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.

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.

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…

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.

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…

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

Hey, Good morning Jim.

Hi, Larry.

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?

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

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?

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.

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?

Correct Larry.

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?

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

Okay and that is based on the spacing is 1280?

That's correct.

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

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.

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, 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].

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?

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.

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

Thank you, Larry.

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

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?

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.

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

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.

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

That's okay, go ahead.

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?

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

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

Okay.

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.

Got you, okay.

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.

You did about double that?

Right, right.

Okay.

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.

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?

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

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.

Okay. And then just the…

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

Yeah.

Those are about 3.5.million per well.

I'm sorry, 3.5 million per well?

Yes.

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

That's right.

Okay, great thanks again.

All the best. Thank you. Operator?

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

Hi, Scott.

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

Good.

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?

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.

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.

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.

Correct, Scott.

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.

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

Great, thanks Scott.

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

Good morning.

Good morning Nick.

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?

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.

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

Currently it is not.

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?

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.

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?

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.

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

You are welcome and all the best.

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

Hi, Jim, hi guys.

Hi, nice to talk to you Jack.

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?

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

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

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.

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?

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.

Thanks a lot.

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.

Thanks Jim.

Thank you, Jack.

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

Hi Jim, good morning.

Hi Eric.

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

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

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

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.

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?

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.

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.

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.

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

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.

Great. Okay thanks very much.

All the best. Thank you.

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

Good morning gentlemen, congratulations on a nice quarter.

Thank you, Wayne.

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?

Mark will answer.

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.

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.

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

Yes.

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.

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

All the best. Thank you, Wayne.

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

Thanks. Good morning, Jim.

Good morning.

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

Good.

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?

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

Yes.

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.

All right.

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.

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

Yeah, we're using lower deck.

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?

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

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

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.

All right, fair enough. Thanks.

Thank you.

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

Thank you and congratulations on a great quarter.

Thank you.

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?

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.

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…?

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.

Okay. Great, thank you.

Yes, you are welcome.

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

Good morning guys.

Hi Dave.

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?

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.

Now I appreciate that clarification.

The end of the third quarter.

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?

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.

Yeah.

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.

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?

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.

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

All the best, great questions.

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

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?

Mark will answer that.

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.

Okay.

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

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?

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 --.

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?

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.

Okay. Appreciate the answers, thanks.

You are welcome.

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

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.

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.

Yes, thank you. Unidentified Company Representative

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

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.

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.