Good day ladies and gentlemen and welcome to the first quarter 2009 Whiting Petroleum Corporation Earnings Conference Call. My name is Francis and I will be your coordinator for today. At this time, all participants are in listen-only mode. We will be facilitating a question-and-answer session towards the end of this conference. (Operator Instructions). As a reminder, this conference is being recorded for replay purposes. I would now like to turn the presentation over to your host for today's call, Mr. John Kelso, Director of Investor Relations. Please proceed.

Thanks Francis. Good morning everyone and welcome to Whiting Petroleum Corporation first quarter 2009 earnings conference call. On the call for Whiting's 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; Bruce DeBoer, Vice President, General Counsel and Secretary and Chuck LaCouture, VP of Marketing. During this call we will review our results for the first quarter and then discuss the outlook for the reminder of 2009. This conference call has been recorded and we will available for replay approximately 1 hour after it's completion. Both the conference call with an accompanying slide presentation and our first quarter 2009 earnings release can be found on our website at www.whiting.com. To access the call and the website, please click on the Investor Relations box on the menu and then click on the Webcast link. Please be advised that the following remarks including answers to your questions, includes 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 Form10-K for the year ended December 31, 2008. We disclaim any obligation to update these forward-looking statements. I would also like to mention that our first quarter 2009 10-Q will be filed later today. In this call, we use the terms, probable and possible reserves, which are unproved reserves that we do could not include in our SEC filings. Please refer to our website slides for more information on probable and possible reserves. During this call, we will also make references to 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 With that, I will turn the call over to Jim Volker.

Thank you, John. Good morning and welcome everyone to Whiting Petroleum's first quarter 2009 conference call. We are looking forward to this conference call as we have a number of good operating statistics to discuss with you as well as in our opinion especially considering current oil and gas price levels, excellent financial results. So, we look forward to answering your questions that you may have following the presentation. Two days ago we announced the closing of a new credit agreement which will provide Whiting additional financial flexibility whether we have improving or deteriorating conditions on oil and gas prices. The agreement replaces Whiting's previous credit agreement and increases the borrowing base from $900 million to $1.1 billion. In our announcement we said that we had $1.042 billion of commitments are closing. Yesterday we were informed of another $58 million commitment thus bringing commitments and our borrowing base to $1.1 billion. Today we announced a new capital budget of $420.6 million. Our objective for 2009 continues to be maintaining our current liquidity by funding our capital expenditures primarily through discretionary cash flow. We will focus our exploration and development expenditures on our Bakken play in North Dakota and our CO2 enhanced oil recovery projects. With the $420 million budget, we believe we can generate at least year-over-year production growth of between 8% and 10% in 2009. I would remind those of you that it's Whiting's practice to obviously risk the drilling that we have scheduled between now and year-end since most of that is at Sanish where we have had a 100% success ratio. We obviously believe our guidance here is something that we hope we can improve. To the extent net cash provided by operating activities for oil and natural gas prices are lower than currently anticipated. We would…

Thanks, Jim. As Jim mentioned earlier we entered into new credit agreement with our bank syndicate that was arranged by JP Morgan. The new credit agreement expires in three years on April 28, 2012. As of April 27, 2009 $610 million was drawn on the facility and $3 million in credit were outstanding resulting in $429 million of availability. We expect to add an additional bank to the facility today bringing total commitments to the borrowing base amount of $1.1 billion an increase in availability to $487 million. The next regular borrowing base redetermination day is November 1, 2009. Our borrowing base was increased due to improvements in our reserve quality. Which more than offset the effects of using lower pricing assumptions. We believe this action provides further affirmation of our strong credit and favorable operating outlook, and it will allow us greater financial flexibility to operate in the case of an extended period of low commodity price. First quarter of 2009 we reported a loss of $43.8 million or $0.92 per basic and diluted share and total revenues of $163.8 million. Whiting's net loss in the first quarter of 2009 included after tax non-cash losses on hedging arrangements of $14.6 million or $0.31 per share. This compares to the first quarter 2008 net income of $62.3 million or $1.47 per basic and diluted share and total revenues of $264.1 million. Discretionary cash flow on the first quarter of 2009 totaled $71.9 million compared to the $161.4 million reported for the same period in 2008. The decrease in discretionary cash flow and net income of the first quarter of 2009, was primarily the result of a 64% decline in the company's oil price, and 52% decrease in natural gas prices. During the first quarter the company wide basis differential for crude oil compared NYMEX $10.66 which compared to $11.38 per barrel in the fourth quarter of 2008. We expect our oil price differential to average between $9 and $10.50 during the remainder of 2009. Within the Bakken Whiting has operated production during April at an estimated differential of $7.50 per barrel. In addition we expect their 17-mile oil line connecting the Sanish field to the Enbridge pipeline to be in service in the third quarter of 2009. We expect this event to have an additional positive effect on the crude oil differential in this area. I would also like to point out that our cash costs on the unit of production basis are down more than 26% from the first quarter of last year. We expect to see further reductions in our cash costs as we move through 2009. I will turn the call back over to Jim Volker for some additional comments on our operational activity.

Thanks, Mike and with that I would like to. View the slides on our webcast which I hope will provide some additional color on our primary operating areas. Please give special note to our forward looking statement disclosure reserved information and non-GAAP measures. That’s seen on page 1. Page 2 is just a quick outline of Whiting's current market cap I am sure you are all familiar with that. And our current debt situation which gives us debt-to-total cap at 37%. Still I might say even at the reduced oil and gas prices that we have today. 239.1 million BOEs reserve. So lot of reserves behind every share of stock and great RP ratio of 13.6 years. Current production of 54,500 barrels a day. We are pleased to see this slide on page 3, 32% increase in the quarterly average daily production year-over-year. Moving to the reserve pie chart as you can tell the bulk of our proved reserves here coming in the Rocky Mountain and the Permian Basin. Moving on to slide, 4. still even at what I would call this moderate oil and gas prices attractive margins with sales price net of sales price net of hedging, $32.97 in the quarter, still an EBITDA margin of 42% or $14.13 after exploration G&A production tax and lease operating expenses. Moving on to page 5 here we breakout where are the reserves total 239 million BOEs and what percent is oil. And how we arrive at the 1.6 billion value based on NYMEX prices of 44.60 and 5.63 at 12/31/08. As you can see the largest portion of the value being in the Permian basin and the Rocky mountains. Moving on the slide 6, the highlighted points A and B of course are key to Whiting. Where we are continuing…

Thank you. (Operator Instructions) And our first question is from the line of Joe Allman with J.P. Morgan. Please proceed.

Thank you, good morning, everybody.

Good morning, Joe

Hi, Jim, you are producing somewhere around 13,000 barrels of oil from the Bakken, could you tell us why you're moving that and how much is through pipe and how much through rail and truck and what not, what do you think with differentials recently.

Thank you for asking. It's all being trucked and we believe by the time we get no later than the end of the third quarter of this year, most of it will be in the pipeline, the differential there for us is currently $7.50. And it's come down obviously markedly from it was almost $18 during the worst times last year. And we're looking forward to further improvement on that. We hope to say essentially overtime, somewhere between $2 and $4 a barrel, as a result of first the recovery of our cost delaying that line. And then brining what I would call the transportation through the line down and that should save us in comparison to trucking between $2 and $4 a barrel. And we don't rail out anything. Our friends at EOG do rail-outs in barrels and that I believe this probably one of the reasons if they elected not to perhaps complete wells as we did during the winter time up there, they were suffering somewhat greater differential than we were. So I concur on their decision there not to complete this many wells during the winter. And I think it's a good decision on their part. We however weren't suffering quite as big a differential. So we when had completed our wells.

So the cost of trucking, you are saying as a roughly $2 to $4 per barrel?

Its about 4 bucks now and we hope that as we get it into the third quarter of this year, then you will see a decline hopefully a couple of bucks and then after the recovery of cost of the gathering system and that line that we're putting in, it we should do better than that somewhere into ranges $3 to $4.

Great, and do you have any firm transportation on that line? I mean how much capacity do you think you will have?

Well, let's thank you again for asking the line has a capacity of 65,000 barrels a day and our plan here is, there is a large industry marketing company crude oil marketing company they wants on that line. So Whiting essentially has permitted, we will lay it in the ground and at that point we'll sell it to them at our cost, which should plus a moderate mark up which should be around $6.6 million and so its not a very expensive thing to do. And in return for that, what we will get is priority, first priority on a 100% of this particular companies allocation, how much crude they can put into the Enbridge line, we will have a 100% of theirs and then combined with the allocation of another four purchasers, who put there crude into Enbridge we think that we will be able to mark up all of our crude unless we elect the market sum elsewhere, I would say at our option will be able to market all of our crude down that line.

Okay, got you, okay, and then I guess the cost of that, is there to the separate cost that we should look forward?

Yes. Just try to, initially we think there will be roughly a $2 recovery of the expenses. So if we say truckings for, we will say $2 and then probably after around 36 to 48 months we'll bring it down probably another buck and half. I expect that there will be at least $0.50 or so operating cost.

Okay, very helpful. Thank you, Jim.

Thank you.

Our next question comes from the line of John Freeman with Raymond James. Please proceed.

Hi guys.

Good morning, John.

Good morning, can you elaborate some more on a what's drive in the big efficiency improvements that you are seeing in your Bakken wells getting down from 60 days to 41?

Yeah, sure, John, this is Jim Brown, the guys have been doing a lot of things, when we run our swell packers out there, our liner with swell packers. We have been taking the time to ream to do a real careful job of reaming that hole that we drilled out there, that horizontal lateral. And we've been working on techniques, where we can eliminate that reamer run, that saves is about three days. Some other things our guys have done, one of the well we've recently drilled in 38 days. We’ve drilled the entire lateral with one mud motor run. So we were able to get the whole lateral done in one shot. And the guys are trying to figure out ways to make sure they can do that consistently. Also they are working just on the vertical part of the whole working on some efficiencies to try to reduce the time they takes and to get the vertical whole the curve built, and get the seven-inch casing set. So that's the approach they're really tackling right now.

Okay. That’s helpful, and then moving to that Lewis & Clark prospect in the slide, you said you have identified the next six wells. Is there any sort of timing you can give us, on when we would expect to hear, additional results from the area?

Yes. When you see NYMEX around 58 bucks on the front end, that’s about when we’ll gear up and start going there yet.

Okay.

Okay. Let me just explain briefly on Jim Brown's answer, all of those things that he talked about are part of our program here at Whiting that we call wells on paper, where we involve everyone from the office to the drilling contractor to the pumping service people in the field and our operations people in the field in order to have a plan for every foot of that well and how long it should take. That’s based upon our experienced in the field and what happen when it was done most efficiently, I mean we apply that to be entire, horizontal and vertical link through the well. That’s really been effective and driving our time on location and our cost down.

Okay. And then since you did kind of bring up the price sensitivity just, looks like during the quarter, you didn’t add any hedges and just with the strip in 2010, now north of 60 is that a price you would be comfortable starting to add additional hedges and do you have any sort of target in terms of percentage you like to be hedged.

Okay, those are great questions, John, let me say that, well no final decision has been made here, because we put our hedges on about Thanksgiving time. What we did in order to get what I would call the profitable hedges that we have been getting paid on the front end then cash, is that we went to long, we went up to 2013, right? And that basically gave us an average from the front end to the backend high enough to get some profitable hedges on at that time and profitable hedges that are still on today. Some of the non-cash losses that you see in the income statement are the result of the fact that the backend has been coming up. So well, we haven’t made a final decision on that, should well prices continue to sort of waffle where they are here in my opinion as we see what I would call earnings come in from the industrial companies in the United States. I am thinking that the backend may comedown a little, so we may lift some of those back end hedges and liquidate them even though, at what I would call breakeven or little better, I mean in 2012 and 2013, if possible. So might be a combination of '11, '12 and '13. And then put on replacement more hedges on the front end but using, again, costless collars to give us an opportunity to put on a floor that's acceptable. Currently, obviously, we have tried to show you here that we are I think making money and making good money on our CO2 projects and in the Bakken at essentially $50 oil in those areas. And so if we can get, floors that are around that area and ceilings somewhat higher than I think we do that predominately, let me answer your question, is yes, we would put on some more hedges, Mike can comment after me on the volume of hedges that we have, that we could put on, I am going to say the remainder of 2009 and 2010 and 11. So that sort of the idea, John would to be not so far out, life those here, well we can that little or no cost and maybe put a few more on at the front end. I hope that's helpful.

I appreciate the color. And that's all I had. Thanks guys.

All the best, John. Thanks.

Our next question will come from the line of [John Rabavino] from Wachovia. Please proceed.

Hi, good morning, guys.

Good morning, John.

Can you walk me through the first quarter CapEx, I mean I am looking at $176 million in E&D. And I just want to see the run rate there it seems high little bit for the full year. I just want to see if you could break that down either geographically or by (inaudible)?

Okay. Well, in summary I try to be relatively specific what you hear that how see it going. 176 in the first quarter, roughly 100 in the second quarter, roughly 73 in the third and roughly 71 in the fourth getting you to the so, that's how we kind of intend to bring it in and in terms of how that was done kind of you should by region that would have been in the range of around and this doesn’t necessarily include quite everything, but roughly in the range of around $9 million I think and mid continent around we gets about $100 million in the Rockies and about roughly the difference than in the Permian.

I appreciate it.

Permian was about 176.

Okay. Can you compare that number to what I saw on PR for it, the total cash, it was investing activities is like $220 million number what's difference there?

Difference is that the way that works from investing activities you have to put in your change in payable position from the end of the year to end of March.

Okay.

So as our payable decreased in increasing amount of cash that we had to lay out during the first quarter.

Okay. And then looking at your first quarter production guidance back in February. What kind numbers I was backed in to that as far as weather impact and you see that EOG kind of pushed of 13 wells, was that something that you foresaw, or was that something I was baked into the guidance or just can you talk about that little bit more?

It wasn’t. We didn’t know we are going to do that.

Okay. And then one more just kind bigger picture on the full year CapEx budget. If you go back to the beginning of the year targeting call 8% to 10% growth on $320 million budget. Then the equity issuance came you guys raised the budget to $474 million and then also increased the growth rate to call it 12% of the midpoint. Now were backed at 420 but my growth targets are backed down where they were with the same budget of 320 if you follow me. Where is that additional $100 million going and how come there is not bigger uptick on the growth rates?

Well, in general, I guess, I can always say this, yes, we have brought our target down. Yes, we have been conservative in terms of spending that CapEx, the capital that we raised with the equity offering. And in general that's because when we did it the 12 months trip was at little better than 58 bucks, okay. So we want to keep that power dry. Are we in comparison to where we were before being somewhat more conservative? I would say, yes, on our guidance we are, but in part keep in mind as I said early on my talk here that. We do risk our results going forward in the second, third and fourth quarter. We may have hit it little heavier than we needed to this time with risk in our guidance and we are hopeful that to maintain the same kind of success ratio that we have to date especially there in Sanish. So I realized that we have been somewhat more conservative on this guidance, but we are hoping that with continued results there we will be able to improve on that guidance and get us back into somewhat higher range. I hope that answers your question.

Great. I really appreciate it. Thanks very much for color.

All the best.

Our next question is from the line of Biju Perincheril from Jefferies. Please proceed. Biju Perincheril - Jefferies & Company: Hi, good morning, everyone.

Good morning, Biju. Biju Perincheril - Jefferies & Company: Most talking of it the North Ward Estes production looks like its flat to down here, if that what you would have expected from phase one and before we see it turn around. Do you need to see response from phase two or?

No, actually I would say really as I commented there that we were sort of moving into phase two, executing first part of phase two there, but really what happens to us was that as we got out there in the phase one we put a fairly big love to see two into the reservoir. We saw obviously a nice buzz out of that and we begin to put some water as there is a lag process out there. We did see bit of an issue with some build up on the tubing there, that took us roughly a month, month and half to work our way through that which we now I am going to say treat for as we complete wells. We basically put some chemicals in before we put the producers on production and that issue was gone away. And so, even I would say, Biju, without respect to the increase that we expect to see from phase two, I do expect to see lives and production from phase one as and hats off to the team there in Midland. I believe they did an excellent job of responding to that schedule. Biju Perincheril - Jefferies & Company: Okay. And then where do you think phase one can peak out at?

Again I don’t want get into too much detail here because we will be frank about it. There is just not movement because we are doing so much in the field both at phase one, phase two and then our two water flood restoration areas that best I would like to do is refer you back to that slide or you can see that we are going to get up to roughly 10200 BOEs a day. And out of all proved categories and then we are hopeful as I said this is just obviously very interesting time for us here Whiting because the flood is responding writing because the flood is responding in a manner that would indicate that we are getting a higher response which would indicate a somewhat greater than the 5.5% based upon Chevron flood recovery factor and we're not far enough to long that I can call that in finality or tell you how many reserves we're going to add or for that matter be exact as to what the peak rate might be over and above that 10.2 roughly, 10,000 barrels a day improved. We're hopeful that with the continued operation of the field in the manner that we're operating it which is different than the way Chevron did it, basically, they operated at about 50 psi and we're operating at about a 150 psi holding those pressures on the wells, what does that do? That causes pressure in the reservoir, in our opinion that means that liquids don’t fall out of the reservoir, it carries them up to the well bore better, we're not putting liquids back into the reservoir, Chevron was recycling those back in and that reduces the efficiency of your flood and so those two factors alone we think will resolve in a higher recovery factor than Chevron has. How all those factors play out especially over about the next 24 months remains to be seen. I can only tell you that I am highly optimistic about the results that we're seeing today and the ability hopefully over the time to add that 78 million BOEs out there to our improved reserve base and I hope that’s an adequate feature. Biju Perincheril - Jefferies & Company: It is. Thank you.

Thank you.

Our next question comes from the line of Joseph Magner with Tristone Capital Inc. Please proceed.

Good morning

Good morning, Joe.

Good morning. Just touching the follow-up on the early question that Jai asked. Understanding, you maybe more conservative in resting in capital investments, would have expected the difference in equity proceeds and cash to have shown up in lower bank debt balances and/or cash balances on the balance sheet. It looks like cash the bank facility the borrowings outstanding there were lower a the end of Q1 than they were at the end of 08 but they’re now back up in mid-April further in the release you added earlier this week. Can you provide any additional details on other capital investments and any other projects of acquisitions, or any other uses of cash in the first quarter that reserves revisions you’ve already disclosed?

I’ll talk about two things, one is we had some additional two wheelers that we had under contract that we had to pay for in the first quarter. That was probably in the range of $20 million to $30 million and secondly, if you look at the page 17 of our press release, you can see our balance sheet there. If you look at the first seven line items, and you look at the difference in those payable balances from December 31st to March 31st there is a decrease from about $301 million and we're around $200 million so, as we wind our operations as the traffic slowdown has decreased or the payables that built up during the higher activity period have to be paid-off and that’s about a $100 million reason for the, where we're with our debt positions as well.

So, I guess, the expectation, the banks debt would be or that I was saying debt would be paid-off with you know half of the proceeds with equity offerings essentially that those proceeds were used to pay down payables that were already expensed last year. Is that one way to look at or other way to look at it?

Well, the proceeds were used to pay down debts and then debt was borrowed back as the payables came due. So, that’s the way I look at it.

Got it, that’s an accurate, I think that’s accurate, so…

Sorry, some of those payables are from last year and some were the first quarter, you know, as we've reportedly spend a $176 million. We incurred a $176 million of CapEx and our discretionary cash flow was $71 million. So, all those factors are why we're where were at with the debt.

Alright

And, really it’s just a momentum thing and as I sort of detailed our CapEx going-forward, you can see that we've had our foot on the break and I think we're going to be bringing that debt at $420 million number or we’ll see maybe a little bit less by the time we get to the end of the year.

Okay, and you spend a lot of time on what’s left in the budget. Can you touch on $70 million in reduced spending and you know Rockies with a tag of $13 million to $14 million in the Permian Basin. What are those activities? Were you specifically pulled-out beyond, will you address that?

You want to tackle that one.

I’ll take a shot at it. In general, in the Permian Basin, it’s been just a kind of a decline in the number of work-over rigs that we're using there. As we wind down the when I say wind down, as we move through the project at the pace that was anticipated, we're just using some fewer work-over rigs out there as we work away through the project and then the Northern Rockies it’s basically just some fewer wells.

Thanks for your comments.

You’re welcome.

Our next question is from the line of Mike Scialla with Thomas Weisel Partners. Please proceed.

Good morning guys.

Good morning.

Is the Hanson well down yet and if so is there anything you can tell from the logs in terms of fitness or proximity compared to the Braaflat well?

Sure, go ahead Mike, we drilled the Hansen roll outs down in the Southwest side of the field, second Three Forks well and we saw encouraging shales when we drilled it and we're in the process, we've kind of started the process of completing it. We don’t yet have, it’s stimulated so we don’t know how it’s going to compare to the first well but we have stimulated the first three stages of the well and so far it has been encouraging, we dream a lot on how the remaining seven stages are going to do?

We're optimistic. It’s – I mean this all looks thick and rich out there. It’s all we can say. So, we don’t have the final result for you yet. We’ll put some fun out when we get a good test on it.

Okay and then in terms of the Braaflat, Jim from your comments, I was wondering are you concerned that that well is drilling from Bakken or is there enough data that you can tell us at this point?

Well, you got to take a look at that well, see, that well was only about 600 feet away from the Bakken well, okay, so, it’s closer than we would normally drill either Bakken to Bakken or going forward Three Forks to Bakken. Both would be spaced roughly 1500 feet apart and so as we go forward here we saw only before I could talk about going forward, when we frac that well, we saw an indication in one of the stages of the frac, we did see communication between what I would call a vertical fracture that runs from Three Forks up into the Bakken, but only one, one out of a ten stages. So, the fact that that happen and it happen and we were able to see that in only one phase, is actually in our opinion an optimistic outcome and as a result, I would say as we move to the West, where the interval between the Bakken and the Three Forks expanse, where more and more optimistic about the Three Forks here being a truly separate targeted reservoir from the Bakken and not subject to drainage one from the other.

Okay. And you also mentioned in your comments about a third well per 1280 in the Middle Bakken and I assume that just to considering the Middle Bakken, that any plans that test that concept this year?

No, not this year. First thing we want to do is drill a part of acreage out there, but I would say we have already proved that concept by the fact that those wells will be essentially the same distance apart, roughly 1500 feet, one from another as they are within each unit. So it just has to do with the setbacks on the leases, one unit from another, that you end up with another 15 with roughly about 3,000 feet and between the well, the southern most well in the unit on the north and the northernmost well in the unit on the south. So it is really the same spacing pattern just being applied across the two unit boundaries and it is really on just the land process where you go in and bring the two units together and the royalty owners and the unit to the north and the royalty owners in the unit to the south share the royalty from the cross unit well, so as required.

So, is the ultimate spacing going to be 640 acres or something less than that?

Yes, slightly less.

And based on what you are seeing right now on the two wells, would that 700,000 to million barrels per well if you don’t see any interface going forward, that would be, you think, a good number to go with on a 640 acre spacing or not.

We do.

Okay.

Thank you.

Thanks.

Our next question comes from the line of David Tameron with Wachovia Bank. Please proceed.

Good morning, Dave.

Please check your mute feature. And at this time, there are no other questions in the queue. I would like to turn the call back over to Mr. James Volker for closing remark.

Thank you Francis. I would really like to underscore the excitement all of us here at Whiting, feel about continuing to execute on our Bakken drilling field as well as our Postle and North Ward Estes CO2 fields. These key projects showing declining completed well costs and operating costs. We are very optimistic about Whiting’s operational results going forward. And I would like to mention several events that Whiting would be participating in over the next several weeks to may give us an opportunity to meet with you personally. We are going to be at the RBC Capital Markets Energy Conference at the Ritz-Carlton Battery Park in New York on Monday, June 1. We are also going to be presenting at the 21st annual COGA Rocky Mountain Natural Gas Conference here at the Colorado Convention Centre in Denver in the week of July 6. We look forward to seeing you at those events. In closing, I would like to thank all of you on this call for your new or continuing interest in Whiting and in particular, I want to express my personal thanks to all of our shareholders, our banks, and Whiting employees and our directors, who have put us in a position to prosper at these oil and gas prices and to respond appropriately to improving, or for that matter, deteriorating oil or gas prices. I think Whiting is in a great position where we are right now. And we look forward to executing for our shareholders. Again, all the best and we look forward to seeing you and speaking with you again soon.

Ladies and gentlemen, thank you all for your participation in today's conference call. This concludes the presentation and you may now disconnect and have a great day.