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Whiting Petroleum Corporation (NYSE:WLL)

Q4 2008 Earnings Call

February 24, 2009 11:00 AM ET

Executives

John B. Kelso - Director of Investor Relations

James J. Volker - President, Chief Executive Officer and Chairman

Michael J. Stevens - Vice President and Chief Financial Officer

Rick A. Ross - Vice President of Operations

James T. Brown - Senior Vice President of Operations

Chuck LaCouture - Vice President, Marketing

Analysts

Eric Hagen - BAS-ML

Biju Z. Perincheril - Jefferies & Co.

Joseph Magner - Tristone Capital Inc.

Kevin Smith - Raymond James

Eric Kalamaras - Wachovia Capital Markets

Operator: Good day, ladies and gentlemen and welcome to the Fourth Quarter 2008 Whiting Petroleum Corporation Earnings Conference Call. My name is Demali and I will be your operator 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 today's 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.

John B. Kelso

Thanks, Demali. Good morning and welcome to Whiting Petroleum Corporation's fourth quarter and full year 2008 earnings conference call.

On the call for Whiting this morning is Jim Volker, our President and CEO; Mike Stevens our CFO; Jim Brown, Senior Vice President; Doug Lang, VP of Acquisitions and Reservoir Engineering; Mark Williams, Vice President of Exploration; Dave Seery, VP of Land; Chuck LaCouture, VP of Marketing and Doug Walton, our National Drilling Manager.

During this call, we'll review our results for the fourth quarter and full year of 2008, and then discuss the outlook for 2009. 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 fourth quarter 2008 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 31st, 2007.

I should mention that we'll be filling our 2008 10-K later this week. We disclaim any obligation to update these forward-looking statements.

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

During this conference 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 J. Volker

Thanks, John. Good morning and welcome everyone to Whiting Petroleum's fourth quarter 2008 conference call.

2008 was the best year in Whiting's history. In line with our discretionary cash flow, as to our base drilling budget, and with the net proceeds of our recent equity sale as merited by the results in our new discovery and development areas, we intend to continue our operational momentum into 2009. Substantially, all of our production growth in the fourth quarter and full year 2008 was organic.

Our average net daily production rose 38% to a record 55,540 barrels of oil equivalent in the fourth quarter of 2008, up from 40,340 BOE per day in the fourth quarter of 2007.

Our average net daily production rate in the fourth quarter was 74% crude oil and 26% natural gas. Most of this production gain was due to our successful drilling results in the Middle Bakken, and from the favorable response of our two CO2 projects; the Postle and North Ward Estes fields.

During the fourth quarter of 2008, our average net daily production from the Bakken rose 43% to 15,300 BOEs a day from 10,700 BOEs per day in the third quarter of 2008.

During December 2008, or comparing December 2008 to December 2007, our average net daily production from the Bakken jumped 516% to 14,170 BOEs from 2,300 BOEs.

As is often the case at this time of the year, crude oil sales volumes in December of 2008, and the first quarter of 2009, have been affected, that is reduced, by winter weather in North Dakota, which has caused delays in trucking operations, and well completion activity.

It's also important to note that we completed our first two infield wells, and our first three horz (ph) well in the Sanish field.

Our first infield well, the McNamara 42-26H was drilled between two horizontal Bakken producers; the Locken 11-22H and the Liffrig 11-27H. The initial production rate at the McNamara well was 2,170 BOE per day, which falls between the initial production rates of the two offset wells. There was no indication of communication or interference with either of the offset wells.

Our second infield well, the Fladeland 12-18H was completed on February 18th, with an initial production rate of 1,765 BOEs per day, from the Middle Bakken.

Based on the results of these two infield wells, we expect to develop our leases with two 10,000 foot horizontal wells in each 1,280 acres spacing unit. This adds a total of 78 potential infield well locations.

We also completed our first Three Forks horizontal well in the Sanish field. This well is known as the Braaflat 21-11TFH. The initial production rate at the Braaflat well, which was drilled in the east central portion of the Sanish field, was 1,005 BOEs per day. Production and pressure data from this well will be analyzed over several months to determine the viability of developing the Three Forks in the Sanish field.

We're currently drilling a second Three Forks well on the southwest part of the Sanish field. Results from this well known as the Hansen 21-3TFH will also be used to determine future drilling potential in the Three Forks formation in the Sanish field. We are currently drilling or completing eight other operated wells in the Sanish field with an 80% average working interest.

Also in the Robinson Lake area of our Sanish field area, we completed the expansion of our Robinson Lake gas plant to a capacity of 30 million cubic feet of gas per day in December 2008.

As wells have been connected to the plant, net gas and NGL sales have increased to 4.2 million cubic feet and 1,060 barrels of NGLs per day respectively. That's up from 1 million cubic feet of gas per day, and approximately 130 barrels of NGLs per day prior to the expansion. We expect net daily sales to reach approximately 20 million cubic feet of gas and 3,000 barrels of NGLs by mid-2010.

I would like to stop for a moment and compliment our Robinson Lake gas plant team and all involved for their tremendous accomplishment of bringing that plant up for us while temperatures hovered between minus 10 and minus 40 degrees.

At our two CO2 projects, average net daily production increased 8.2% to 13,310 BOE compared to 12,300 BOE in the third quarter of 2008. Comparing December 2008 to December 2007, our average net daily production from the Postle and North Ward Estes fields, which are our two CO2 projects has increased 26% to 13,700 BOE from 10,850 BOE.

At the Postle field, we have five producing units and one producing lease covering a total of approximately 25,600 gross acres with working interest of 94% to 100%. Four of the units are currently active CO2 enhanced recovery projects.

As of December 31, 2008, we were injecting 142 million cubic feet of CO2 per day into the field. Production from the field has increased 22% from a net 5,800 BOEs per day in December of 2007 to a net 7,100 BOE per day in December 2008.

Operations are underway to expand CO2 injection into the northern part of the fourth unit known as HMU and to optimize flood patterns in the existing CO2 floods. These expansion projects include the restoration of shut-in wells and the drilling of new producing and injection wells.

Here again, I would like to stop and thank our entire Postle team for hitting the new records of production that they have been here in the fourth quarter of 2008 and continuing into the first quarter of 2009.

At the North Ward Estes field, we hold six base leases, with a 100% working interest in 58,000 gross and net acres. We initiated water flood in this field in May of 2007 and we were injecting 123 million cubic feet per day of CO2 as of December 31, 2008.

Production from the field has increased 29% from a net 5,100 BOEs per day in December 2007 to a net 6,600 BOEs per day in December of 2008. In this field, we are developing new and reactivated wells for water and CO2 injection and production purposes.

Additionally, we plan to install oil, gas and water processing facilities in five phases through 2015, and we estimate that the first three phases will be substantially complete by December 2009. As with our Postle project, I'd like to compliment our entire North Ward Estes team for accomplishing all of the above feats on time and within budget.

I would like to discuss our year-end 2008 proved reserves. As of December 31, 2008 our estimated proved reserves totaled 239.1 million BOEs. Of which, 67% were classified as proved developed. These estimated reserves had a pre-tax PV10 value of approximately 1.6 billion at year-end 2008 prices, of which approximately 90% came from properties located in combination of our Permian Basin, Rocky Mountain and Mid-Continent core areas.

Most of the proved reserve additions at December 31, 2008 came from our Bakken play in North Dakota. An estimated 23.6 million BOE of new Bakken proved reserves were booked at year-end 2008. Of which, 63% were proved developed and producing, 37% were proved undeveloped, 70% were attributable to the Sanish field and 30% to Whiting's interest in the Parshall field.

Partially offsetting 39 million BOE reduction in price-related reserve revisions at year-end 2008 were 5.7 million BOEs of upward reserve revisions. These performance-related upward revisions came primarily from the Postle and North Ward Estes projects.

I would like to point out that if our December 31, 2007 total proved reserves have been calculated using prices as of December 31, 2008, the total proved reserves would have been 207.5 million BOEs at 12/31/07 as opposed to 250.8 million BOEs with the higher prices in effect at year-end 2007.

The 207.5 million BOE reserve number would compare to December 31, 2008 total proved reserves of 229.9 million BOE after adjusting our year-end reserve number of 239.1 million BOE for an add back of property sales of 6.3 million BOEs and a deduction for acquisitions of 15.6 million BOEs during 2008. Under this scenario, our proved reserves would have shown a year-over-year increase of 11%.

With that, I'll turn the call over to Mike Stevens, Whiting's CFO.

Michael J. Stevens

Thanks, Jim.

Effective November 1, 2008 Whiting's Bank Group reconfirmed the company's $900 million borrowing base, which matures in August 2010. Our Bank Group is comprised of 23 commercial banks holding between 1.8% and 12.9% of the total facility.

As of December 31, 2008, approximately $620 million was drawn on this facility and approximately 3 million in letters of credit were outstanding, resulting in 277 million of availability. Our next bank meeting is scheduled during the first week of March.

In February 2009, we completed a public offering of common stock at a price of $29 per share. The offering resulted in the sale of 8,450,000 million shares of Whiting's common stock. The company received net proceeds of approximately 235 million after deducting underwriting discounts, commissions and expenses of the offering.

We used all of the net proceeds that we received from the offering to repay a portion of the debt outstanding under our credit agreement.

In the fourth quarter of 2008, we reported a loss of $3 million or $0.07 per basic and diluted share on total revenues of 223.9 million. This compares to fourth quarter 2007 net income of 45.8 million, a $1.08 per basic and diluted share on total revenues of 232.4 million.

During the fourth quarter 2008, we recorded a 10.9 million non-cash impairment charge to write-down a portion of our cost basis in the central Utah Hingeline play.

Discretionary cash flow in the fourth quarter 2008 totaled $111 million, compared to $139.9 million reported for the same period in 2007. The decrease in net income in the fourth quarter of 2008 was primarily the result of a 34% decline in the company's realized oil price and a 31% decrease in our realized natural gas price.

For the year ended December 31, 2008, we reported net income of $252.1 million or $5.96 per basic share, $5.94 per diluted share, on total revenues of $1.2 billion.

Discretionary cash flow in 2008 totaled a record $744.4 million, compared to $422.2 million in 2007.

During the fourth quarter, the company-wide basis differential for crude oil compared to NYMEX was $11.38 per barrel, which compared to $8.25 per barrel in the fourth quarter of 2007, and $10.09 per barrel in the third quarter of 2008. The primary reason for the change was increasing differentials on production from both the Sanish and Parshall fields during the fourth quarter of 2008.

Subsequent to year-end, crude oil differentials in these areas have improved by approximately $2 per barrel. In addition, Whiting expects its 17-mile oil line connecting the Sanish field to the Enbridge pipeline in Stanley, North Dakota to be in service at the end of the second quarter of 2009. We expect this event to have at least an additional $2 per barrel positive effect on the crude oil differential in this area.

The company-wide basis differential for natural gas compared to NYMEX in the fourth quarter was $2.58 per Mcf, which compared to $0.60 per Mcf in the fourth quarter of 2007, and $1.62 per Mcf in the third quarter of 2008.

Turning to our guidance for the first quarter and full year 2009, our production guidance for the first quarter is at a midpoint of 4.8 million BOEs. First quarter 2009 production levels are expected to be affected by winter weather in North Dakota, which has caused delays in trucking operations and well completion activity in the Sanish field and the Parshall field.

Our production guidance for the year is at a midpoint of 19.6 million BOEs, which should represent an increase of approximately 12.12% (ph) over the 17.5 million BOEs reported for 2008. The production gains in 2009 are respected to come primarily from our drilling programs in the Bakken, as well as our two CO2 projects.

I would also like to point out that our cash costs on a unit of production basis in the fourth quarter of 2008 were lower compared to the fourth quarter of 2007 in every category, except for cash income tax expense.

I would like to turn the call back over to Jim Volker, to discuss our exploration and development budget and drilling plans for 2009.

James J. Volker

Thank you, Mike. I would like to emphasize that with the current volatility in oil and gas prices and their effect on our revenues, we plan to adjust our base 320 million exploration and development expenditures to approximate our discretionary cash flow.

Second, as warranted by the results of our new exploration and development areas, we've employed the capital raise in our recent stock offering. That being said, our current 2009 capital budget for exploration and development expenditures is 474 million which you can see itemized on page 7 of our news release.

We expect to fund that 474 million with net cash provided by our operating activities, and a portion of the proceeds from the common stock offering. As I just indicated, to the extent net cash provided by operating activities is higher or lower than currently anticipated, we intend to adjust our base $320 million budget accordingly.

Our 2009 capital budget currently is allocated among our major development areas. As stated in our recent prospectus, we may use a portion of the proceeds from our common stock offering to further develop the properties in our base $320 million drilling budget, develop our new exploration and development areas or to keep our bank debt at lower levels.

We believe the projects, I am about to discuss, present the opportunity for the highest return and most efficient use of our capital expenditures.

Our planned capital expenditures for the Sanish field in 2009 are $204.9 million which would be used for the drilling and completion of approximately 40 wells. We hold interest in a total of 125,557 gross, 83,606 net acres in the Sanish field and the adjacent Parshall field where we own interest in 73,760 gross acres, 18,315 net. We plan to invest 22 million for the drilling and completion of approximately 18 Bakken wells. Please note that we have included a chart in our news release showing the declining well costs for Whiting-operated Bakken wells in the Sanish and Parshall fields.

The reduction in these completed well costs are the result of drilling and completion efficiencies which have recently reduced the average time from spud date to completion to approximately 41 days from 60 days earlier in our drilling program.

We plan to invest a total of $129.3 million in our two CO2 projects during 2009. Of this total, 97.8 million will be directed to the North Ward Estes field, of which an estimated 36.9 million or 40% is expected to be used for the purchase of CO2.

At the Postle field, we plan to invest $31.5 million, of which $15.3 million or approximately 50% is planned for CO2 purchases.

In the Piceance Basin, in the Sulphur Creek field, which is comprised of our Boies Ranch and Jimmy Gulch prospects, our planned capital expenditures are $39.4 million. This investment would be for the drilling and completion of an estimated 18 gas wells. In this area, we expect an acreage grade completed effective December 1, 2008 with a third-party to consolidate our acreage position.

As a result of the trade, we now own 8,424 gross and 4,338 net acres in the Sulphur Creek field area. We currently plan to invest $19.1 million for the drilling and completion of four Entrada gas wells in the Flat Rock field, located in the Uinta Basin of Uinta County, Utah.

In the Flat Rock field area, we have an acreage position consisting of 22,000 gross and 11,533 net acres.

We recently completed two wells in the Entrada formation that had initial gross production rates of between 4 million and 9 million cubic feet of gas per day.

We have assembled 81,249 gross, 111,501 net acres in our Lewis & Clark prospect along the Bakken shale pinch out in the Southern Williston Basin.

On December 13th, 2008, we completed our first horizontal well in this area, which had an initial production rate of over 1,000 BOE per day from the Three Forks formation. The second Three Forks test on this prospect, the MOI 22-15H is a casing exit of an existing vertical wellbore that is expected to be completed by the end of February.

In 2009, we intend to drill an additional six Three Forks wells on this prospect, for an estimated cost of $15.4 million.

In Southern Wyoming, in the Hatfield prospect area, we have a large acreage position, covering over 80 square miles, and encompassing 53,164 gross and 31,907 net acres.

In September 2008, we drilled the Beckman Canyon 21-24D, the vertical test of the Niobrara formation, as we also drilled it to a deeper zone. During drilling operations in the Niobrara, at a depth of approximately 3,500 feet, oil flowed to the surface and oil shows were seen in the drill cuttings. Completion operations are underway at that well.

In December 2008, we drilled the Artus 19-33, a horizontal Niobrara well, and have also commenced completion operations on this well. We plan to drill an additional six wells on the Hatfield prospect in 2009 for an estimated cost of $9 million further test the Niobrara.

At the height of our drilling activity in 2008, we are active with 18 operated rigs and 51 operated workover rigs.

As of February 13th, nine operated drilling rigs and 37 operated workover rigs were active on our properties. We were also participating in the drilling of four non-operated wells, all of which are located in the Parshall field. We expect our operated rig count to draw up to four drilling rigs, and approximately 25 workover rigs by November 2009.

I would now like to review the slides in our webcast, which provides more detail and color in our primary operating areas. To begin, please take special note of the forward-looking statement disclosure, and reserve information on non-GAAP measures, in particular the risk factors cited therein as it may affect all forward-looking statements that I may make during this presentation.

Turning to page two, slide two as you can see, our market cap as of February 20th using a price of $25.05 a share was 1.3 billion, long-term debt, pro forma for our equity reissuance is 1 billion, shares outstanding 50.8 million, our debt-to-total cap 33%, and our proved reserves 239.1 million BOEs, based on year-end 2008 pricing.

Our RP ratio was 13.6 years and our December 2008 production 55,100 BOEs a day.

Turning to slide three, you will note the 38% increase in quarterly average daily production from Q4 '07 to Q4 '08. You will also note in the right hand portion of this slide that the light blue, the red and the green regions that is the Rocky Mountains, the Permian and the Mid-Continent amounted to 92% of our proved reserves. 75% of which are oil, 25% of which are natural gas, 67% of which are developed and 33% of which are undeveloped. We also hold a total of 935,000 net acres, 55% of which are developed.

I'd like to call your attention to slide four, going immediately to the far right hand side, where you can see that for the year as a whole, Whiting enjoyed a great EBITDA margin of approximately $45.05 per BOE and with LOE declining to approximately 20% of the total Whiting realized price per BOE including hedging adjustments.

Turning to page five, here again, we break out for you in the middle of the table the total of the 239.1 million BOEs by region, obviously with the Permian region at 97.7 and the Rockies at 83.2 being our two largest regions, and with the Postle field being the largest portion of the Mid-Continent 49.1 BOEs. We've also broken out for you there, where the production comes from by region. And again, we calculated for you in the white box at the bottom of the page five, the 11% increase using year-end 2008 pricing applied to our year-end 2007 reserves. So a 11% increase on an apples-to-apples basis using the lower oil and natural gas prices in effect at 12/31/08 of 44.60 and 5.63 respectively.

On page six, you can see in the highlighted area, I think the key aspects of Whiting at this time and that is we are getting continued moderate organic growth, moderate risk organic growth from Postle and North Ward Estes fields, while at the same time enjoying significant organic growth potential from drilling programs in the Sanish and Parshall oil fields for the Bakken and our new projects at Lewis & Clark, which is the Three Fork zone for oil at Sulphur Creek fields; Boies Ranch and Jimmy Gulch prospects, where the Mesaverde is gas productive and our Hatfield prospect in Southwestern Wyoming, where the Niobrara we believe will be oil productive.

Moving to page seven, I'd just like to say that we will continue to acquire, exploit and explore and from time-to-time monetize reserves as part of our overall business plan.

On page eight, I would like to point out that all of our reserves, both approved, probable and possible are independently engineered and that the probable and possible reserves, totaled 244.8 million BOEs. That's just a total there of 133.2 probable and 111.6 million BOEs possible.

Moving to page nine. This is where the bulk of those P2 and P3 reserves are located. That is, 71% of them are located in North Ward Estes at Sulphur Creek in Sanish and Parshall.

Moving to page 10. This is a vision of this table. I like it better because it includes the line and five lines down from the top of the page, change in future development cost wherein we've calculated for you our total finding cost for each year and the five year total. As you can see in '04 and '05, we concentrated on acquisitions. In '06, '07 and '08 a larger portion of our CapEx was with respect to the drillbit and our development cost such that, by the end of 2008, essentially what we've done with the drillbit has exceeded in total dollar amount over that five-year period, what we did with the acquisition dollar.

We have shown for you here, therefore in the far right hand column, what I believe is the key number, which is $21.25 all in F&D cost based upon proved reserves and three lines below that, $13.28 based upon P2 and P3 reserves as well as proved reserves. We've also footnoted those for you, so you can see what those finding cost and development cost would be, have they not been affected by the year-end '08, 39 million barrel reserve reduction as a result of lower oil and gas prices at year-end 2008. And that, of course, causes footnote 1 there to decline from 94 bucks to $22.38, footnote number 2 to decline from 21.25 to 18.32 and footnote number 4 to decline from 13.28 to 12.18.

Moving on to slide 11, here we've laid out for you the reserve replacements for the same five-year period and in total, in the far right hand column, you can see that it is a 362% overall reserve replacement versus production.

On page 12, I'd just like to concentrate on the middle pie chart here showing that our total proved reserves by core area are 92% in our three largest areas of the Rockies, Mid-Continent and the Permian, and that production comes 84% from those same three areas.

On slide 13, we've laid out for you the base drilling budget here, which by region is broken out for you with respect to the $320 million base drilling budget plus 124 million that we enumerated with respect to the recent capital raise for certain projects totaling 444 and we get to the 474 as a result of roughly 30 million in projects which continued over year-end '08 and into the year 2009. And they're broken out for you then on page 14 by region and by major project so that you can see the genesis here of the 474 million total planned capital expenditures.

On page 15, you'll also see that by the way on page seven of the news release. On page 15 of the slides, I'm concentrating on the far right hand pie chart here. As you can see, 41% of our CapEx is expected to be invested in non-proved areas, 29% into our CO2 recovery projects and 30% will be directed toward the development of proved undeveloped reserves.

We've broken it out for you then by region on page 16 where you can see that 66% of the budget will be attributable to the Rockies and 21% to the Permian. Thus those two are the bulk of our 474 million budget.

In addition, I would point out to you that the balance of the proceeds of the offering that we closed in February may be used to either further develop these incremental projects, expand these projects included in the capital base or to keep our debt at lower levels basically depending upon what happens to oil and gas prices. So that $111 million number there you see in footnote number 1 is just the difference between the 235 million raise and the 124 million of incremental projects.

In the lower right hand corner of page 17, which gives you the total on our gross and net as well as developed and undeveloped acres and as you can see, we have approximately 420,776 net undeveloped acres. And most of those as you can see by looking at the Rocky Mountain tag in the center of the United States there, 326,718 of those net undeveloped acres are in the Rockies.

On page 18, something I'd like to point out that we are very pleased with the results of our drilling in the Bakken. We see average EURs in the 700,000 BOE range. And our completed well cost has come down to approximately 6 to $6.5 million per well.

On page 19, you can see what we are doing at Sanish and Parshall and the difference in the reservoirs at the two fields. And essentially we are going horizontal in the dolomitic section of the Middle Bakken at Sanish whereas essentially we are drilling in the fracture portion of the Upper Bakken Shale at Parshall.

Slide 20 is a good summary for you, I hope where you can see our total drilling plan. I would point out to you that the base budget is indicated here by the thinner red lines and in total at this point, as of the 23rd of February, the date of the math we had essentially five wells that we are drilling 23, yet to be drilled as part of our base drilling budget. So that's 28 total and then we got to the total of 40 overall as a result of the additional capital raise for an additional 12 wells indicated by the thicker red lines. And there are, as you can tell, 12 of those at Sanish and total of nine additional wells at Parshall, bringing Parshall to a total of 18, essentially nine with the base drilling budget and nine with the incremental capital raise.

On page 21, it shows I think the market reduction that's occurred after about our first 10 wells there at Sanish, and we brought on a continuing basis and fairly consistent basis I think, our drilling and completion costs that is total completed well cost is down to around 6 million and in some cases little less. We are pleased with that. Obviously that's important as oil prices have declined.

We've summarized on page 22 for you the initial IP rates over 24 hours. The average production over the first 30 days and the average over the first 60 days from the first 25 wells there listed on this page and if you can tell, the wells are still averaging over 800 barrels a day, 60 days after completion.

If you would like to know what it's like out there in the field and what it has been like in January for that matter part of December, in Mountrail County, this picture on page 23 will indicate what kind of a winter they are having up there. And again my thanks goes out to our Mountrail County team for continuing to be able to deliver our production up there and get it out, keep it trucked out during these challenging times. And also as can be seen on page 24 to construct our gas plant at temperatures, as I said earlier, that range between typically about 10 below and 40 below.

On page 25, as you can see the production curve here are tight curve wherein we see on a proved basis of roughly about 600, 700,000 BOEs, and with the continued production performance we believe part of the reserves that we currently call probable will give us a total EUR range in the range of 900 to 1 million BOEs per well.

Lewis & Clark, this is a great prospect area for us. Obviously, I wish that cash flow was up, and we could really take off on this. But with prices where they are, we'll be judicious about going after this area. However, I'm very enthusiastic about this particular area, even I might say at somewhat lower oil and gas prices in that I'm hopeful that we'll see perhaps 500 to 600,000 BOEs per well here. And if we can net roughly $23 after royalties, operating expenses, and production taxes here, we will get close to 14 million of future net revenue here per well that costs us of hopefully only about $4 million, because we can do a lot of them out of casing exits. So that's about 3.5 to 1 on our money at these what I would call depressed price levels. And we are optimistic about the results that we have seen here, with our first well testing over 1,000 BOEs a day, and with the second well currently being completed.

On page 27, Hatfield prospect, I would like to say this is another large acreage position, covering over 83 square miles. As you may have noted, the Lewis & Clark is a huge acreage position for us, the prospect I just previously talked about, covering 283 square miles. At any rate, here at Hatfield we are drilling horizontal in the Niobrara.

We had some great shows when we drilled Beckman Canyon well. And we are in the process of completing and testing the Artus 19-33 and since jury is still out on this, but we are optimistic based up on the shows we have seen. And we hope to drill another well or two there at a minimum this year.

Moving on to Boies Ranch prospect in the Rio Blanco County, Colorado on page 26, I'd just like to show you what it's like up there when it's not snowing. And as you can see, the local stock likes to have us there, doesn't seem to mind our drilling activities going on.

We document for you on page 29, what we intend to do with the capital raise at Jimmy Gulch and that is to drill nine more wells out there, into the Mesaverde. Looking at the bullet points, sort of the indented portion of the bullet points on page 29, you can see that the last three wells there were producing at a combined rate of 3.9 million cubic feet of gas a day, on February 13, and we're very pleased with the results there. And we plan on drilling an additional nine wells there, at an estimated net capital cost of about $28.4 million.

If you'd like to know what it looks like at Uinta County , Utah, you can see that on page 30, when Neighbors rig 270 was drilling in the Ute Tribal (ph) 15-30 for us. That was a well that tested at the higher rates shown here on page 31, jumping ahead to page 31, where that well initially tested about 9 million cubic feet of gas a day and the other well, the 1-30 at about 4 million a day respectively.

So we have good hopes subject to gas prices hanging in there to continue to develop Flat Rock, and because we think it does have a great economic potential for us.

Moving on to Postle and North Ward Estes fields, I'd call your attention in the upper left hand corner to the dark blue box, where you can see in the far right hand column that these two projects currently compose 47% of our reserves and 26% of our net daily production.

Consequently, along with Sanish and Parshall, these two CO2 projects plus our Bakken currently represent just over 50% of our net daily production. Things are on track and my compliments again go out to the Postle and North Ward Estes team for executing these projects on time. And as you can see, we are projecting from proved reserves alone, production to rise to approximately 10,000 barrels a day, at both of these projects, Postle first in approximately four years, three years from now and approximately five years from now with respect to North Ward Estes.

The P2 and P3 reserves which I've talked about earlier, would of course sort of layer in on top of these and cause somewhat higher production. And we hope that as that production is seen, if it is seen that we'll be adding those P2 and P3 reserves into the proved category. I think some of that may happen near the end of this year and again next year.

Page 33 shows what we think our fully developed costs have been at Postle and North Ward Estes and it's roughly $17.80 per BOE, see that in the far right hand column, that's fully acquired and developed as we go forward. Based upon the proved reserves and with P2 and P3 reserves, it drops down to about $11.18 per BOE. I think that explains simply why we are executing those two projects at Postle and North Ward Estes.

In particular at Postle, you can see in the lower right hand corner at page 34, again the lower right hand corner that our remaining capital expenditures going forward are expected to total approximately 149 million. And so we are definitely over the hump in the CapEx trend and with roughly a third of CapEx going forward being related to simply purchasing CO2 at about two-thirds then for hard CapEx of equipment. And main production trends shown on page 35 at the Postle field as it rises to approximately 7,000 BOEs a day.

Likewise on page 36 in the lower right hand corner, you can see that with respect to our remaining capital expenditures at North Ward Estes, roughly 50% of those are simply purchasing CO2 and roughly 50% of them directed toward the hard CapEx of drilling completion, water flood restoration and plant costs.

And on page 37 also rising towards 7,000 barrels a day at North Ward Estes net daily production graph for you.

On page 38, a good graph here for you to see. First of all, a number that I would remind you of and prepare for you and that is the 150.4 million BOEs, P3. And I would remind you that when we acquired both Postle and the North Ward Estes, this slide here of course referring only to North Ward Estes, but when we acquire Postle and North Ward Estes, we thought that in total there were roughly about 120 million barrels across the two of them and about 80 million barrels at North Ward Estes. So here looking at... those are proved reserves and here looking at the P2 and P3 reserves along with proved roughly 150 million barrels now that we've got our arms around to further extend the reservoir at North Ward Estes.

And so in total, as you can see almost 14,000 BOEs a day net on page 39 coming from North Ward Estes and Postle. And so, then we've shown you on page 40 how the two that is the Bakken compared to the two CO2 projects are stacking up. As you can tell, the Bakken has been rising and it's currently at about 14,170 BOEs a day and two CO2 projects of 13,700 BOEs a day.

And then finally, our pro forma capitalization slide for you. Pro forma for closing of the recent stock offering that our debt to total cap at 33%. Our hedging position shown on pages 42 and 43, I hope laid out for you so that you can see that we have roughly into the mid 40s percentiles of our December net oil production hedged at prices with floors of essentially around $58 on average and ceilings up to about $70 for 2009. The percentage is roughly 35% in 2010, 30% in 2011 and 28% in 2012 and roughly 24% in 2013 with floors of roughly $60 and ceilings of little better than $80 a barrel for oil.

We don't have much of our gas hedged. As you can see on page 43, only approximately 1.5% or so of our gas is hedged and we've done predominantly through the trust and it's hedged at prices of roughly $6 to $7 floors and $13 to $18 ceilings.

So in summary, Whiting has all of these things that you see on page 44. The highlighted ones, the five year drilling inventory, moderate risk organic growth from Postle and North Ward Estes and significant organic growth potential from drilling programs in the Sanish and Parshall oil fields, the new project at Lewis and Clark, at Sulphur Creek field in the Piceance Basin, Boies Ranch, Jimmy Gulch for Mesaverde gas and at Hatfield for Niobrara oil.

Operator, with that, I'd like to open up the conference call for questions.

Question-and-Answer Session

Operator

Sure. (Operator Instructions). Your first question comes from the line Eric Hagen with Bank of America. Please proceed.

Eric Hagen - BAS-ML

Hey, good morning Jim.

James Volker

Hi, Eric.

Eric Hagen - BAS-ML

Hi there. The question on your CapEx, the $30 million in other, I think if I heard you right, you said that was a spillover from 2008. Is any of that discretionary or is that pretty much something we can add on to that base 320 and will be spent this year?

Michael Stevens

Base, it would be a definite add-on to the base 320, Eric.

Eric Hagen - BAS-ML

Okay. So you're basically your sort of lower case CapEx then is actually around 350 all-in?

Michael Stevens

Yes.

Eric Hagen - BAS-ML

Okay. And then when do you make the decision whether you spend the additional $124 million or whether you keep that on the balance sheet to just retain your flexibility and at what point do you think you will be ready to make that. Is it a 2Q issue after you could go back and see how the bank re-determination goes?

James Volker

Well, I'll try to be as direct as I can to answer that question. I really believe that we will probably be making parts of that decision within the next 30 days Eric as we watch oil prices primarily and secondarily the results on drilling that's been done out there on the new incremental projects. And part B of your question, I will say that I have high confidence in what the banks are going to do, having had good meetings with our top three banks, and I have high confidence that we are going to get a great outcome on our borrowing base. So I am not really worried about our borrowing base. If I had to guess I'd say it will go up.

Operator

Your next question comes from the line of Dwain Rupert with PRT Capital. Please proceed.

Unidentified Analyst

Yes Jim, on the upward performance revision from the CO2 projects, can you talk a little bit about how conservative or aggressive you think you're postured in terms of this particular level of revisions? And what will you be looking for in the future to maybe get even more confident, would be more aggressive on performance revisions?

James Volker

Well Erik I will try to... I am sorry, Dwain I will try to be as succinct as I can here. In general, as you know what happened to us when we bought this project was that we were pretty much limited in terms of the kind of response that the independent engineers could work with in projecting future proved reserves. And I was pretty much limited to roughly a kind of a 5.5% recovery that the private project that was done by the major oil company that used to own this field had achieved. But in reality, we thought certainly 9% was more likely based upon other floods in the area and essentially just the fact when you implement a big project you create a bigger sweet spot and consequently just as the recovery factor and sort of the sweet spot that got benefit of four-way push in the project may have been higher than 5.5%, same way (ph) like 9%.

We expected that as we implemented the entire project and created essentially a huge sweet spot for benefiting from four-way push that the P2 and P3 reserves that we set out for you here which are roughly at 78 million barrels could be achieved. And we do think, it's going to be added in over several years. As I said I think we'll start to see, I am hopeful that we will start to see some of that at year end 2009 and more even at year end 2010. And of course that we would also see some rising production levels obviously above what you see on the proved curve at North Ward Estes on page 32 of our slides. So I hope that's direct enough for you and I hope to say that we will be seeing that essentially over about the next three to five years.

Unidentified Analyst

Yeah, that is very helpful. And in terms of your debt management, when you look at your covenant, for example, with debt to EBITDAX ratio and if you look at your potentially larger capital spending going forward, do you have in mind in an ideal case, if prices were to improve a little bit, a debt pay-down goal?

James Volker

Yes, and I would think that... well, first of all as I suppose I should have answered part A of that question that, I think is embedded in your question. And that is... an answer to your question and an answer to Eric's question previously asked, when are we going to be making these determinations? And that I think we're going to be doing that over roughly the next 30 to 60 days, so that we can adjust our CapEx if prices are going to stay down, let's say at $35 a barrel.

Then we would trim back on our CapEx, so that it wouldn't be as high as this 474. We might lay down some rigs perhaps 3 or 4. And that my opinion would probably not somewhere between 80 and 100 million bucks off of $474 million number. And the prices continue to stay down there. We have the flexibility I think to knock off another 80 million or so.

So that's... we are over all there Eric and you too, Dwain. We're all over that, we're watching it very closely, and we'll make the adjustments necessary to... I guess I'd put it to you this way, stay within 100 million or less overspent of our cash flow. And perhaps even less than that amount. I hope that's direct enough for you.

Unidentified Analyst

Yes, that is helpful. And then just one follow-up kind of grabbing on to something you said about laying down rigs. If you do trim back do you think of it more as, I want to do all these different programs and I might do some of them less or is it more like some programs will either be funded or not funded?

James Volker

It would be the latter, Dwain. And the ones that probably would get funded to the greatest degree would be Sanish and Parshall. I don't think you'd see more than maybe a $4 million reduction at North Ward Estes and Postle. And where you would see the big cut is probably in the central Rockies where that might decline from something in the $72 million range as currently anticipated to maybe only 8 or 9 million.

Operator

Your next question comes from the line of Biju Perincheril with Jefferies & Company. Please proceed.

Biju Perincheril - Jefferies & Co.

Hi, good morning.

James Volker

Hi Bi.

Biju Perincheril - Jefferies & Co.

A quick question on the borrowing base Jimmy, your comment about being flat or perhaps going up with obviously, the prices that banks are using is lower. Is it because you are able to pledge more reserves, or your higher production, or can you give us some more color into that?

James Volker

Yes sir. I think the direct answer there is that we have got a higher rate of production, and we have got... and of course with the banks what you look at is your proved developed producing reserves. And so we have shifted reserves from the undeveloped or P2 or P3 category in the proved developed producing. That's really what affects your borrowing base. And so that's the primary reason for what I could call the potential for an increase in our borrowing base.

Biju Perincheril - Jefferies & Co.

Okay. That's helpful. And then, just to clarify, did you say that if prices stayed lower... did I hear this right that your flexibility to cut CapEx is total of about 180 million?

James Volker

Yeah, I would say something in that range, 150 to perhaps 180 million.

Biju Perincheril - Jefferies & Co.

Okay.

James Volker

That's on the upside. And you ought to think about that and sort of cut that number in half. In other words, we might cut half of it first, and half of it later if prices continue to stay down.

Biju Perincheril - Jefferies & Co.

Got it, got it. Okay, thanks. Well one more question actually. Do you have the offset wells to the second infill well that you drilled at Sanish, the flat line?

James Volker

Yes, yes. That one was basically about 1800 BOEs a day.

Operator

Your next question comes from the line of Joe Magner with Tristone. Please proceed.

Joseph Magner - Tristone Capital Inc.

Good morning. Just wondered if you could address the revised production outlook from the time of the equity offering. I think you were talking around 15% growth off of a increased CapEx budget. Now, it's 12%. And then also, along the lines of some of these CapEx reductions if prices stay lower, what are the sensitivities from the 12% range, when and if some of that capital gets carved out of the budget?

James Volker

Thanks Joe. Good to hear from you. By the way, what we were talking about at the time of CapEx raise was roughly a 9% growth year-over-year based upon the $320 million budget. We've raised that to 12%, including the incremental capital. And to give you a range, I still think even with what I would call the laying down, perhaps four rigs, I am still optimistic that we would be somewhere in terms of the production growth year-over-year of between 5 and 9%.

We are just getting great results up there at Sanish. And of course, every time we drill one, we essentially derisk our projection. So, I'm still highly optimistic that we'll show some production growth year-over-year, even if we have to cut the budget.

By the way, I think some of you may have follow-up questions. Feel free to call back in, we'll stay on till you have all your questions answered. I'd see that some of you are getting cut off after I give my answers. So, if you have a follow-up question, feel free to call back in. We'd be happy to answer it.

Operator

Your next question comes from the line of Jane Li with JP Morgan. Please proceed.

Unidentified Analyst

Hi Jim. Question on your CapEx in the Parshall field, EOG has reduced its rigs in the area. Wondering, if your current budget in the area is based on EOG's current drilling plans?

James Volker

Yes. Our budget is based on EOG's essentially 18 well within the area where we have joint acreage with them drilling plant. Where they currently have five rigs operating, and as set forth, there were essentially nine wells in our base drilling budget, and nine wells from the incremental capital raise that we would participate in.

Unidentified Analyst

Okay. And also, you say you plan to reduce rig numbers from nine to four by November this year. I'm wondering, if that's in the base plan, or it's in the 474 million case?

James Volker

That's in the base plan.

Unidentified Analyst

Okay. Thank you.

James Volker

Thank you.

Operator

Your next question comes from the line of Kevin Smith with Raymond James. Please proceed.

Kevin Smith - Raymond James

Thank you. I just had one or two questions here. First, when do you plan on completing the Hansen well, I believe you've already drilled if that's correct?

Rick Ross

We are still drilling that. We'll be completing that in the next or finishing drilling in the next couple of weeks. And then, I would expect about four weeks after that we will finish the completion of the well.

Kevin Smith - Raymond James

Okay.

James Volker

Thank you, Rick. That was Rick's first answer here, starting around so, good job, Rick.

Rick Ross

Thanks.

Kevin Smith - Raymond James

We do have 7 Sanish wells that you are in various processes of drilling. How many of those do you think you're going to be able to complete by Q1?

James Brown

This is Jim Brown. Currently on our schedule, we have five perhaps scheduled for the month of March. So that's going to get it to fairway down the line to get those online.

Kevin Smith - Raymond James

Okay. So that would be... they'd be typically at kind of the end of March, middle or any specific?

James Brown

With five cracks we are going to be doing basically one week, so we are going to be hitting it hard the first and probably do, there is ramped out on in there some place, but it's going to be one week through March.

Kevin Smith - Raymond James

Okay. Thanks. And just one follow-up question now Jim Brown. On the Parshall field, I know EOG it's hot about setting in half to its production. Have they communicated any of that to you that any of your wells will possibly be shut in?

James Volker

Well, what I would say is that they've been curtailed there as a result of operational issues, having to do mostly with the weather. And we think EOG is doing a great job up there. We are pleased to be their partner and we share information with them openly. And all I can say is I think given the right thing based upon the situation that they have at Parshall and what I would call their particular takeaway capacity. Fortunately, we have what I consider to be a crack marketing department here and fortunate we haven't been restricted significantly anyway on our takeaway capacity as we have seven different purchasers who we sell to up there, so that's a bit of a scramble for all of us right now, I think EOG is doing the right thing and it's kind of waiting to complete some wells until March when some normal weather shows up. I think it's probably a good plan on their part. I think they'd probably be in April or May, railroading out fewer barrels than they are today and I think that's going to help their differential up there as well, so hats off to them and kudos to our people in the field for dealing with what I would call the tight market as well as the inclement conditions.

Kevin Smith - Raymond James

Thank you very much.

James Volker

Thanks.

Operator

Your next question comes from the line of Eric Kalamaras with Wachovia Capital Market. Please proceed.

James Volker

Hi, Eric.

Eric Kalamaras - Wachovia Capital Markets

Hi, Jim. Good morning. How are you?

James Volker

Great, thanks.

Eric Kalamaras - Wachovia Capital Markets

A question on the current revolver availability. Where does that stand today?

James Volker

Well, as you know we have $900 million of availability under our borrowing base. And Michael tell you here we're little over 500 million in the quarter, about 540 currently drawn.

Michael Stevens

540 drawn today.

Eric Kalamaras - Wachovia Capital Markets

Okay, great. And also regarding the hedges, what is the portion there that is exclusive of the trust that is just triple to Whiting Corp?

James Volker

Basically, it's almost everything that you see there in the corporate oil column.

Michael Stevens

Everything we put on our slide presentation is our net position.

Eric Kalamaras - Wachovia Capital Markets

Okay.

Michael Stevens

Whether it be in the trust or outside the trust. So we have the economics on all of the hedges we showed.

Eric Kalamaras - Wachovia Capital Markets

Okay, great. Thanks. And I guess, regarding some of the changes in the G&A line that you got going into the full year of '09. Can you kind of highlight to me what are some of the changes there in terms of some of the increase you got from the run rate, first quarter?

Michael Stevens

Well, our guidance for the first quarter of '09 of $1.90 to $2.20 is actually a lot less than it's been historically.

Eric Kalamaras - Wachovia Capital Markets

Agreed. But it's moving, it then moves higher for the full year?

Michael Stevens

Well, it has to do with where we project primarily our net revenue position to be revenue less LOE and taxes. As the year goes out, our differentials come together. We produce little more net revenue. Why that's important is the biggest line item within G&A historically has been our production participation plan, which is our bonus program here, and as net revenues increase G&A will increase along with it.

Eric Kalamaras - Wachovia Capital Markets

Okay, great. All right guys. Thank you very much.

James Volker

Thank you.

Operator

Your next question comes from the line of Scott Lumis (ph) with Simmons and Company. Please proceed.

Unidentified Analyst

Hi, guys. One question on the Flat Rock Entrada wells. 5 million of oil, is that a good estimate on the well cost?

James Volker

That's a reasonable estimate. We're going to potentially come in a little bit below that, but it's somewhat weather dependent.

Unidentified Analyst

And based on the results you guys have seen, what kind of EUR are you expecting from your wells?

James Volker

Our reserve estimates are recurring on the books there. And what we've seen based on our current drilling and we drilled two wells out there since the acquisition. We're still up in the range of between 7 and 8 Bcf per well. So we've got very good results with especially one of our wells out there. And so we don't really see any reason to change there.

Unidentified Analyst

Okay. And then one last question just, I know December production averaged 55.1 and what was the exit rate for '08 and where do you guys expect that to be in, in '09?

James Volker

55.1 was the exit rate because that was December. That was down from 55.5 for the quarter. That is set forth on the slides and then the press release. That's the result of the increment (ph) weather at Sanish and in terms of... go ahead Mike if you want to give him a rate based upon the 12% overall.

Michael Stevens

For all of '09?

Unidentified Analyst

Just the exit rate for Q4

Michael Stevens

It's around when it comes right back right around 54 to 55,000 barrels BOEs a day.

Unidentified Analyst

Okay. Thanks guys.

Operator

Your next question comes from a follow-up from the line of Eric Hagen with Banc of America. Please proceed.

Eric Hagen - BAS-ML

Hey Jim. Just a question on Bakken differentials, I was just wondering if you could just help to break it down a little bit, how much it costs to ship via the pipeline versus, I mean maybe trucking it out of state or railing it and how that mix might be shifting going forward?

James Volker

Okay. Chuck will take a crack at that one.

Chuck LaCouture

Eric, are you talking about shipping on Enbridge or are you talking about shipping on our barrels in the field?

Eric Hagen - BAS-ML

On Enbridge?

Chuck LaCouture

Currently the tariff rate on Enbridge is about $2.08 to 2 LX (ph). To get into there is about $3 on trucking. So that is the net transportation cost to get it to the market at Clearbrook. Once we have our pipeline in place later this year, it would be reduced by approximately $2. So we will see a roughly $3 or $3.50 at the least pricing to Clearbrook.

Eric Hagen - BAS-ML

Okay, great. Thanks a lot.

James Volker

Good thanks for calling back Eric.

Operator

(Operator Instructions) And you have no further questions at this time. I would now like to turn the call over to Jim Volker for closing remarks. Please proceed.

James Volker

Thank you. In closing, I'd like to emphasize our intent to keep our CapEx in line, I'd say approximately with our discretionary cash flow in 2009 as it relates to our base drilling budget. And at the same time, we continue to expect production growth in 2009.

Despite the current volatility in commodity prices in the markets, I would like to underscore the excitement all of us at Whiting are feeling about continuing to execute on our Bakken drilling play as well as our Postle and North Ward Estes CO2 projects. As a result of these projects, we expect to show year-over-year organic production growth in 2009.

I'd also like to mention several events that Whiting will be participating in over the next several weeks that may give us the opportunity to meet with you personally. We'll be presenting at the Raymond James 30th Annual Institutional Investors Conference at the JW Marriott in Orlando, Florida. We're scheduled at 2:15 PM Eastern Time on Monday, March 9th. We will also be presenting at the Oil and Gas Symposium at the Sheraton the New York Hotel and Towers which is scheduled for April 20th and we'll be there until the 22nd.

We look forward to seeing and speaking with you at those events. And in closing, I would like to thank all of you on this call for your new or continuing increase in Whiting Petroleum Corporation, and I want to express my personal thanks to all Whiting employees and our directors for their contributions to Whiting's performance. Again, 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. Have a good day.

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