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Whiting Petroleum Corporation (NYSE:WLL)

Q3 2008 Earnings Call Transcript

October 30, 2008, 11:00 am ET

Executives

John Kelso – Director, IR

James Volker – President and CEO

Michael Stevens – CFO

Chuck LaCouture – VP, Marketing

Mark Williams – VP, Exploration

Jim Brown – SVP, Operations

Analysts

Scott Hanold – RBC Capital Markets

David Tameron – Wachovia

Kevin [ph] – Raymond James

Daeken [ph] – Chelly Asset Management [ph]

Nicholas Pope – JP Morgan

Eric Hagen – Merrill Lynch

Jerry Elan [ph] – Hedge Fund [ph]

Operator

Good day, ladies and gentlemen, and welcome to the third quarter 2008 whiting petroleum corporation earnings conference call. My name is Madge and I will be your coordinator for today. At this time all participants are in a listen-only mode. We will be conducting 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, sir.

John Kelso

Thanks, Madge. Good morning, and welcome to Whiting Petroleum Corporation's Third Quarter 2008 Earnings Conference Call. On the call from 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; and Chuck LaCouture, VP of Marketing.

During this call we will review our results for the third 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 third quarter 2008 earnings release can be found on our Web site at www.whiting.com. To access the call and the Web site please click on the Investor Relations box on the menu and then click on the webcasts 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 under 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 year-ended December 31st 2007. We disclaim any obligation to update these forward-looking statements.

In this call we use the term “probable” and “possible reserves” which are unproved reserves that we do not include in our SEC filings. Please refer to our Web site 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 and on our webcast slides.

With that I'll turn the call over to Jim Volker.

James Volker

Thank you, John. Good morning and welcome everyone to Whiting Petroleum's third quarter 2008 conference call. The third quarter of 2008 marks the very best quarter in Whiting's history. And rather than waiting till the end of the call to thank the Whiting employee team, I want to personally thank them for the planning and execution that went into these wonderful and still improving results. We look forward to discussing those results and to answer any questions you may have following this presentation.

Substantially, all of our production growth in the third quarter and the first nine months of 2008 was organic. Our net production from the Middle Bakken formation rose 48% to 12,420 barrels of oil equivalent per day in September from 8,400 BOEs per day in June.

One of our most recent Bakken producers, the Richardson Federal 11-9H was completed on October 22nd flowing 4,184 barrels of oil and 2.3 million cubic feet of gas per day from the Middle Bakken formation. At 4,570 BOEs per day this is the highest initial production rate recorded to-date from a Bakken well according to the North Dakota Industrial Commission.

Combined production from our two CO2 projects increased 15% to 13,400 BOEs per day in September from 11,700 BOEs in June. Both the Postle and the North Ward Estes field are responding to our water flood and CO2 injection. We expect production rates to continue to increase from both fields for the remainder of 2008 and 2009.

Our net production from the Boies Ranch prospect and the Piceance Basin ramped up to more than 9.5 million cubic feet of gas per day in September, representing a 56% increase from the June average daily rate of 6.1 million cubic feet of net gas production per day.

We also established gas production at our Jimmy Gulch prospect located about 2 miles southeast of Boies Ranch. The Jimmy Gulch federal 397-3G-G1 was completed flowing 4.4 million cubic feet of gas per day from 414 feet of net pay in the Isles and Williams Fork Formations. This opens up 31 additional potential locations at Jimmy Gulch based on 20-acre spacing.

In light of our third quarter results we've raised our production guidance for 2008 to a range of 17.3 million BOEs to 17.5 million BOEs and, of course, we hope to – with up improving results exceed that amount.

Midpoint of this range alone would represent an increase of more than 18% over our 2007 production total of 14.7 million BOEs. Total production in the third quarter of 2008 reached a record 4.64 million BOEs, of which 71% was crude oil and 29% was natural gas. This third quarter 2008 production total equates to a daily average production rate of 50,480 BOEs or a 24% increase over the 40,640 BOEs per day average rate in 2007's third quarter.

The third quarter of 2008 daily average production rate of 50,480 BOEs also represented a 14% sequential increase from the second quarter 2008 daily average rate of 44,200 BOEs. September 2008 average production of 51,700 BOEs per day represented a 10% increase from the June average daily rate of 47,100 BOEs.

The primary contributor to our production increases in the third quarter of 2008 came from new wells in the Middle Bakken formation in the Sanish and Parshall fields in Mountrail County, North Dakota. Since July 1st of this year we've completed 12 significant single lateral Bakken oil and gas producers in the Sanish field. Initial production rates from these 12 wells ranged from 4,570 BOEs per day to 1,298 BOEs per day, averaging about 2,300 BOEs per day per well. We hold an average working interest of 78% and an average net revenue interest of 63% in the 12 new Bakken producers.

We are currently drilling or completing five operated wells in the Sanish field with an average working interest of 86% and an average net revenue interest of 70%. These wells include the company's first Three Forks well, the Braaflat21-11TFH from which we expect results in December 2008.

We're also drilling our first infield well, the McNamara 42-26H well, an approximate 10,000 foot lateral across two 1,280 acre spacing units in the Sanish field. Test results from this well are also expected in December 2008.

We completed construction of the first phase of our Robinson Lake gas processing plant in the Sanish field in late June of this year and the installation of a 17-mile natural gas and natural gas liquids pipeline to Stanley, North Dakota located directly north of our field in August 2008.

Whiting operated net gas sales from the plant are currently averaging approximately 1 million cubic feet of gas per day and NGL sales are currently averaging approximately 130 barrels per day. Whiting expects to complete the expansion of the Robinson Lake gas plant through capacity of 33 million cubic feet of gas per day in December of this year at which time net daily gas sales are expected to approximate 3 million cubic feet of gas to 4 million cubic feet of gas and 700 barrels of NGLs, again, net to our interest.

Net sales are expected to reach approximately 20 million cubic feet of gas and 3,000 barrels of NGLs by the middle of 2010. In the Parshall field located directly east of Sanish, we participated in 16 new Bakken wells during the quarter. The new producers bought our net average production from Parshall to 6,560 BOEs per day in September, up 31% from 5,000 BOEs per day in June.

Moving to our Boies Ranch prospect in Rio Blanco County, Colorado, 15 wells were producing at a combined average net rate to Whiting of 9.5 million cubic feet of gas per day, approximately 1,600 BOEs per day in September 2008 representing a 56% increase from the June average daily rate of 6.1 million cubic feet of gas.

The company holds an average 72% working interest and an average 63% net revenue interest in the 15 Boies Ranch gas wells. As of October 22nd, 2008, four additional gas wells have been completed bringing the total number of gas producers in the field to 19, three wells were being drilled, four wells were being completed and four wells were awaiting completion. Eight of these 11 wells are expected to be on stream by December 2008.

Although the company will not submit its 2008 capital spending budget to its board of directors until later this year Whiting expects to submit a budget in line with the company's estimated 2009 discretionary cash flow. Such a budget is expected to generate double-digit production growth in 2009 based on then prevailing oil and gas prices.

With that I'll turn the call over to Mike Stevens, Whiting's CFO to discuss some of our key financial results.

Michael Stevens

Thanks, Jim. In September, Whiting's Bank Group reconfirmed the company's $900 million borrowing base, which matures in August 2010. The Whiting Bank Group is comprised of 24 commercial banks holding between 1.8% and 6.8% of the total facility. As of September 30th, 2008, approximately, $500 million was drawn on the facility and $3 million of letters of credit were outstanding resulting in $397 million of availability.

In the third quarter 2008 we set company records in production, net income, net income per share, discretionary cash flow and total revenues just as we did in the first and second quarters of 2008. Our net income in the third quarter reached a record $112.4 million or $2.65 per diluted share on total revenues of $388.4 million. During the third quarter we recognized a non-cash, after-tax unrealized gain on commodity derivative contracts of $6.7 million or $0.16 per share.

Discretionary cash flow in the third quarter of 2008 totaled a record $255.6 million, more than double the $108 million reported for the same period in 2007. The increases in the third quarter 2008 net income and discretionary cash flow, compared to the third quarter 2007, were primarily the result of a 24% increase in our total equivalent production, a 43% increase in our realized oil price net of hedging, and a 71% increase in our realized gas price.

During the third quarter, our companywide basis differential for crude oil compared to NYMEX was $10.09 per barrel, which was $0.63 lower than the $10.72 per barrel in the second quarter 2008. We expect oil price differential to be in the range of $9 to $10.25 in the fourth quarter 2008.

During the third quarter our companywide basis differential for natural gas compared to NYMEX is $1.62 per Mcf, which compared to $1.10 per Mcf in the third quarter 2007 and $0.92 per Mcf in the second quarter 2008. We expect our gas price differential to be in the range of $1.00 to $1.50 in the fourth quarter of 2008.

Turning to our guidance for the fourth quarter and full year 2008 our production guidance for the fourth quarter is at a midpoint of 5 million barrels of oil equivalent. Our production guidance for the year at the midpoint is 17.4 million barrels of oil equivalent, which would represent an increase of more than 18% 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'll turn the call back over to Jim Volker for some additional comments on our operational activity.

James Volker

Thank you, Mike. I'd now like to review and move quickly through the slides on our webcast which provide some color on our primary operating areas. First, the photographs on the front cover here, which we're very proud of, that line that you see which we've laid from the gas plant located at our Robinson Lake area in Mountrail County extends north approximately 17 miles and connects to an interstate gas market. That line is now buried and next to it shortly between now and the end of the year we expect to have our oil line laid within the same right away all the way up to the Enbridge pipeline.

Moving to slide number 1, please make note of our forward-looking statements disclosure, reserve information and non-GAAP measures statement paying particular attention to the risk factors in the company's Form 10-K for the year-ended December 31, 2007 and our Form 10-Q for the most recent quarter.

As you can see on page 2, our market cap which was at $1.7 billion based on the closing on October 29th, this moved up smartly today to about $2.1 billion. Long-term debt has not changed in the last day, still at $1.1 billion. Our fully diluted number of shares outstanding about 42.6 million shares. Proved reserves at the beginning of the year 250 million BOEs and 78% of that being oil for an RP ratio of approximately 13.3 years. As we've just explained our September average daily rate – our exit rate for Q3 was 51,700 BOEs a day.

We had a smart, that is 24% increase, very marked increase from Q3 of '07 to Q3 of '08 and we expect a further increase for our guidance in the fourth quarter of 2008.

Mike has already stated as shown on slide 4 that we've just had record earnings, $2.65 a share. And moving to slide 5, $255 million – $255.6 million of discretionary cash flow in the third quarter.

If you look at slide 6 you can see in the total MBOE column there as of December 31 of last year where the 250.8 million BOEs was located, i.e. per region and what percent is oil. Please note that the PB10 values there were calculated at $96 NYMEX and $7.10 per the year end prices at year-end 2007. I will update you somewhat on that when I get to the NAV slide which we've updated and calculated at more current prices.

Moving on to page 7, I really think the key points here are the great growth we're getting, that is the organic growth from the drilling programs in the Williston and the Piceance Basin and the continued growth that we're getting from our two CO2 projects, Postle and North Ward Estes. I'd also like to say that we've had other, although not as significant to the company, but nevertheless nice discoveries in the Gulf Coast and continued success in Michigan as well.

Moving down to page 8, please, I think the key on this page is seen in the far left hand column under MBOEs in the sense that you can see that primarily as a result of our two CO2 projects and the projects in the Williston and other areas in the Rockies. We have 242.7 million BOEs of probable and possible reserves. That simply the total of 87 million and the 155.7 million BOEs.

As to where most of those 242 million BOEs of Peak 2 and Peak 3 reserves are located, slide 9 answers that question. And as you can see 89 million BOEs of those are located in the North Ward Estes field, 62 million at Boies Ranch and Jimmy Gulch and 42 at Sanish and Robinson Lake. We do expect those numbers of course to change. These volumes are as of December 31, 2007.

We've recalculated our NAV for you. Again, we have not updated reserves here. These are reserves as of January 1 of this year; however, we have applied more current pricing that is as of October 23rd and as you can see per footnote 2 those were NYMEX prices of $65 and $6.50 per MMBTU. And as you can tell bottom of the page there including proved that is P1, P2 and P3 reserves NAV is at about $117 per share.

Finding costs on 11. The significant aspect here I think is two-fold. (NYSE:A), you can see from the highlighted numbers on the top line what we did in '04 and '05 was acquire approximately $1.4 billion worth of properties and then in '06 and '07 and now on into '08 we've been using the cash flow off the properties that we acquired to further develop those properties and to be successful on some of our exploration plays. Such that on a fully developed basis we expect including P2 and P3 reserves overall to have a fully developed and acquired cost of about $12 per BOE. That includes the proved.

Currently, what we've invested in it and what we found to-date through this point in time giving us a cost of approximately $12.27. Then the future development cost of those proved reserves without of course any increase in those proved reserves raising it up to about $17 and then bringing it back down as a result of the fact to add the additional $242 million of additional reserves costs only about a total capital expenditure of about 1.7, all in development costs for those probable and possible reserves, and bringing therefore total for the entire P1 through P3 complex down to $12.21.

Page 12, I think these pie chart show succinct that by looking at the center pie chart here that the yellow, the green and the blue sections are totaling about 90% of our reserves come from our three of our core areas, the Permian, the Mid-Continent and of course, the Rockies and that currently approximately 87% of our net daily production coming from that same 90% of our reserve area.

On page 13, an important change from 2007 to 2008 is noted and that the light blue section there has grown from 27% to 59%, i.e. 59% of our now increased budget being $900 million is going toward looking for non-proved reserves.

On page 14 you can tell again of that $900 million budget looking at the right hand pie chart 83% of that is going to combination of the Rockies and the Permian; the 56% less the 27%.

Our debt to total cap on page 15 is down to 38.6% as a result of increasing earnings adding to stockholder equity. And of course, our margins have expanded as a result of the strong oil and gas prices we saw during the third quarter, such that the price per BOE rose to almost $80 and we were netting after lease operating expenses, production taxes, G&A and exploration expense $53.72 per BOE or 68% of that gross BOE sales price.

Importantly, on page 17, I called your attention to two numbers in the far right hand side in the white box. You can see that Whiting has about 400,000 net undeveloped acres. As you know – many of you know about 100,000 of that is in the Bakken in North Dakota, but about 300,000 of that is in the Rocky Mountains.

So, as you look at the Rocky Mountain box kind of keep in mind there in the Rockies Whiting has some other things up its sleeve to the tune of about another 200,000 net undeveloped acres and we hope to be testing that with a drill bit in the remainder of 2008 and into 2009 and we'll let you know how those other prospects work out as they're tested.

On page 18, please, you can see our view of the Bakken here. We've outlined the limits of the Bakken on the left hand side of page 18. We've shown you where Elm Coulee was where we originally began, but did not have a large interest. Looking for conditions that were similar to Elm Coulee, we landed on an acreage position at Sanish and at Parshall whereas you can see on the right hand side of page 18 we think the zone, the Middle Bakken zone is in active oil generation and in the expulsion phase.

As we move on to page 19 you can see what we're doing in our portion of the Parshall/Sanish area in that we're drilling horizontally and having multiple frac and then fracing in multiple stages within the dolomitic portion of the Middle Bakken. That's what's responsible for these great rates that we're getting which on page 20 you can easily see as we've outlined them there from the east side to the west side of our acreage position, such that as of October 22nd at Sanish we had 36 producers, Parshall had 69, we were completing four, they had 12 waiting on completion, we were drilling seven over there, the operator in Parshall was drilling five and obviously, we had a number of AFEs out and approved and to stay ahead of our plans.

Moving to the top of that map you can see there where both our oil and gas line have been in the case of our gas line and will be in the case of our oil line laid for approximately 17 miles north respectively to the gas market and the oil market.

On page 21 you can see in the lower left hand portion the number of wells that we think we may be able to drill here. As you can tell essentially looking at all of these lines essentially the gray lines being the ones going forward and the other colored lines being ones that we're already active on. They total for both operated and non-operated about 180 wells.

In addition, if we were to be able to down space as we've begun to do and are attempting to do as I speak to you here, we could add perhaps another 60 operated wells in that pattern indicated by the red dash lines, for our operated properties and about 52 for our non-operated properties. So that could bring our total here for the Middle Bakken alone, not including the Three Forks to about 292 potential wells.

Page 22 I think is an impressive page by virtue of the fact that not only it shows all 21 wells that we have drilled and completed so far, but most importantly that after 60 days of production the average is still over 800 barrels a day flowing.

We've updated our type curve on page 23 such that we think the type curve currently represents right at about 700, that is 691 MBOEs or 691,000 barrels of oil equivalent for a typical type curve in this area.

Our budget for 2008 is broken out for you on page 24. As you can see the Bakken represents 37% of that particular budget. And meanwhile, our Midland office is handling approximately 36% of our budget, so those are obviously the two largest areas. The northern Rockies in total being Sanish, Parshall and a few other activities we have going on represents about 42% and the Central Rockies represent 14% of that budget.

Speaking specifically on page 25 about the Piceance Basin you can tell by the highlighted line there that there is an opportunity to drill 109 wells on 20 acre spacing and 76 additional wells are currently planned on 10 acre spacing. So we're very happy with the results that we've incurred to-date. Those results are laid out for you on a well-by-well basis on page 26.

We've shown you the IPs of wells drilled to-date and as of October 22nd we were drilling three, completing four, four were waiting on completion and 19, we're producing.

Moving to page number 27, I think it's now important to note about our CO2 projects that as you can see in the upper left hand corner of page 27 the middle column there entitled Postle and North Ward Estes that the September net daily production there of 13,400 BOEs per day. That combined with our net daily reported production from the Middle Bakken.

Those two areas currently represent approximately 50% of our net daily production. And Postle and North Ward Estes as you can see in the far right hand column as to reserves represent 49% or approximately half of our reserve base, that is approximately 123.9 million BOEs.

Page 28, ladies and gentlemen, is a great slide I think because it shows why we elected to acquire and then put the capital that we have into North Ward Estes and Postle. And in summary, as you can see we think when fully developed including P2 and P3 reserves our acquired and fully developed cost will be in the range of around $10.62 per BOE.

Moving forward and looking at Postle and our plans going forward you can see that as of January of this year we had plans to execute through 2010 that would total about $259 million, but as you can see of that over half of it $152 million is simply the cost of purchasing the CO2 that we have under contract.

Page 30 shows nicely what's happened to production as it approaches 7,000 net BOEs per day, net to Whiting's interest, up from about 4,600 BOEs per day in March of last year.

Moving on to the North Ward Estes field, which as many of you know is approximately 23 miles long and 3 miles wide. We have that divided up into five different phases. Phase 1 is essentially complete and is currently producing about 3,200 BOEs per day. We're injecting a little over 100 million cubic feet of CO2 per day into that reservoir.

Our Phase 2 well work, facility work is under way. Water injection began this quarter and we plan to start CO2 injection in the first quarter of 2009. The plans for the rest of the flood are laid out as you can see in terms of the injection start date on page 32. And again in the lower right hand corner of page 32 you can see that in terms of going forward over half of the estimated CapEx going forward is for CO2 purchases alone. So in terms of the execution phase here we're definitely over the half way point.

Page 33 shows nicely sort of model here quarter-end to quarter-end BOE production in the net BOEs. As you can see North Ward Estes is approaching 7,000 BOEs per day net.

We've shown you how that has occurred and essentially the light green line at the top of page 34 is a combination of the sort of gentle decline curve there that's in the form of the other existing wells. The Phase 1 new drilling that has occurred and then the decline on the newly drilled wells. So that you can see that the effect of putting that area on to the CO2 flood and has got us up as you can tell to where we're approaching 7,000 BOEs per day net.

I think it's important now to look sort of at pages 35 and 36 simultaneously here because it makes a good point. And that is that our independent engineering is based upon cumulative recovery factor of only about 5% here that has been called our proved reserves in the area. And as you can see by the green line in the lower left hand corner of page 35 production is rising markedly above the forecasted level.

And as a consequence, now turning to page 36, if we are able to get it up, I would have you read on the left hand side scale of this page, we can raise our recovery factor to say 8% or 12% then we'll end up with total reserves including what our currently P2 and P3 reserves of approximately 162 million BOEs.

I would like to add proudly now point out the state-of-the-art facilities that are in the North Ward Estes field where we monitor 24/7 the rates and pressures of both injection and production. That is of both oil, gas and water. And then our reservoir management team which is involved in the 24-hour surveillance meets every two weeks in order to tweak those areas that need to have pressure changed or volumes changed in terms of our injection in order to maximize the recovery from that field. As a result in total on page 39 you can see that again the 13,400 BOEs a day we've spoken of before from in combination our total North Ward Estes and Postle fields.

Where we are headed for those, well, we think as shown on page 40 that production from Postle should rise to the range of around 8,000 BOEs to 9,000 BOEs a day net. We're obviously becoming much more confident of that since we're already in almost 7,000 BOEs a day net. And so that's looking good. North Ward Estes, of course, being earlier in its response to the water, flood, reactivation and installation and the installation of the CO2 flood has further to go, but we're very pleased with the initial reaction to the CO2 flood as I previously showed you there on page 35 in which initially anyway the response to the flood has been excellent.

We're not hedged very much right now unfortunately and I will take the blame for that. Just didn't expect the credit crunch here to have this much affect on oil prices, but we are hedged on our trust. And as a consequence, I think the investors in our trust can take some comfort from the fact that we have approximately 30% of the production hedged there at prices with floors of about $75 on oil and about $6.50 on gas and the opportunity to participate on the uptrend in prices to approximately $135 on oil and about $15 on natural gas.

(inaudible) continues to execute on our formula for success of acquired exploit, explore. We have monetized some reserves and tend to do that from time to time, perhaps continuing with our royalty trust plan as we move forward. And we've been successful, of course, we think in having good results not only in the sale of that particular security, but also then in the results that we produced with the holders of those securities.

So, with that, operator, I'd like to open up the conference call for questions. Thank you very much.

Question-and-Answer Session

Operator

(Operator instructions) And your first question comes from the line from Scott Hanold from RBC Capital Markets. Please proceed.

Scott Hanold – RBC Capital Markets

Thanks. Good morning.

James Volker

Good morning, Scott.

Scott Hanold – RBC Capital Markets

Some pretty nice results out therein the Bakken. Can you give us a little more insight? I know you were all involved in a consortium out there. Was there anything different about the drilling or completion on that well that would have led to such a great result? And is there any indication that this 4,600 barrel a day well may not be the only one out there or could results get better?

James Volker

Well, as you know we've been – our team, I believe is well schooled in the method that we have developed. I'd like to thank our partner over at Parshall, EOG, for sharing information with us and other operators in the area for sharing information with us. And we've tried to reciprocate. We think we do have a method that's working very well for us. Obviously, we're drilling these wells on 1280s. We're getting approximate 10,000 foot horizontal out there. We're concentrating on conditioning the hole prior to the time that we run that assembly in the hole that allows us to do the multistage fracing.

And I'd like to compliment our Northern Rockies team for the way that they have executed there. I think it's – lot of it has to do with, I guess I'd say, the way we are able to oversee the drilling of the wells, the kind and quality of equipment that our drilling team, drilling department has brought to work out there in the form of three different drilling contractors with the appropriate equipment for the area and then our collaboration with Halliburton on the way we're fracing those wells. So, I think all of that is important. I don't think we're doing anything that anyone else couldn't do. I just think we're being careful in the way that we're executing there and the results are, in my opinion, and I answered your question I hope, repeatable.

Scott Hanold – RBC Capital Markets

Okay. So, particular with that well, there was nothing you did any different than other operators are doing in and around that same area, is that correct?

James Volker

Yes. I'd like to say that I think we were obviously one of the first to try the 1280s. I think we have our – the way in which we drill these things down, the manner in which we do it honed, but other people could do the same thing. And I think some of them now are doing it. They're going to be drilling on 1280s and I think they're going to have good success as well.

Scott Hanold – RBC Capital Markets

Okay. Was there anything particular with this specific well that it was so strong? You've obviously drilled a number of wells and sounds like you've used similar types of care in drilling the wells. Why do you think this one was so big relative to some of the other ones you've drilled recently?

James Volker

Well, I guess I'd like to say that I think in actuality, there were other wells that we drilled here that could have tested as high a rate as this one. And it's just basically has to do with how many facilities you put out there in order to have available to flow into. So, in this particular one, we did have a larger number of tanks out there available to flow into. Although I would say also that I believe that not only in other wells that I've just mentioned that could have had a higher IP this well might have even had a higher IP should we – if we had allowed to let it flow to a point that we were getting back less load water and more oil. So, obviously, when we frac we're going to get back part of our load.

So, in the past, I would say and even on this well we've been somewhat limited by the tanks that we have. We bought our own tanks out here so we could flow these wells back, but at any rate we set up enough tanks that we could allow this one to flow a little higher. But as you look down the list there you'll see some of the bigger wells I think probably could have flown – been flowed at a rate similar to this. So I'd say that it's not that this one is so much better than the others, but that the others were somewhat restricted by the facilities on location at the time.

Scott Hanold – RBC Capital Markets

Okay. And then so what would you say kind of going forward? Would you expect to have adequate capacity to open up the other wells as much going forward or is it going to be a little bit here and there?

James Volker

Well, I think the wells – the important thing about I believe at this point is to not very open up and then choke back and open up and choke back, et cetera, your wells. I think it's important to let them flow at a relatively stable choke size over an extended period of time so we get an idea about how much they're going to decline and how pressure will decline. So, I think that's the most important thing for us right now. The market for oil is tight out there; by that I mean take-away capacity. I'd like to compliment our marketing team which has arranged for seven different markets.

And essentially other than shown in the footnote there on page 4 of our press release where we had a couple of wells where we say they're somewhat restricted as a result of take-away capacity and maintenance at the time that was being done on the Enbridge line, I think our marketing team has done a yeoman effort there and that's why we don't have many wells there awaiting completion. We have been able to sell virtually all of the production that we have been able to produce. So, kudos to our marketing team and I think that just underscores why we want to be in control of our own destiny here. That's why we're laying our own line 17 miles north to Enbridge.

Scott Hanold – RBC Capital Markets

Could you give us a little more color on that line take-away capacity? Remind me how much take-away that's going to give you in the Sanish area? And also what does that mean for operating costs because you're not trucking it as much? Would that obviously improve the operating cost aspect going forward as well?

James Volker

Right. Okay. There's several questions there. First of all – and thank you for asking, Scott, the 65,000 barrels a day is the capacity of that line that we're laying. Currently, the capacity of Enbridge to take crude in that area is about 35,000 barrels a day. Second, we expect Enbridge to be up to about 65,000 barrels a day by the time we get out to the end of next year, say, December of 2009 or January of 2010. So, we're building a line there that has enough capacity. I want to underscore that I'm not telling you that we think we're going to have 65,000 barrels a day of gross oil production to put down there. We do have plans – I'm not prepared to say what, but we hope to use a very large portion of that. I will say half or more for our own production and that would be out of the Middle Bakken alone without talking anything about the Three Forks. But that's still subject to a lot of what I would call risk.

So all I can say about that as we build a line there with plenty of capacity to get crude up to Enbridge. And we believe that Enbridge is taking the steps necessary to take all that crude from us and we build a line there such that if we're not using it all, other people – we can transport other people's crude up that same line. We've been approached by a number of crude oil purchasers who want to own that line either with us or exclusively who would purchase that line from us and then give us virtually first call on any production through the line. So, we're evaluating that opportunity as well. I'll let Jim Brown and Chuck like to – I'd like to have some other people talk during this period of time and I'll let them talk about essentially the difference between the, say, discount to NYMEX that we will see currently as a result of trucking the barrels out versus when we start the crude oil down that line. Chuck?

Chuck LaCouture

Hey, Scott, good question. Obviously, and especially in the winter the trucking can be an issue up here. It's also expensive and as Jim mentioned earlier when we bring these wells on at high rate it's always a contest to get enough trucks in there move, not only have their enough facilities, but also have enough trucks and there to move the crude. When this line is complete obviously that part of the equation is removed and not only will we see substantial reduction in the cost of getting the barrel to Enbridge, but also any pipe barrel is seen as a more favorable barrel into the pipeline as opposed to going through a truck unloading facility.

James Volker

Having said that, let's just talk about the dollar amounts of essentially the trucking costs versus what we think we're going to get through it when we are connected to Enbridge.

Chuck LaCouture

Roughly, it would be half. Our current trucking facilities or trucking costs up to that point are around $3. Obviously, that depends a little bit on the cost of diesel which is a fuel surcharge. And then once we have this line in place and operational, that number will be in half or less.

James Volker

Thanks, Chuck. I hope that helps, Scott.

Scott Hanold – RBC Capital Markets

It's a lot. I appreciate your time.

James Volker

All the best. Thank you.

Operator

And your next question comes from the line of David Tameron from Wachovia. Please proceed.

David Tameron – Wachovia

Hi, good morning. I would echo the congrats on a nice quarter.

James Volker

Thanks, Dave.

David Tameron – Wachovia

Couple questions. If you look at the '09 and you mentioned the stay within cash flow. What type of – and you're still processing double digit fracture growth, so there must be some number in your mind that you're thinking about oil prices? Do you want to give us any indication of what that might be?

James Volker

First of all, I'd like to say that for really the last quarter we've been preparing for our 2009 drilling program. We have budgets that run all the way from $84 crude down to $54 crude. We think it's more likely that it will be in the $64 crude to $74 crude and $6 gas to $6.50 gas. So, our best guess is we're looking at budgets at $74 and $6.50 and $64 and $6.00 and under those budgets are exploration and under those oil and gas prices our budget would be in the range of $700 million at the $74 and about $600 million at the $64 oil price scenario. And those would both be – those CapEx numbers would both be under our discretionary cash flow.

David Tameron – Wachovia

Okay. That makes sense. And either of levels you could generate double digit production growth?

James Volker

Yes, I would say at the lower level we would be we think in the low to mid teens at least in production growth and at the higher number, the mid to high teens or perhaps even a little higher.

David Tameron – Wachovia

Okay. Those are good numbers. Thanks. If I think about the Bakken, our models show that this play works down to $45, taking a 50% discount for differentials. But at $45 you get 10% rate of return. Is that – are those good numbers? Have you got good similar type numbers? I'm trying to find out if there's a downside on the price threshold.

James Volker

Yes, well, I guess I would say it if you don't mind I'll use – I think we could drill here all the way down to $50. I'll just tell you why. So, $45 is not too far away from that, so I guess I'll agree with you. But at $50 we'd net about 60% of that or around $30 and if we're getting 700,000 BOEs that's about $21 million in future net revenue here for a well cost in the range I think of around – I think drilling costs would continue to come down a bit. But let's say even if they stayed at around $7 million that's still a pretty solid three to one on your money and a pretty quick payout. So – I don't want to get into the IRR thing with you right now.

David Tameron – Wachovia

That's fine. That gives me some range. Let me ask another question. You said (inaudible) 20 play but the hedging what – going forward in 2009 any change in philosophy assuming we get some rebound in oil and how do you look at it going over the next 12 months to 18 months?

James Volker

Yes, I would – certainly, as oil prices rise you may see us – you might see us layering in some hedges as we go forward. Obviously, we missed it here. And I can tell you that we did talk actively about it in the short period of time there that it was possible to do $100 floors and something approaching $200 ceilings. And but at the time we were unaware that the credit crisis was going to cause lot of things to fall out of bed here for a period of time. I blame myself for that because ultimately I'm the final decision maker on that.

David Tameron – Wachovia

Okay. And then one last question. Well costs in the Bakken, what are they currently running at?

Jim Brown

This is Jim Brown. They're currently running $6.5 million to $7 million per well and we're expecting those to go down. Steel prices have already headed down. We expect service costs, fuel – all the fuel charges will start down.

David Tameron – Wachovia

Okay. What type of lateral does that assume, Jim?

Jim Brown

That's a 10,000-foot that's drilling on a 1,280 acre space unit.

David Tameron – Wachovia

Alright. I'll jump off and let somebody else ask. Thanks. I appreciate it.

James Volker

Thank you.

Operator

And your next question comes from the line of Kevin [ph] from Raymond James. Please proceed.

Kevin – Raymond James

Good morning. Congratulations once again on the strong results.

James Volker

Thank you.

Kevin – Raymond James

I have a question on your Three Forks Sanish test. I know you talked about joint two different test wells. Can you elaborate and which, I guess – one close to the Bakken and then one further away, I guess, from a well that you've already drilled in the Bakken formation. Are you still planning on drilling both of those? Which one are you drilling right now?

Mark Williams

I'm not sure exactly which ones you're referring to, but with the two – this is Mark Williams. I'll try to address that. The two that we have talked about most recently here are the Richardson Federal, the Canyon [ph] wells and those are shown on the map on page 20.

James Volker

He wants to know about the Three Forks.

Mark Williams

The Three Forks, well, there's actually two of them. One of them is over here in the east side of our Sanish field area. If you look on the map on page 20 you can see that as well. The Braaflat 11-11H well and that well – pardon me, it's the one immediately adjacent. It's the Braaflat well, the red one, it's the second well within that 1,280, but targeted specifically at the Three Forks, whereas the first well in that 1280 is a Bakken well. And so we're still in the process of drilling that well. We're approaching TD right now and then we have another Three Forks well that's plan that's over on the west side of our acreage block here. And that well is soon to spud. It's well called the Hanson [ph] well. And we'll be drilling that here and completing it sometime around the end of the year.

Kevin – Raymond James

Okay. And the Hanson well is going to be away from a Bakken formation or Bakken producing well, right?

Mark Williams

That's right.

Kevin – Raymond James

Is that where you'll be able to test the two different flow rates?

Mark Williams

Right. We're going to be – it will mostly be an attempt to determine whether there's any significant pressure differential between the Braaflat, which is essentially drilled closer to a Middle Bakken producer and the Hanson, which is drilled away from a Middle Bakken producer.

Kevin – Raymond James

Got you. Now, are you going to need both well results? It sounds like you'd need both well results before you'd be able to say anything really conclusively or do you think you'll know something with a Braaflat well?

James Volker

I think we – we don't see what I would call a sharp drop-off in production as we produce the Braaflat, then I'd say we'll be encouraged. And then, of course, if we get the Hanson well and it's at approximately the same pressure and if there's not too much difference in pressure, why I'd say then we'll feel good about it. We have some preliminary data from the micro seismic that we've done in the area which tends to indicate that the frac wings that we've put out when we do these multistage fractures may go out horizontally about 300 feet and vertically 100 feet or little more. And as a consequence of the fact that the Three Forks is typically 75 feet or more as we move from east to west on our acreage below the bottom of the Middle Bakken that we're completing in, we feel that we may be in a geologic situation that will insulate us either entirely or somewhat from depletion of the Three Forks by production out of the Middle Bakken. That's what our hope is.

Kevin – Raymond James

Okay. Great. Now when do you think you'll have the Hanson results?

James Volker

End of the year.

Kevin – Raymond James

Okay. One other question. On your tight curve – or type curve what IP rates are you assuming? Just looking at the chart it looks like 1,000, but I realize that's the first day.

James Volker

Well, it's the 30-day rate there, which as you can tell is still up there at about 900 barrels a day.

Kevin – Raymond James

Okay. And so, that's what – I know you said on your last wells you've averaged over 2,000. Does that kind of equate to a 900 30-day rate?

James Volker

Yes. Right. If you take a look at page 4 of the news release or page 22 of our slides here you'll see that the average 30-day is 941 BOEs a day. So, that's we've started the type curve.

Kevin – Raymond James

Okay. That make sense. One other question. On your Piceance assets, I know there's been a lot of talk about rigs dropping off in that area, not with you guys, but with other producers. Are you seeing any softening in service costs there? And what kind of gas levels or what type of economics do you think you're making right now at these price levels?

Jim Brown

This is Jim Brown. We haven't seen any drop-off in rig rates yet just because we had, the rigs we're drilling with out there we had all tied up into long-term contracts. But some of those contracts are coming due in 2009 so we're expecting those rig rates. Hope there's some drilling contractors on line. We're hoping some rig rates are going to be dropping. It's the same thing also for our fracs. We had bid our fracs out for a year at a time out there and we're in the process of rebidding all of our frac work out there as we speak.

So, we're expecting some drop-offs in there. I guess right at today's gas price right now we're seeing somewhere in the 2.5 to 1 type on our money with what we're drilling out there. We are expecting to see a rebound in gas prices. I just wish we would get cold somewhere in the United States. I mean we're to be 70 some here in Denver today, so we're expecting a rebound in gas price through the winter and heating season to get our returns back up to what we normally see on our 3, 3.5, 4 to 1 on our money, et cetera.

Kevin – Raymond James

Okay. Great. Is there a dollar amount to run the numbers of where you might want to back off or you're comfortable right now?

James Volker

I think the drop down gas prices could go a little below $5 and we probably – we wouldn't want it to stay there very long, but we probably keep drilling at $5. Keep in mind here that the normal numbers that you think about don't really apply because we're not paying any royalty here. Remember, in this Boies Ranch area we own the minerals. So, we own in most of these – in the areas, for example, where we own a 50% working interest, we own a 49% NRI. So, you're really only subject to roughly, call it 20% for operating expenses and production taxes here. So, that's definitely helping our economics.

Kevin – Raymond James

Great point. Thank you for the answers and I'll jump off.

James Volker

All the best. Thanks again.

Operator

And your next question comes from the line of Daeken [ph] from Chelly Asset Management [ph]. Please proceed.

Daeken – Chelly Asset Management

Gentlemen, this Middle Bakken is a dolomite, isn't it?

Mark Williams

Yes, the Middle Bakken changes from the west side of the Sanish field as you go over into Parshall field. The zone we're drilling in is a dolomitic sandstone in the Sanish field. You can see it depicted on one of the graphics we've got in the Power Point on page 19 what actually is happening there. That reservoir has good matrix ferocity so in addition to the fractures that we normally encounter in this area there's actually a matrix reservoir here that we're drilling in. As you can see in that graphic there actually thins and pitches out as we get towards the east side of Sanish field.

Daeken – Chelly Asset Management

The dolomite tend to have big spots of ferocity I believe and can be depleted quickly. That's why I wondered. Does the fact that there's sandstone in there make a difference?

Mark Williams

Yes. Dolomite is really there in the form of cement within a matrix reservoir which is the sandstone. And so – these – all this Middle Bakken is not like a conventional reservoir that you would normally expect. We think that we're also getting significant contribution from the Bakken shale itself. And so, while there's multiple components to the reservoir here there is regional tectonic fractures, there is ferocity within the upper and lower shales of the Bakken and then there's a matrix component in the dolomitic sandstone, but I don't want to emphasize – overemphasize that part of it. It's distributed through this whole interval.

Daeken – Chelly Asset Management

That would be interesting to see how the production holds up on these wells.

James Volker

We're optimistic because as we look at the decline curves initially, preliminarily, early on, we think that the wells at Sanish are breaking over, i.e. flattening out somewhat earlier than our wells in Parshall.

Daeken – Chelly Asset Management

Thank you.

James Volker

Thus the benefit of the reservoir matrix. And you're welcome and thank you for asking a good question.

Operator

And your next question comes from the line of David Tameron. Please proceed.

David Tameron – Wachovia

Hi, Jim. Couple follow-up questions.

James Volker

Sure.

David Tameron – Wachovia

In the Piceance it looks like you guys updated your 10 acre spacing location since the last presentation you had out. Went from 32 to I think you had 76 in today's. Can you talk more about what the changes there or why the change?

James Volker

I'll try to be succinct here. At least when you stare at that map of the Piceance that we have put in there for you. At least over there we think what we call the Middle East which would sort of be the eastern side of that long, narrow acreage position. Our results have been such that – without going into too technical, I guess an explanation here. It's pretty well indicates to us we can drill there on 10 acres and – because we're getting bigger wells, we're getting better wells, we're not seeing much in the way of interference on the 20 acre spacing. So that's why preliminarily here we have said essentially at least part of our acreage we believe should be drilled on 10 acre spacing. And as our drilling continues here there may be more of it that we add to the 10 acre spacing area.

David Tameron – Wachovia

Do you have a feel for – I guess you do, but how much of that's on the lower interest and how much of it's on the higher interest working property as far as the additional locations?

James Volker

Well, all of those locations, all 76 currently would generally be in an area where we would have roughly somewhere between a 50% and 80% working interest.

David Tameron – Wachovia

Okay. Alright. Let me ask a question about the Eunta [ph]. Maybe I missed it, but I didn't hear you talk about it. What are the current plans there with the Flat Rock?

Mark Williams

Right now we have – we're just – we're in the process of drilling our second well at Flat Rock and while we're not really giving out lot of details on our '09 budget right now we'll continue to drill at Flat Rock through the end of the year and we have a number of additional wells identified for 2009 that's going to really depend on our budgeting process right now how many of those we end up getting drilled.

James Volker

But so far we're very encouraged by the results that we have had drilling on our 100% ownership acreage at Flat Rock. And we've got one down and we're in the process of completing in the Entrada now so I don't have a rate for you, but I can tell you we're very encouraged by the amount of pay that we see on the log.

David Tameron – Wachovia

Okay. Alright. And then one final question. If I look at 2007 oil prices, $95, if you project out a number, say keep it flat with the current month and say it's somewhere in the mid – or it's $70 at the end of 2008. Do you anticipate – but two questions, one, do you anticipate any reduction in reserves related to the lower oil price as compared to a year ago? How much – is there tails that fall off or? Can you talk a little bit about that? And second, any indication at this point of what 2008 reserve growth looks like?

James Volker

I don't want to talk about reserve growth yet in 2008 in finality, but I would say that our best guess currently is that although oil prices may be lower versus the year end 2007 that the pluses and minuses will more than even out. I guess I'd say we would hope that the plusses would be bigger than the minuses, meaning net of production and net of any problems that we might have with lower oil prices. We're still hopeful that we'll see a meaningful add to our net reserves.

David Tameron – Wachovia

Alright. Thanks. That's all I got.

James Volker

Great. Thank you.

Operator

(Operator instructions) And your next question come from the line of Nicholas Pope from JP Morgan. Please proceed.

Nicholas Pope – JP Morgan

Good afternoon, guys.

James Volker

Hi.

Nicholas Pope – JP Morgan

Quick question, looking at your CapEx budget, I guess whenever you're talking about cutting back here, what areas are we even looking at that, that could see the reduction in CapEx, I guess, year-over-year?

James Volker

Well, I guess I'd say there's a couple ways I could probably answer that for you. But – how about if I say what areas I guess I'd say we're not going to see much of a cut. Obviously, we're not going to – here's the way I'd like to answer that question. Let me pick, say, a $700 million budget case, which would be based upon like $74 crude. And I'll compare that to a $64 case and a $600 million drilling budget. Sanish would still get about $300 million in both cases. North Ward Estes would get about $150 million at $700 million case and about $122 million to $125 million at the $600 million case. The Piceance would probably get about $86 million at the $700 million case and on the $600 million case it might get cut to about $46 million. Flat Rock might on the $600 million case might be at about $14 million to $15 million, at the $700 million case it might be about $33 million to $34 million, Postle probably about the same in the range of around $55 million to $60 million on both cases. Parshall about the same, around $25 million to $27 million on both cases.

There's some exploration that we might do on Red River at the $700 million case and not do at the $600 million case. There's some sort of exploration work in one of our Permian fields to the tune of about $2.5 million that we would probably do at the $700 million case and not do at the $600 million case. So – and then below that I would say there'd be roughly a smaller percentage spent in the $600 million case on Wilcox drilling in South Texas, perhaps some exploration drilling for gas we have on held by production acreage so it certainly wouldn't hurt us to put that off a little bit. In West Texas there might be some other land and exploration work that we would put off on exploration targets that we identified in the Permian.

If you look at our acreage map there's an acreage area there called Hatch Point in southeastern Utah. There we might spend say about $5 million at the $700 million case and around $3 million at the $600 million case. Along the Gulf Coast we might have about $3 million of what we call Gulf Coast other, which is some predominantly expanded Wilcox plays and other things that we have in mind that would maybe go down from around $3 million to around $2 million.

There's a couple other cases, couple other plays along the Gulf Coast in the northern Rockies and central Rockies where things would be about between a half and a third less. I've kind of been through the entire list with you there. I kind of prefer to answer that question in comparison to what we see going forward versus what we did in the past. So I think that's more – hopefully, that's more informative for you as you think about what we would drill versus what we would not drill.

Nicholas Pope – JP Morgan

That was exactly I was looking for. Another question I had just looking at production numbers it looks to me like just fourth quarter midpoint guidance held flat over 2009. Is it already brings you up to about 12% year-over-year production growth? So – is it – is that right? It seems like you're being a little conservative whenever you're giving some of your production numbers for 2009, am I crazy?

James Volker

No, you're not and we hope so.

Nicholas Pope – JP Morgan

Okay. And then I guess just real quick I guess, kind of conditions in the Piceance getting gas out. You kind of mentioned you were working around some of the REX issues. Can you kind of – what kind of pricing have you been seeing with your Piceance gas? How do you think that's going to be looking going forward like fourth quarter?

James Volker

I'll answer the first part and I'll let Chuck or Jim, whoever wants to answer about the gas prices going forward. We're lucky ducks in the view of where our acreage is located. We're lucky ducks because we laid our own line that connects directly to Enterprise to Boies Ranch. We only had to lay about a 3 mile line. It's got 80 million a day capacity, so from our current production there is no capacity restriction on our line nor the three quarters of the Bcf a day line capacity that we're connected into which is owned by Enterprise. Likewise at Boies Ranch we're connected essentially into that same three quarters of a Bcf a day Enterprise line that runs right through Boies Ranch. You can see that on our map there, which is on page 26. So we feel good about the take-away capacity. I'll compliment our marketing department for reacting such that we were not restricted even when REX was undergoing the hydra testing issue.

So I feel good about the take-away capacity. I'll also mention that in addition to this sort of three quarters of a Bcf a day capacity that Enterprise had recently – they're essentially as we speak bumping up their capacity to 1.5 Bcf a day. So I see them having the capacity to handle all our gas for the foreseeable future. Chuck, do you want to comment on the price?

Chuck LaCouture

Sure. As Jim mentioned we tie into a 36-inch main line that delivers into their processing facility so not only are we receiving index around CIG index pricing, but we're also receiving by virtue of going through the processing facility a significant uptick via the NGL upgrade. So, they mean, Enterprise, have a second train which Jim mentioned of 750 million a day addition of processing facility that will give us continued access to great markets and great pricing uplift via the NGL.

James Volker

Help him out in addition to the fact there we're getting CIG index, why don't you tell him what we're getting kind of a bump per Mcf we're getting out of the NGL.

Chuck LaCouture

Yes, at current pricing scenarios it's about $0.50 per M uplift.

James Volker

We hope that helps you.

Nicholas Pope – JP Morgan

Certainly does. That's all I had. Thanks guys.

James Volker

All the best. Thank you.

Operator

And your next question comes from the line of Drew Wenker [ph] from Merrill Lynch. Please proceed.

Eric Hagen – Merrill Lynch

I wish I were Drew Wenker. It's actually only Eric Hagen.

James Volker

Okay. Good. Hi, Eric.

Eric Hagen – Merrill Lynch

Hi, there. Couple quick questions. The two exploration projects you mentioned in the Rockies, I think one was Hatch Point, I think the other one was Hattrick [ph]. Are those gas, oil? Are they sort of oil expulsion type plays like the Bakken? Can you broaden any color on that? And do you have any partners in those or?

James Volker

Well, the answer is they're both horizontal plays for oil. They're both centrally, primarily horizontal plays for oil. The Hatfield play in southwest Wyoming also has a vertical element to it for two other oil reservoirs.

Eric Hagen – Merrill Lynch

Okay. And do you have a partner in either of those plays or is this Whiting generated entirely here?

James Volker

Well, the good news is that with respect to the Hatfield area we control an area there that's about 85 miles, 85 square miles, and within that area our working interest will range we believe from 100% to 65% on the low side, primarily we think more on the – toward the higher side. With respect to the Hatch Point area, things are still in the bit of a flux there, but we'll have a minimum of about 56% and that may rise up to about 76%.

Eric Hagen – Merrill Lynch

Okay. Any idea that the timing of some results there exploration results next year, end of this year?

Mark Williams

Well, at Hatfield, we're currently drilling a well right now. It's public knowledge. We'll be down on that well here very shortly. We're planning to follow that up with another one. So I think we'll probably in a position to release some results on that towards the end of the year. At Hatch Point, we're still working through some regulatory issues for our first well there, but we plan to drill that well early in 2009.

James Volker

I'll try to give you a little bit more color on Hatfield. I don't want to be specific about the zones yet, but you can think about it as having three potentially productive zones and the bottom two being sort of vertical, the bottom one being a vertical target, the middle one being a horizontal target and the upper one being a horizontal target. So once we drill the TD then we'll have some decisions to make based upon what the log shows as to whether or not we're going to try to complete vertically in the deepest zone, go horizontal in the middle zone or go horizontal in the upper zone.

Eric Hagen – Merrill Lynch

Great. Thanks. And I just one other follow up. The NAV estimate you provide, Jim, in the presentation, the probable and possible, are those also engineered by – is it Colly Gillespie [ph] at your end?

James Volker

Yes, Colly Gillespie, and the answer is yes.

Eric Hagen – Merrill Lynch

Okay. And that's just the standard SEC methodology, the same thing you'd see in a standardized measure or a PD 10 like calculation?

James Volker

It is with respect to the proved reserves and then it meets the SPE definition of probable and possible.

Eric Hagen – Merrill Lynch

Great. Thanks, Jim. That's all I had.

James Volker

All the best, Eric. Thank you.

Eric Hagen – Merrill Lynch

Likewise.

Operator

And your last question comes from the line of Jerry Elan [ph] from Hedge Fund [ph]. Please proceed.

Jerry Elan – Hedge Fund

Hey, guys, I just had a couple quick questions if you can help me out please.

James Volker

Sure, Jerry.

Jerry Elan – Hedge Fund

I'm on that Sanish field and when I look at these numbers you write on your page 3 of the release going from the initial IPE to the 30-day and then 60-day. I correct calculating decline rate going from the 30 day to 60 day looks like it's going down at the rate of 6% from – taking the wells that are active.

James Volker

Well, if you – I'm looking at essentially page 4 of the news release and that's where the average – that's the one I'm looking at – it's 804 versus the 941. So, in that 30-day period it declined about 15%.

Jerry Elan – Hedge Fund

15%. Is this – is there a point where it stabilizes or not?

James Volker

The best answer I can give you there, Jerry is to go, take a look at our type curve to see how the thing bends over. And our type curves on page 23 of the slide presentation. So, what happens here is that we think in the reservoir is like this. The rate of decline itself declines. And so, you get that bend in the curve, meaning it's not a straight exponential rate of decline, which is sort of – if you're looking, if you look at the green line on page 23 of the slides you'll see how that sort of heels over in itself begins to flatten out and decline at a lesser rate of decline as the well produces over a longer period of time.

Jerry Elan – Hedge Fund

Is it breakeven on that at $70 a barrel, right around 500,000 barrels per well?

James Volker

Well, we're using 700,000 barrels. I'd say at $40 if we met 60% of that or around $24. So, $24 times 700,000 barrels gets you about $16.8 million of future net revenue for the scale of $6 million to $7 million well cost. We certainly don't want to drill these things for much less than around two to one on our money. So we'd probably back off if we got down there certainly in the $40 range.

Jerry Elan – Hedge Fund

Okay. And on your page 8 of your release on the bottom I was trying to work the numbers a little bit, but it looks like – correct me if I'm wrong, you got $16 million from production improvements and about $140 million from pricing improvements. Is that about right?

Michael Stevens

What are you referring to there?

Jerry Elan – Hedge Fund

The consolidated statements on income.

Michael Stevens

On page 8?

Jerry Elan – Hedge Fund

Yes.

Michael Stevens

What period are you talking over? Where does the improvement come from?

Jerry Elan – Hedge Fund

Well, it's got the September three months and nine months. I just took that $70 and calculated out your production increase and I come up about $60 million there. I assume it all back at $70 against the overall thing I get about $140 million. Alright?

Michael Stevens

Sounds reasonable.

James Volker

I guess – we're struggling here because we don't have the same page numbers that you're looking at for some reason. We're on page 16 of the news release if you're talking about the consolidated statements of income for the three months and nine months.

Jerry Elan – Hedge Fund

That's what I've got.

James Volker

Okay. Anyway, anything else?

Jerry Elan – Hedge Fund

One other thing, please. If you take me through this method of how you would take and deplete or run your depletions against your overall assets.

Michael Stevens

Alright. With successful efforts depletion, you have two parts, two components. Your depletion rate, one's your lease hold rate and one's your drilling rate. Your lease hold rate is based on your lease hold costs and your total proved reserves and there's a number of different depletion areas. You have to break your properties into a lot different areas. There's another component of that which is your drilling costs over your proved developed reserves. So, there's two components to the rate.

Jerry Elan – Hedge Fund

If I look at the number you've got here I think it's on your balance sheet you have a total of I guess your properties you've got like $4.3 billion and then the other one at $3.4 billion, depletion and amortization runs at $789 million, which equates back to what you've gotten back into your earnings. I assume that's return to capital that's going on here. It's like return of capital.

Michael Stevens

It's similar. Those types of calculations would use different numbers though. You'd be talking about your income divided into your asset base.

Jerry Elan – Hedge Fund

Your recovery rate, you got – first of all get back out your cap and that's really what that number is above right? Is that changing in some manner?

Michael Stevens

Okay, which number are we talking about?

Jerry Elan – Hedge Fund

I took the property and plant equipment (inaudible) at $4.3 billion and your capture rate getting that back appears is what would be your earnings. You've got to get back to capital first obviously. And that's why I was wondering about the depletion and amortization.

Michael Stevens

Well, I'm not fully following all of your logic there, but as far as our depletion rate it's going to increase and has been increasing. It's right around all in, right around $16 per BOE right now.

Jerry Elan – Hedge Fund

I know. I calculated it. You've got it calculated there.

Michael Stevens

Right. I expect that to go up somewhere around $0.80 a BOE in the fourth quarter here, which is what the kind of guidance we put out there.

Jerry Elan – Hedge Fund

Does that have any relationship to what you expect is what you call discretionary funds or your funds you can put anywhere?

Michael Stevens

No. The calculation simply follows GAAP accounting and it really doesn't have anything to do with return on assets or anything like that. They're not comparable in my mind.

James Volker

I think you're well aware that it's a non-cash expense, right?

Jerry Elan – Hedge Fund

Yes, I'm aware of that. I calculate it back and I add it back, I understand that. And so, first of all, I don't know, I always look at these things to get my money back out and the next thing I look at is my profit. If I don't get my money back out I don't really have a profit until I get my money back out. I've got to first of all recover what I put into. If I buy an oil well – I buy an oil well, for example, I buy an oil well and I don't get back what I put into it, I've obviously got a deficit in my equity or I get a loss. If I get something over and above what I put back into it then I've got gain. So, that's why I was curious looking at it this way this is set up whether your depletion is representing that. If I took that and divide into total overall assets it looks like another six years for recovery back out of the assets that you have, which would make sense at $70. That would make sense. You're at 4.5 at basically $100. You're at $70 it would go to 6.5 for your pricing.

Michael Stevens

You can see the amount of cash flow that we're generating. You can see the amount of cost we have invested in our assets. That might be a better way to approach..

Operator

I would now like to turn the –

James Volker

Thank you very much. We don't disagree with the fact that you certainly don't want to drill wells that don't return your capital and I think I've tried to give you an idea here of the types of multiples of that drilling completion and even lease cost involved that we look at typically in the plays that are forming the heart of our budget. And those are a multiple, significant multiple, generally in the range of three times to six times the cost of acquiring the leases and drilling and completing the wells. Further, if you were to maybe look at our 10-K and look at the estimates of discounted future net revenue and compare that to the CapEx you'd see the same sort of thing in that there's generally a nice multiple there of future net revenue over the estimated capital cost. I hope that helps you. Go ahead, operator.

Operator

I would now like to turn the call over to Jim Volker for closing remarks.

James Volker

Thank you very much, operator. We certainly appreciate the opportunity to speak to everyone today. In closing, I'd like to emphasize our intent to keep our 2009 CapEx within discretionary cash flow in 2009. We will be making that determination of our CapEx budget as we get closer to the end of the year and have a better idea of where oil and gas prices are at that time. But as you can tell we've tried to be forthcoming about where our budgets might be and the type of growth nevertheless that we still see even in view of somewhat lower oil and gas prices in 2009, perhaps than we had overall in 2007. So, we're very optimistic again about our ability to continue to grow production even at more moderate oil and gas prices. And we do expect that growth to be in the double-digit range.

So, despite the current volatility and commodity prices in the markets I'd like to underscore the excitement all of us here at Whiting are feeling about continuing to execute on our Bakken and Piceance Basin drilling plays as well as our Postle and North Ward Estes CO2 projects. We expect year-end 2008 results to show organic growth in both production and reserves assuming reasonable oil and gas pricing at year-end.

I'd also like to mention several events that Whiting will be participating in over the next several weeks that we hope will give us the opportunity to meet with you personally. We will be presenting at the Bank of America Energy Conference at the Ritz-Carlton Hotel in Key Biscayne, Florida at 11:20 a.m. Eastern time on Thursday, November 13th. We will also be presenting at Bank of America's Credit Conference on Thursday, November 20th at 4:40 p.m. Eastern time. That conference is being held at the Royal Pacific Resort in Orlando, Florida. And our first conference in 2009 kicks off with the J.P. Morgan High Yield Conference at the Lowe's Miami Beach Hotel. This conference runs from February 2nd through the 4th. So we look forward to seeing you at those events.

And in closing, I'd like to thank all of you on this call for your new or continuing increase interest in Whiting Petroleum Corporation and I want to again express my personal thanks to all Whiting employees and our directors for their contributions to Whiting's performance. All the best and we look forward to seeing and speaking with you soon.

Operator

Thank you for your participation in today's conference. This concludes the presentation. You may now disconnect. Good day.

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Source: Whiting Petroleum Corporation Q3 2008 Earnings Call Transcript
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