed.

Jack Aydin - KeyBanc Capital Markets

Hi, Jim, hi guys.

Jim Volker

Hi, nice to talk to you Jack.

Jack Aydin - KeyBanc Capital Markets

Yeah absolutely. Going back to the Rockies just you have, in that slide 18 the 323,000 acres we got 96,000 or so towards the Sanish and you said about 160,000 also to the Three Fork, there is about 60,000 acres. Could you talk about that additional 60,000 acres what the lend themselves to?

Jim Volker

Well I understand the math that you are doing there and...

Jack Aydin - KeyBanc Capital Markets

I'm trying to get little bit more insight to it.

Jim Volker

Right, right, I will try to be responsive to that by saying that we've used what we have learned in the Bakken, and other people have learned elsewhere on this horizontal shale place, to try to develop what I would call some additional shale plays that are in the expulsion phase. Without being too specific about where they are other than the fact that they are in the Rockies we have been active on those and we're going to test some of those with the drillbit in the later half of this year and the first part of next year. And so, we'll talk more about those as we drill them and have results in hand. I can only say that I think we're out in front in of that play and have been for some period of time and we are looking forward to put the drill a bit in dirt.

Jack Aydin - KeyBanc Capital Markets

Jim, did you give a thought also for the – I'm sure you did going into 2009 as far as the CapEx level because some of your CapEx in the CO2 will come down, do you have a, I'm sure you got a plan. Could you discuss it or it's too pre matured?

Jim Volker

Its a little prematured in the sense we obviously have part of that reflected already in our engineering database and it’s another number up there approaching where our current budget is today. But we won't know for sure whether it will be equal to or greater than where we are right now, that is greater than $850 million, until we get closer to the end of the year and have a chance to see some of the results like what we've talked about here today, Jack, where we are going to want to try to look for some more rigs and come in and try to drill some more three, four wells, in addition to those that we could drill with the nine rigs that were already planning to have in there for the middle back-end development.

Jack Aydin - KeyBanc Capital Markets

Thanks a lot.

Jim Volker

You are welcome. I'll go on a little further and say, the same thing will happen there in the Piceance in the sense that, I think there is a good chance that we'll probably ramp up to at least one more rig, and the Piceance will go from two to three, so that we can accelerate to development to Boies Ranch and Jimmy Gulch.

Jack Aydin - KeyBanc Capital Markets

Thanks Jim.

Jim Volker

Thank you, Jack.

Operator

Your next question is from the line of Eric Kalamaras of Wachovia Capital Markets. Please proceed.

Eric Kalamaras - Wachovia Capital Markets

Hi Jim, good morning.

Jim Volker

Hi Eric.

Eric Kalamaras - Wachovia Capital Markets

Quick question for you regarding hedging strategy going forward in 2009, what's the thought there in the prices where they are?

Jim Volker

Say that again? The hedging got out a little bit, we couldn’t hear all of your questions.

Eric Kalamaras - Wachovia Capital Markets

Sure. Just curious as to your thoughts on forward hedging in to 2009 at current prices?

Jim Volker

Really at this point, unless we were to do an acquisition or something like that, I would say we are going to be unhedged or if we do hedge, you will see us do something like floors in the 70s to 80s and ceilings that would be hopefully up there in the 200s.

Eric Kalamaras - Wachovia Capital Markets

Okay. And could you bridge us on production? I know you gave the guidance. Can you bridge us by area I guess, and give me a little bit more granularity in terms of second quarter production versus your third and fourth quarter implied guidance that you put out? Can you do that by operating area?

Jim Volker

I don't want to do that right now due to the variability by region right now. I will simply say that you can expect that the growth will come from the Bakken and the Piceance, that's where it's going to come from. I don’t want to be too specific yet as to how much of it from each area. But we gave you pretty good guidance here and there, with respect to the breakdown in the news release of the production from Sanish, and Parshall, and the Piceance. And you can see how those add in for the first quarter to the second quarter. And I would only say that that combined total for our third quarter projection is going to be from those three areas.

Eric Kalamaras - Wachovia Capital Markets

Okay, that's fine. And then I guess geologically, can you give just a little more clarity on accessing Three Forks and some of the problems that can be encountered or some of the challenges that you may encounter etcetera? And it's just kind of a general question on that part of the geology of the zones.

Jim Volker

Well in general I'll say this that from east side where it might be 70 or 80 feet under, being the top of the Three Forks under the bottom of the little Bakken, to perhaps twice that amount on the west side of our acreage, we really don’t see any significant issues dealing with during the horizontal well and Three Forks. We think it will pretty much like the middle Bakken, or let say the Bakken as it’s been developed at Parshall.

And we don’t see any significant changes in our drilling technique or our completion technique. We think they will be laterals driven out, we hope around 9,000 or 10,000 feet, and we'll complete them with a multi-stage completion technique very similar to what we were doing in the middle Bakken.

Eric Kalamaras - Wachovia Capital Markets

Do you see any meaningful cost differences there at all, maybe doesn’t sound like it?

Jim Volker

We don’t see any significant cost issues or problems, and probably we are optimistic and looking forward to doing it. Hopefully, what we've got there is another oil field underlying the middle Bakken that in and of itself be significant to Whiting, just like the middle Bakken is significant to Whiting.

Eric Kalamaras - Wachovia Capital Markets

Great. Okay thanks very much.

Jim Volker

All the best. Thank you.

Operator

Your next question comes from the line of Wayne Andrews of Raymond James. Please proceed.

Wayne Andrews - Raymond James

Good morning gentlemen, congratulations on a nice quarter.

John Kelso

Thank you, Wayne.

Wayne Andrews - Raymond James

I know you've had a number of questions regarding your Three Forks test, I just got one more for you. Have you decided that test, I guess the question you want to answer is if you are getting any contribution in your Middle Bakken production from the Three Forks zone, because you are in an area where it is fractured.

So is your well one that you will drill in an area where you have already being producing Middle Bakken or you would you move outside of that currently productive area for a separate test?

Jim Volker

Mark will answer.

Mark Williams

Wayne, Mark Williams here. We have really wanted each of those that you just mentioned. We are going to be testing one area where we will have a grassroots horizontal well and a 1280 that has not been drilled at all for Middle Bakken yet. And of course we want to answer the question of whether there is any interference. So we have another well planned.

There a slight offset to an existing Middle Bakken well that we believe will test that theory at an optimal distance away from the current Middle Bakken producers. So outlining each of those schedule here in the late third quarter, that will probably go down about the same time that just in terms of what we are anticipating there. There is a Lower Bakken Shale member that sits below Middle Bakken that is where we believe there is a very good chance that that will be a barrier that's actually separating those two zones. We don't know that yet, and that is why we are drilling these.

Wayne Andrews - Raymond James

Yet it sort of sounded like you need two of them. I am glad you are working on that and we'll look forward to the results. And then maybe just one other question on your winter area at Flat Rock. You mentioned that almost all the productions coming from seven wells, and I was wondering what is the advantage of those wells, when will they drill? I guess they are currently producing, if you just do the math, close to 2.5 million cubic feet a day. I am just wondering how old they are and we can get a feel for the decline curve.

Mark Williams

The oldest are probably be five years, we are talking about Entrada wells.

Wayne Andrews - Raymond James

Yes.

Mark Williams

Probably five years and then there has been some continuing drilling. So probably, five years, and there is a couple in the three to four years range, and couple within the last two years. I would say.

Wayne Andrews - Raymond James

Very good. So, you've held up quite well. Great, that answers all my questions. Thanks again.

John Kelso

All the best. Thank you, Wayne.

Operator

Your next question is from the line David Tameron of Wachovia. Please proceed.

Dave Tameron - Wachovia

Thanks. Good morning, Jim.

Jim Volker

Good morning.

Dave Tameron - Wachovia

Believe it or not, I have a couple of questions left.

Jim Volker

Good.

Dave Tameron - Wachovia

Running through some math, I am talking about just doing some math in my mouth. It looks like the wells are going to payout in a couple of months up in the block, and am I looking at that right. What's your pay back internally on a typical Sanish well right now?

Jim Volker

Well certainly, Dave, did you hear my comments about our type curve.

Dave Tameron - Wachovia

Yes.

Jim Volker

Okay. In round numbers, and again, I am going to use a somewhat lower oil price here, I am going to say, we are only going to net after royalties, operating expenses, and production taxes. We're only get a net $60, okay.

Dave Tameron - Wachovia

All right.

Jim Volker

Dave, on our curve the Q after 12 months was 112,000 barrels of oil equivalent. So, $60 times 112,000, that’s little over $6 million. So, that’s roughly the one year payout. And we think we are probably doing, I don’t want to say, how much better yet, you heard my comment, we would like about another three or four months here before we revise our type curve upward. But I would simply say that in all probability our payouts somewhere between six months and nine months at this point in time.

Dave Tameron - Wachovia

Okay. And is that current crude prices or you'd like to say used at slightly lower deck?

Jim Volker

Yeah, we're using lower deck.

Dave Tameron - Wachovia

Okay, fair enough. And then for 2009 when I look out and run by model, it looks like you can get to 10% production growth fairly easily. Any comment on 2009 and where you guys are headed just big picture wise?

Mike Stevens

We're trying to under promise and over produce, my friend.

Dave Tameron - Wachovia

Does that mean that when I'll get the number?

Mike Stevens

We would agree with you that 10% is obvious. But we'd like to not comment on 2009 until we get to the end of 2008, please.

Dave Tameron - Wachovia

All right, fair enough. Thanks.

Mike Stevens

Thank you.

Operator

Your next question is from the line of (inaudible) of Cardinal Capital. Please proceed.

Unidentified Analyst

Thank you and congratulations on a great quarter.

Jim Volker

Thank you.

Unidentified Analyst

The question was on hedging in response to your answer about the kinds of colors you all might look at, it would be useful to get your view on how feasible it has been or maybe to enter into those kinds of fairly white colors, given how volatile the cash market teams that have been?

Jim Volker

Well, I can tell you that earlier this week, we receive sample sort of unsolicited quotes that are typically, I think you know what I am talking about when I say $10 out of the money quotes, and $20 out of the money quotes, and both of those would indicate that something approaching $200 ceilings is still possible.

Unidentified Analyst

Okay. So, I guess then the follow-up arises which is that, what would get you to that point where you would want to initiate hedges beyond 2008 and what would be sort of the percent of production that you all have typically being comfortable, is that the 35% it seems for the rate or…?

Jim Volker

50%, and what would initiate that would be further thinking frankly as to the direction of oil prices, personally, I think the last time I was interviewed this would have been back in May and June, and oil was already over a 120 and we gave our estimate as being 120. And the questioner sort of blinked why aren't you saying 140, and that's because we felt that it was more like a 120. And that's where we are still as our estimate of average NYMEX oil price in the second half of the year.

Unidentified Analyst

Okay. Great, thank you.

Jim Volker

Yes, you are welcome.

Operator

Your next question is from the line of Dave Kistler of Simmons and Company. Please proceed.

Dave Kistler - Simmons and Company

Good morning guys.

Jim Volker

Hi Dave.

Dave Kistler - Simmons and Company

Hey, wanted to follow-up on kind of production guidance just for a second. Won't ask you about '09, don't worry. But if I just take your exit rates from June, your average production rates and run those forward against what you've done year-to-date, puts you pretty darn close to the low end of your guidance with all the different fields that you're working on and the rigs going to work. Am I missing something or is it, I understand under promise over deliver, but can you give me some more color around that?

Jim Volker

We both, I mean Mike and I know, we know exactly what you’re asking and why you’re asking it, and yes we are close to the low end of the guidance, just holding it flat. First of all let me say, so we recognize that, we recognize that we have a number of wells that just have to be completed at Boies Ranch to come on. We recognize that we're going to have -- you might think about it as sort of five rigs working up until October, November and then adding these last four rigs in that October through December range, so they will help us kick up a little bit anyway our activity there in the Bakken. And the other thing, frankly, that I hope isn't stated too obliquely in our press release is that the production that we have, I'm kind of referring to page 2 of the press release and kind of the second paragraph there wherein we say, you know, we basically sold 3000 barrels a day in April, that closed in April. And so we didn't have it in May and we didn't replace that 3000 barrels a day until June.

So you can say -- therefore that 3000 barrels of day for that three months period is really only more like about 2000 barrels a day since we had it for two months out of the quarter rather than three months out of the quarter, and so it should be roughly a 1000 barrels a day in the third quarter that gives added back as we try to having that production on for full quarter. So on view of those, what I call three positives, yes we would agree that the comment is accurate, but we're not prepared at this time to say anything other than our guidance is the guidance. We want to under promise and over produce. So I'm sorry, but we're not prepared to go much beyond at this point.

Dave Kistler - Simmons and Company

Now I appreciate that clarification.

Jim Volker

The end of the third quarter.

Dave Kistler - Simmons and Company

Great, I appreciate that clarification. One just quick housekeeping, with respect to the thought about down spacing in the Sanish, essentially we should think about those more as offsets, is that correct?

Jim Volker

Yes. Down spacing in the Middle Bakken is just – in other words when we say down spacing keep in mind that what we're planning here is two well bores within each 1280 units acrossed -- so within each section you can think about that as being developed on 320s.

Dave Kistler - Simmons and Company

Yeah.

Jim Volker

Okay, then in terms of an additional well bore, we're talking about running a well bore at a later date after we get fully developed in there on 1280s with 2 well bores within each 1280. Then we are talking about running a well bore in that space which is essentially between each unit, between each 1,280 acre unit, which would cross the unit boundaries, and we think therefore, continue the development pattern which what you can think about is the total of five wells within each two unit capsule.

Dave Kistler - Simmons and Company

Okay, great. Thank you for that clarification. And then, one other down spacing question and this is related to Jimmy Gulch and Boies Ranch. With the possibility of going down to 10 acres spacing, can you talk a little bit about how you are approaching, planning to test that at some point or any color around that?

Jim Volker

Thank you for asking. Yes, we do have an area we are currently going to test with the 10 acre spacing, we're going to start out with around 20 wells in that area. And if the results continue to be as good as we think they are and we could expand that hopefully to a large area.

We can't say that we necessarily believe that will appropriate for our entire acreage position. But we are encouraged even by what I would call the parameters of our acreage position and the results that we are seeing there. So I'm not yet prepared to say that we are going to go to 10 acres everywhere. But we're going to test it starting out with about 20 wells or so, and that the results continue to be as good as we hope, then you will see us come out with an announcement about a larger area on 10 acres spacing.

Dave Kistler - Simmons and Company

Well, great guys thank you very much for all the time today.

Jim Volker

All the best, great questions.

Operator

And your next question is from the line of Scott Hanold of RBC Capital Markets. Please proceed.

Scott Hanold - RBC Capital Markets

Thanks, just got a follow-up too here. I am looking at I think its page 17 of your presentation of your acreage position. Did you have acreage, I guess in the couple of parish's and even on the Texas side that are sort of hot for that Haynesville trend. Is there anything you have that’s meaningful to talk about?

Jim Volker

Mark will answer that.

Mark Williams

Yeah, most of that acreage is in areas that are operated providing and we are participating in wells in the Haynesville play. But they are not operated, when you add it all up its not a terribly significant component in (inaudible), they are known as significant component to our overall production.

Scott Hanold - RBC Capital Markets

Okay.

Jim Volker

We hope all those boys stay down there along the Gulf Coast and over in the Mid Continent and leave the Rockies to us.

Scott Hanold - RBC Capital Markets

Would you, do you have an acreage number you can put on that sort of the stuff you are having like this sort of board here in [canola] like on a net basis?

Mark Williams

If I were to give you a number it would be an approximate number, but we have about five sections total in that area, which we think probably two-thirds of its --.

Scott Hanold - RBC Capital Markets

Okay, and just kind of on a strategic development question here and given where commodity prices are and potentially what a seller is looking to get because of that and your organic opportunities. Has there been sort of a change in your thought process of how you can grow Whiting here over the next few years?

Dave Seery

Excuse me Scott. Your question really presupposes, and correctly presupposes our answer. Yes there has been a change. It has been a change that we have been executing on now for over a year with the drill bit. I hope my earlier answer about comparing as we always do the opportunity is available to us through the drill bit, but the opportunity is available to us through the acquisition dollar, indicate that we know and understand that those opportunities that have the highest. Whether you talk about it as rate of return, or ROI, or lowest finding cost, are the ones that we need to pursue, we don't want to dilute those with say lower rate of return or lower ROI opportunities that might be available to us through the acquisition dollar.

I would remind everybody however, is I have recently discussed with our Board that we wouldn’t be in this position today if we hadn’t taken advantage of some acquisition opportunities which added to our inventory of acreage. For example the equity acquisition, which gave us acreage in the Piceance where no one gave a darn about the Piceance. And we are acting on that now and it is obviously being very helpful for us in terms of our production growth and our reserve growth.

So I would just like to remind you that I know the market would take it out of our hide if we did an acquisition now, but I hope that our track record of having made both opportune, and I think smart, acquisitions from a cost standpoint would cause people to say, well we understand it may not be growth like they are getting from the drill bit. But hopefully, based upon their track record, they've given some thought about why they want a particular acquisition and we will benefit from it in the future.

Scott Hanold - RBC Capital Markets

Okay. Appreciate the answers, thanks.

Jim Volker

You are welcome.

Operator

Your next question is from the line of [Chris Gold] of Lehman Brothers. Please proceed.

Chris Gold - Lehman Brothers

Hey guys, I think most of my questions have been answered. Just in regards to your credit facility. Are there any plans to do anything about lowering that amount by year-end either through terming off that debt or through monetizations? Thanks.

Jim Volker

We can't tell you about any plans that we have now until unless we file some sort of registration statement. But, we are happy with our debt levels where they are. We are happy with the current mix of long-term and bank debt. And I think, you can tell from rate of growth in production, that obviously there is some positives happening there with respect to reserve adds. I think Doug and Mike do a great job of staying in contact with our banks. I believe that in September when we meet with them it will be likely that they will look favorably upon the amount of our borrowing base and be, [malleable] with respect to that if we like to ask for an increase.

I hope that's direct enough for you.

Chris Gold - Lehman Brothers

Yes, thank you.

Unidentified Company Representative

Jim Volker

Operator

(Operator Instructions) And there are no further questions at this time.

Jim Volker

Thank you very much. Okay, I know that you've all been very kind in the amount of time you've given us here today. In closing, I'd simply like to underscore that we expect 2008 to continue to be a breakout year for organic production in reserve growth of Whiting.

Now I'd also like to mentioned several events that Whiting will be participating in over the next several weeks, and we hope it will give us an opportunity to meet with you personally. We'd presenting at Intercom's 13th Annual Energy conference, we're on at 10.30 am on Monday, August 11. That conference is being held at the Westin Tabor Center, here in Denver. We're also presenting at the Lehman Brother's Energy Conference, we're on at 2.20 pm on Tuesday, September 2nd at the Sheraton Hotel and Towers in New York City, and I'll be on a panel to discuss techniques that we use to get oil out of shale at (inaudible) Harrold Energy Conference, we're on at 8:15 am on Thursday September 25th. That conference is held at the Hyatt Regency Greenwich, Connecticut and we're also planning to participate in the Merrill Lynch Energy Conference in Midtown Manhattan on Wednesday October 1st and we look forward to seeing you at those events.

As always, I'd like to thank all of you on this call for your new, or specially your continuing, interest and increased interest from what we can tell in Whiting Petroleum Corporation. And I want to express my personal thanks to all of our Whiting employees and our Directors for their contributions to Whiting's success and our plans for significant growth in 2008. Thanks again and thank you operator for your help today.

Operator

You are welcome. Thank you for your participation in today's conference. This concludes the presentation. You may now disconnect and have a wonderful day.

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