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Whiting Petroleum Corp. (NYSE:WLL)

Q1 2008 Earnings Call

May 5, 2008 4:00 pm ET

Executives

John Kelso - Director of IR

Jim Volker - Chairman, President and CEO

Mike Stevens - VP and CFO

Mark Williams - VP of Exploration and Development

Analysts

Nicholas Pope - JPMorgan

Robert Lynd - Simmons and Co

Duane Grubert - CRT Capital

Wayne Andrews - Raymond James

Biju Perincheril - Jefferies & Company

Wayne Andrews - Raymond James

Eric Hagen - Merrill Lynch

Jack Aydin - KeyBanc Capital Markets

Jeff Robertson - Lehman Brothers

Dave Tameron - Wachovia

Operator

Good day, ladies and gentlemen, and welcome to the first quarter 2008 Whiting Petroleum Corporation Earnings Call, during which Whiting management will also discuss today's announcement of its property acquisition from Chicago Energy. (Operator Instructions).

I would now turn the call over to your Mr. John Kelso, Director of Investor Relations. Please proceed, sir.

John Kelso

Thanks, Towanda. Good morning or actually good afternoon and welcome to Whiting Petroleum Corporation's first quarter 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; and Bruce DeBoer, Vice President, General Counsel and Secretary.

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

In this call, we use the terms probable and possible reserves, which are unproved reserves that we do not include in our SEC filings. Please refer to the news release or our webcast 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 will turn the call over Jim Volker.

Jim Volker

Thank you, John. Ladies and gentlemen, we will try to go through this at a brisk but complete pace here this today, so that we can get to your questions. At the end of this conference call, we will discuss today's announcement of our property acquisition from Chicago Energy Associates.

We were very pleased with our first quarter results and our 2008 plans, and we look forward to discussing with you our plans and our results. We will also answer any questions you have following the presentation.

I would like to begin by stating that through April, I believe that Whiting team has gone three-for-three at that; first, by starting our organic growth with the drillbit and our CO2 projects. Second, by selling a unique offering, the Whiting USA Trust I, which provided investors the opportunity to participate in strong oil and gas pricing fundamentals through ownership of a net profits interest in the lowest risk form of oil and gas reserves, proved, developed, producing reserves. For Whiting, this offering allowed us to sell 6.9 million BOEs at $31.18 per BOE after our expenses.

Third, we have agreed to acquire 115.2 Bcfe of gas reserves in the Flat Rock Field of Uintah County, Utah. This field currently produces 19 million cubic feet of gas a day net to the interest of the acquired and has a potential for substantial reserves and production growth. We believe this to be a world-class gas reservoir. My thanks go out to all Whiting employees for your contributions to this great hitting performance.

On my previous comments I think you can see we are especially pleased with the execution of our drilling programs and the implementation and expansion of our two CO2 projects. We continue to generate excellent results from our Bakken drilling program in North Dakota where we recently brought in the Maynard Uran Trust No. 11-24 with an initial production rate of 2,132 BOEs per day. We own an 84% working interest and a 68% net revenue interest in this well.

We are completing the construction of our Robinson Lake gas processing plant in the Sanish field, and we expect gas and natural gas liquids sales to begin from this area by June 30. We also completed the installation of a 2.9-mile pipeline at our Boies Ranch prospect in the Piceance Basin, and expect to bring on more than 6 million cubic feet of gas per day net to our interest from seven wells at Boies Ranch by June 1.

In addition, both of our CO2 projects are responding to CO2 injection, and we expect to see continuing production increases from both CO2 floods as the year progresses. We have increased our exploration and development budget by $100 million to $240 million for 2008. The majority of this increase is related to increased expenditures on our multiyear CO2 project at North Ward Estes, where we have increased expenditures to accelerate construction and the completion of certain projects.

On April 30, 2008, Whiting closed the initial public offering of 11,677,500 units of beneficial interest in the Whiting USA Trust I at $20 per trust unit. The trust units began trading on the NYSE on April 25 under the symbol WHX. After completion of the offering, Whiting owns 15.77% of the 13.86 million total outstanding trust units. We have received net proceeds from this offering of $215.4 million, which we used to reduce the debt outstanding under our credit agreement to $80 million currently from $290 million at March 31, 2008.

Our borrowing base remains at $900 million with $820 million available. Just to make the math simple for everyone there, at March 31 we had 290 million outstanding in April, we borrowed another $10 million, then we paid down $220 million, so the debt is $80 million. This debt reduction brought our current debt to total capitalization to 31% at that point in time. As reflected in our guidance, average production in 2008 has been reduced by approximately 3100 BOEs per day subsequent to the April 30, closing of the press. This represents 7.4% of our total production for March 2008. That is 7.4% of 41,800 BOEs per day.

The 8.2 million BOEs of proved reserves conveyed to the trust represented 3.27% of our total year-end 2007 reserves of 250.8 million BOEs. After netting the company’s ownership of 2.19 million units, third party public trust unit holders received 6.9 million BOEs of proved producing reserves or net-net 2.75% of the company's total year-end 2007 proved reserves. Based on the net proceeds from the initial public offering, of $215 million, Whiting received $31.18 per BOE from this offering.

Turning to our Bakken play, our net production from the middle Bakken formation in the Sanish and Parshall fields of North Dakota, totaled 3,344 barrels of oil per day during the first quarter of 2008. This represents a 92% increase in that same volume number over the fourth quarter of 2007. Net production from these fields in March rose to 4,153 barrels of oil per day or 9.9% of March's 41,800 BOEs per day.

In our Sanish field, in Montreal County, we completed the Maynard Uran Trust 11-24H on April 23, flowing 1,923 barrels of oil and 1.3 million cubic feet of gas per day from the Middle Bakken formation at a vertical depth of approximately 10,300 feet. On an equivalent basis, this equates to the previously stated 2,132 BOEs per day.

The triple lateral was drilled on a 1,280 acre spacing unit and penetrated more than 20,000 feet of horizontal pay. Whiting holds an 84% working interest and 68% net revenue interest in this new producer and of course we are the operator. We are currently drilling or completing 6 wells in the Sanish field, 4 operated, 2 non-operated, and one well is waiting for the lateral to be drilled.

We are also completing a 100% working interest well in the northern portion of the neighboring Parshall field. This well is known as the Lee State 44-16H well. We expect to have as many as 9 rigs working in the area by year-end 2008.

In 2008, we plan to drill approximately 36 operated wells in the Sanish with an average working interest of 81%. We expect most of these to be single-lateral wells drilled on 1,280-acre spacing units. Ultimately, we may drill two single-lateral wells per 1,280-acre spacing unit. Along with some potential in-fill drilling, we estimate we could have up to 230 total well locations in the Sanish field. Our net production in the Sanish field alone in March 2008 averaged 1,175 barrels of oil per day.

We are completing construction of our Robinson Lake gas processing plant in the Sanish field and expects gas and natural gas liquids sales to begin by June 30. The plant is expected to initially process its current capacity of 3 million cubit feet of gas per day.

In the fourth quarter, capacity is expected to be expanded to 33 million cubic feet of gas per day. The gas produced from the Sanish field contains large amounts of NGLs and has a BTU content of approximately 1,700 BTU's per cubic foot. The yield from the plant is expected to approximate 150 to 170 barrels of NGLs per 1 million cubic feet of gas.

Immediately east of the Sanish field is the Parshall field , where we have participated in a total of 37 wells that produce from the Bakken formation, 13 of which were completed in 2008. We expect to participate in a total of 50 to 60 wells in the Parshall field in 2008 with an average working interest of 20%. Nine drilling rigs are currently working in the Parshall field. Whiting's net production from the Parshall field alone in March 2008, averaged 2,978 barrels of oil per day.

Moving to the Piceance Basin in North West Colorado; we have completed seven new gas wells to-date in 2008 that are currently waiting on pipeline connections. These new wells, which will drilled in the Boies Ranch prospect of Rio Blanco, County Colorado are expected to be connected to pipeline by June1 and are expected to add 6 million cubic feet of gas per day net, and bring our total sales at Boies Ranch to more than 7 million cubic feet of gas per day.

Whiting holds an average working interest of 96% and an average net revenue interest of 82% in the seven new gas wells. In addition, four wells are currently waiting on completion and two wells are currently being drilled at Boies Ranch.

We recently completed a 2.9-mile, 10-inch diameter pipeline that has a daily capacity of approximately 80 million cubic feet of gas at Boies Ranch. Start-up of the pipeline facilities is expected to occur by June 1. Our new pipeline connects to a supply trunk line feeding a 750 million cubic foot per day, treating and processing facility connected to the Rockies Express pipeline or REX. That gives us access to multiple intrastate and interstate markets. Our new pipeline connection will allow us to market all of our gas at Boies Ranch without restriction. The 42-inch diameter REX pipeline currently has a capacity of transporting 1.5 Bcf of gas per day. And when REX came onstream in January 2008, Rocky Mountain gas price differentials narrowed significantly.

I would now like to update you on the progress we have been making at our two CO2 project. Our expansion of the CO2 project at our Postle field located in Texas County, Oklahoma, continues to generate positive results. Production from the field has increased from a net 4,200 BOEs per day at the time of its acquisition in August 2005 to more than 6,200 BOEs per day in March 2008, an increase of 48%. Many thanks to our Postle team for this accomplishment.

In January, we have also achieved our objective of increasing CO2 injection into the fields producing more oil sand reservoir to 120 million cubic feet of gas per day, thereby doubling the 60 million cubic feet of CO2 per day at the time we acquired the field. We expect to see increases in production from this greater injection by Q1 2009.

Moving to our North Ward Estes field in the Permian Basin, we are seeing an initial response from our CO2 flood that was initiated in May of 2007. Whiting's target for CO2 injection into the field was 100 million cubic feet of CO2 per day by the end of the first quarter of 2008. This milestone was actually reached in January 2008, and we are currently injecting approximately a 120 million cubic feet of CO2 per day in the Yates formation, the fields producing reservoir, at a depth of approximately 2,600 feet.

Net production from the North Ward Estes in 2008 averaged 5,200 BOEs per day, which compares to a net daily rate of 3,560 BOEs during the first quarter of 2005, prior to Whiting's July 2005 agreement to acquire the North Ward Estes field. Congratulations to our North Ward Estes team for successfully executing on this project on schedule and with great efficiency.

Companywide, we are currently running 17 operated drilling rigs, five in the Williston, three in the North Ward Estes field, three in the Postle field, two in the Permian Basin, two in the Piceance Basin, and one in the Gulf Coast region. We are also operating one rig in Michigan. We are also participating in the drilling of 12 non-operated wells, most of these in the Parshall field. In addition, we have 51 workover rigs in service, 27 of these in the North Ward Estes field and six in the Postle field.

Mike Stevens, Whiting's Chief Financial Officer will now discuss some key financial results.

Mike Stevens

Thanks, Jim. In the first quarter of 2008, we set company records in total revenues, net income, net income per share and discretionary cash flow. Our net income in the first quarter was $62.3 million or $1.47 per basic and diluted share on total revenues of $264.1 million.

In the first quarter of 2007, net income totaled $10.7 million or $0.29 per basic and diluted share on total revenues of $159.9 million. Discretionary cash flow in the first quarter of 2008 totaled $161.4 million compared to the $74.1 million reported for the same period last year. The increases in first quarter 2008 net income and discretionary cash flow, compared to the first quarter of last year were primarily the result of a 64% increase in our realized oil price and 25% increase in our realized gas price and a 6% increase in our total equivalent production.

During the first quarter, our companywide basis differential for crude oil compared to NYMEX was $8.38 per barrel, which compared to $8.79 per barrel in the first quarter of 2007 and $8.25 per barrel in the fourth quarter of 2007. We expect our oil price differential to remain in the $8 to $8.50 range in 2008.

During the first quarter, our companywide basis differential for natural gas compared to NYMEX was $0.14 per Mcf, which compared to $0.44 per Mcf during the first quarter of last year and $0.60 per Mcf in the fourth quarter of last year. We expect our gas price differential to be in the range of $0.30 to $0.50 during the rest of 2008.

Production in the first quarter of 2008 totaled 3.74 million barrels of oil equivalent, of which 69% was crude oil and 31% was natural gas. This first quarter 2008 production total equates to an average production rate of 41,120 barrels of oil equivalent per day. This compares to the 39,260 BOEs per day average rate in the first quarter of last year. This also represents a 2% increase from the fourth quarter 2007 daily average rate of 40,340 BOEs.

As to our guidance, the midpoint of production guidance for the upcoming second quarter is 3.7 million BOEs and the midpoint of our full year production guidance is $15 million BOEs. This guidance has been reduced by 190,000 BOEs and 725,000 BOEs for the second quarter and full year 2008 respectively as a result of the recently completed trust offering. Therefore, our full year guidance represents a replacement of the 725,000 BOEs of production sold through the royalty trust, plus 2% growth over 2007.

The guidance has not been updated to include the impact of the acquisition from Chicago Energy. Whiting intends to update guidance to include the impact of this acquisition after the expected May 30, 2008 closing. Whiting estimates the net production from the property to be acquired from Chicago Energy with 19 million cubic feet equivalent per day in March 2008.

As a result of the trust sale, during the second quarter we will record a deferred gain of $112.4 million in the long-term liability section of our balance sheet. This gain will be amortized to income using the units of production method over the life of the trust. Estimated amortization is $3.1 million for the second quarter of 2008 and $12 million for the entire year.

The general and administrative expense guidance for the second quarter and full year include the charge of $7.7 million under our production participation plan, related to the conveyance of a net profits interest into the trust.

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

Jim Volker

Thank you, Mike. I would now like to quickly review the key points in the slides of our webcast, which we hope will provide some more color on our primary operating areas.

First, of course, please take special note of our statement of disclosure, reserve information and non-GAAP measures, especially risk factors contained therein. Go into page 2, please note that our market cap is currently up to $3.2 billion, and at the bottom, our net production is 41,800 BOEs per day in March.

The great news on slide 3 is shown the left-hand column there, $62.3 million of net income, $1.47 a share and $161 million of discretionary cash flow, all up smartly from the year ago period.

As you can see, on page 4, that is $1.47 per share. On page 5, $161.4 million of discretionary cash flow. On page 6; I would just like to call your attention to the far right-hand column of the table there and say that in each of our regions, wherein we are now producing 41,800 BOEs per day, they are all up somewhat from the 40,300 barrels in December of 2007.

Moving on to page 7; I think the most important point here are points A and B, that is we are experiencing, I would say beginning to experience moderate risk organic growth from Postle and North Ward Ester and some significant organic growth potential from our drilling programs in the Williston, the Piceance and not the Uinta Basin.

On page 8, we continue to apply our acquired, exploit, explore and from time-to-time monetization of some PDP reserves, just as we did through the trust.

On page 9, I call your attention to the second column from the right, Here our SEC PV10 value of $5.8 billion at year end.

And on page 10, I think two important numbers here can be seen in the second column from the right. This is the column entitled millions of barrels of oil equivalent. I have already talked about the 250.8 million BOEs approved. I would also like to point out here, the 242.7 million BOEs, that’s the combination of probable and possible reserves, i.e. an amount about equal to our existing proved reserves in those two categories, which we are working to move into the proved category.

Our net asset value calculation can be seen on page 11, but I would simply like to say, if you look at the bottom line there, its including the probable and possible reserve values, we want you to read footnote three here, in order to get a good understanding of the probable and possible reserves, it is $226 a share. If we had stopped meaning at the $5.8 billion, five lines down in the far right-hand column and then deducted all of the negative shown here on page 11, the number would be $111 a share.

The key slide is slide 12. I would like to call your attention to the top line on that page, especially for the years 2004 and 2005. As you can see there, we made substantial acquisitions, $525 million and $906 million in those two years and then acquisitions slowed down as we used the cash flow from the proved developed producing reserves that we had acquired in order to fund the development cost, which you can see then rising in 2006 and 2007, three lines down in the page at $408 million and $506 million, respectively.

The net of all this is that as you can see in the second underscored section in the far right-hand column is that we believe on a fully developed and of course acquired basis our all-in development cost including future development cost of acquisition post development for our reserves will be about $17 per BOE based on proved and about $12 per BOE based on the addition of probable and possible reserves. On page 11, as you can see therefore our five year reserve replacement is 433%.

On page 14, I would like to call your attention to the fact that this application of the capital into developing our proved and developed reserves, as of January of this year our total reserve base is to be 67% developed. If you look at the center of pie chart, you will see that the green, the blue and the yellow areas our big three regions account for 90% of our reserves and then looking at the production pie chart on the right-hand side here, they account for 81% of net daily production.

The key slide is slide 15, where you can see that in addition to the increase in our drilling budget from '07 to '08 from $556 million to $740 million that light blue portion, i.e. that portion directed toward finding reserves that are currently classed as non-proved is up to 47%, up from 27% in 2007.

Then on page 16, where is that being applied. Well, as you can tell in our two big regions, on the right-hand pie chart 56% into the Rocky's, 26% into the Permian or total of 82% in our two biggest regions.

As a consequence on page 17 of the paydown of debt, which occurred first the closing of the royalty trust, Whiting's debt to total cap came down to 31%.

On page 18, in the far right-hand column, you can see on that bar chart that, our margins have increased as a result of higher oil and gas prices such that our weighted average price per BOE of $70.50 is producing an EBITDA margin of 65% or $45.53 per barrel.

On page19, I would like to point in lower right-hand column in that white box, we have 883,000 net acres.

Moving to page 20, again in the white box, of that 883,000; 401,000 is undeveloped.

And now I would like you to look at the box entitled Rocky Mountains, where you can see 300,000 of that 400,000 exists. Consequently that should tell you where we have been putting our acreage money over the last couple of years.

On page 21, I call our attention please to the; under the Bakken section, the last two bullet points where it shows that, we drilled 33 wells in 2007, approximately 36 operated wells and 20 non-operated wells are planned for the Sanish field in 2008. And then we, plan to participate in 50 to 60 non-operated wells in the Parshall field in 2008.

May I direct your attention to the very last page, that is, bullet point on page 21. In our Red River play, we expect to drill seven wells and run one new 3-D seismic program in 2008.

Page 22, is I think a great map, it shows a lot of things. But in large part, I think the most important is that in the Sanish field, I mean in the initial rate section here in the lower right-hand portion that over the first 30 days those five wells averaged 856 BOEs per day, and the Parshall field over a longer period of time, 120 days, that over 20 wells averaged 618 BOEs per day.

Looking at the extreme lower right-hand corner, currently Sanish and Parshall have 9 and 36 wells respectively producing, five and nine respectively completing, seven and seven drilling, this includes non-operated as well as operated, and there are plans to drill 50 to 60 wells in each field that is both operated and non-operated during 2008.

Moving to page 23, our plans in terms of operated drilling in the Sanish portion of the Bakken area here shows up quite nicely in this white box, the bottom of the page, where it shows again 36 wells with an average 82% working interest for 2008, and over the next three years in total, roughly 118 operated and about 52 non-operated, and adding about another 60 here for infill drilling which basically is the open space between the gray lines that you see in each two sections unit, that number would go up by about another 60 wells to approximately the 230 that we quoted earlier.

On page 24, here are all of the IP rates for the last five big wells we drilled up there. As you can see, they range from 1,000 to 2500 BOEs per day on a 24 hour test.

Moving to the Piceance on page 25, it's clear here we have a 110 wells planned on 20 acre units, about $207 million drilling budget at December 31, 2007, over about a three-year period and the estimated cost per well about $2.8 million.

In the lower right-hand corner of page 26, you can see the current status there. We have two drilling, seven completing and also waiting on completion. So, total of 11 wells there in one form of completion or another and three producing. As we have said before, seven of those that are in the completion or completing stage should be on production soon.

Moving on to page 27, in the far right-hand column of the dark blue box at the top of the page, you can see that these two CO2 projects, Postle and North Ward Estes represent 59% of our reserves and 29% of our current production.

On page 28, I would like to point out that again on a fully acquired and developed cost we think the proved reserves from these two fields will end up being just under $17 per BOE acquired and developed. With the assumption of the probable and possible reserves being added at nominal cost of only about another $150 million, that drives our total acquired and developed cost here down to $10.62.

As you can see in the lower right-hand corner of page 29, we are over the big CapEx hump at Postle, and going forward now, of the $259 million we expect to invest going forward, $152 million of that is for CO2 purchases alone and about $107 million is for hard CapEx.

Some good pictures for you of the installation of the Dry Trail plant there, which is now, as we have mentioned, over 100 million cubic feet of gas going into the ground everyday.

Moving on to North Ward Estes on page 31, as we have mentioned before and as you can see in the last bullet points, we are over 120 million cubic feet of CO2 going into that reservoir everyday into the brown colored start-up area. The design is stated on page 32, just as Postle, is modular and energy efficient.

Moving onto page 33, as you can see there are five phases in our plant to develop North Ward Estes. They extend through 2015. CapEx necessary to do that is estimated at about $625 million, and we have just crossed over the top here in the sense that again now the CO2 purchases exceed estimated future hard CapEx.

On page 34, I would like point out remind people that when we bought this we attributed about 80 million barrels of proved to North Ward Estes, but now with greater study we think, including the probable and possible reserves, reserves are up to about double that were 162 million BOEs.

Moving on to page 35, as a consequence of our investments of possible in North Ward Estes, you've already seen substantial increase in production of Postle and we hope to drive the production up to between 8,000 and 9,000 BOEs a day by 2012 net to our interest and up to between 10,000 and 13,000 BOEs a day net to our interest at North Ward Estes by 2014.

As you look at page 36, you can see based on current volumes; that is as of March 2008, we have about 36% of our oil production, none of our gas production hedged, and after that, our hedges come-off.

We do have some hedges that we have placed on the trust and you can see those on page 37. Whiting owns 24.2% of the beneficial affect of those hedges, and they are outlined for you there as to the floors and the ceilings on both gas and oil for the trust.

In summary, on page 37, Whiting is all of these things listed here and that we have gone over in great detail with you today. I would like to now sort of exit the slides if you would not mind, and just kind of get back to the regular portion of our conference call. In doing so, I would like to now make a couple of comments about this morning's announcement of our Uinta Basin property acquisition from Chicago Energy Associates.

There are two slides regarding the Chicago Energy Associates on our webcast. As you can see, we have entered into a purchase and sale agreement with CEA to purchase 115.2 Bcfe of proved reserves, as well as a 44-mile gathering system and development acreage in the Flat Rock Natural Gas Field in Uintah County, Utah. The purchase price was $365 million. And frankly, we think this is a world-class gas reservoir. After allocation of $35 million to the purchase price of the gathering facilities, the remaining $330 resulted in an acquisition cost for the proved reserves of $2.86 per Mcfe.

The affective date of the acquisition is January 1, 2008, and closing is expected to occur on May 30, 2008, subject to standard conditions to closing and the approval by CEA's members. Whiting will finance the acquisition with borrowings under its existing bank credit facility. Our borrowing bases, $900 million and we have $820 million currently available. Therefore post the acquisition, our debt to total cap will be 41%. So, we are very comfortable at that level at 41%.

The proved reserves contained in the flat rock field are 98% natural gas, 22 prove producing and 78% proved undeveloped. In March 2008, net daily production from these properties averaged 19 million cubic feet of gas a day at approximately 38% of the current net rated buyings from the field will be operated by Whiting. And 97% of the current production or 18.5 million cubic feet a day is from seven wells producing from the prolific Entrada standstone formation, at a debt of approximately 11,500 feet, while only 3% comes from some low volume wells numbering 24 that produce from the shallower Wasatch and Dakota formations.

Importantly, 49 square miles of 3D seismic support the current plan of approximately 59 additional to more fully develop the prolific Entrada formation on the 22,029 gross and 11,534 net acres included in this acquisition. Of these 59 additional wells, Whiting expects to operate 15 while 44 are expected to be operated by another experienced area operator. The Entrada formation in this area has been found with a more than a 100 feet of net gas pay.

Gas gathering assets in the acquisition include 44 miles of lines, compression and processing facilities that deliver the gas to the Questar Mainline 40 interstate pipeline.

With that, I would like to open up the conference call to questions.

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from the line of Nicholas Pope with JPMorgan. Please proceed.

Nicholas Pope - JPMorgan

Hey, guys.

Jim Volker

Hi, Nick.

Nicholas Pope - JPMorgan

I was hoping to if you could tell us how much those, the Bakken oil, the recent Bakken oils cost, specifically the, I think those two new ones there, the tri-lateral and the single-lateral?

Jim Volker

$6 million.

Nicholas Pope - JPMorgan

$6 million. All right. And then jumping into this, the Uinta properties, of those 59 wells, how many of those are booked as PUDs?

Jim Volker

14

Nicholas Pope - JPMorgan

14?

Jim Volker

14m 11 would be probables and 34 would be classed as possibles.

Nicholas Pope - JPMorgan

Okay. You have, are you all ready to talk about how much these wells could cost and what kind of reserves you are talking about for the Entrada wells?

Jim Volker

Yes, we think verticals wells are cost somewhere around $4.2 million per vertical well. We drilled some of them directionally, somewhere around 4.9 to 5.3 Nick, at an average of about $4.35 million for all 59 wells.

With respect to the average reserves, at least with respect to the PUDs we would estimate about 10 Bcf per well and we think we have about an average 78% to 79% working interest in those. As to the probables, where we think we will have 37.5% working interest on average. We think those may have about 12 Bcf and I might say that is based upon some independent engineering that was done on those probables and then also based upon some independent engineering of the possibles we guesstimated about 17 Bcf per well. The reason for that is basically a thickening of the zone in that direction. And then, we think we have about 44.8% average working interest in those 34 possible wells.

Nicholas Pope - JPMorgan

Okay. That is great. And then, I was wondering, have you all thought about 2009 production you had at this point. I mean it looks, there are a lot of growth areas coming here now, have you all thought about what kind of growth rate you all might be thinking about for 2009 at this point.

Mike Stevens

Obviously we have thought about it Nick. We are just not quite ready to hatch that egg yet.

Nicholas Pope - JPMorgan

Okay. I thought that. Thanks a lot guys.

Jim Volker

All the best.

Operator

Your next question comes from the line of Robert Lynd with Simmons and Co. Please proceed.

Robert Lynd - Simmons and Co

Good afternoon.

Jim Volker

Hi, Robert.

Robert Lynd - Simmons and Co

Jim, back to the Sanish field, is the decision to do a tri-lateral being made on the fly based on what you are encountering, as you drill?

Jim Volker

No that one was designed as a tri-lateral. There were some specific reasons for that, having to with, what I would call some science work we wanted to do on that well. I would say that the decision has been made that unless conditions change going forward, virtually all the wells you see us drill will be single-laterals over 1280s. And we intend to drill just as that plan and the slide shows two single-laterals within each 1280. And then perhaps come back in-field in that spaced between the 1280 units. That gets us up to the 230 locations.

Robert Lynd - Simmons and Co

Okay. So just modeling the program $6 million well cost is sort of what we should see it as?

Jim Volker

Yes.

Robert Lynd - Simmons and Co

Okay. Thanks, that is all I have. I will get back in the queue.

Jim Volker

Great.

Operator

Your next question comes from the line of Duane Grubert with CRT Capital. Please proceed.

Duane Grubert - CRT Capital

Yes, Jim when you described your acquisition as being a world class reservoir. Can you elaborate a little bit on what you really like about it, and how you cost? You are thinking about your Uinta program versus your Piceance program going forward?

Jim Volker

Mark's been hoping that you would ask that question Duane. So I am going to let him answer that one. Thank you for asking.

Mark Williams

The Entrada reservoir here has a few different characteristics than most of the Uinta Basin production, which is typically the Mesaverde or the Wasatch. It's a deeper reservoir, it's older in age, it has far better reservoir quality. The velocity typically is 12% with relatively high permeability and low water saturation. But importantly, it has a very high net to gross. It has up to 200 feet of gross interval. But within those 200 feet, up to 140 feet of it is net pay. So, the sands are clean, very continuous over a broad area. It's an Aeolian reservoir similar to the Navajo Formation or the Minnelusa in the Powder River basin. That is really what accounts for better reservoir characteristics. So, it's very resolvable with 3D seismic, and we study that very carefully and feel like we understand both the size and the character of the reservoir pretty well.

Duane Grubert - CRT Capital

Okay. And then, the nature or part of your development wells in the Entrada being possible, what's your chief certainty at this point?

Doug Lang

This is Doug. Really our reserve specification is strictly due to SPE. So, we have our PUDs, which are direct offsets to production, and then we have our probables or one more location way, and then, all the rest by definition or possibles. But they are geologically an extension of the field to the north. So, until we step our way out there, they will have to be possible.

Duane Grubert - CRT Capital

Okay, great. That is very encouraging. Jim, if you could maybe walk through how you think about the Piceance versus the Uinta going forward?

Jim Volker

I guess, let us say, to put it back in baseball metaphor that I used earlier, I think about the Piceance essentially as being hitting some good doubles, and I see potentially anyway this reservoir in the Uinta, not all reservoirs in the Uinta, but this particular Entrada reservoir is potentially, frankly, being a homerun for us.

Duane Grubert - CRT Capital

Okay. That is real helpful. Thank you very much.

Jim Volker

Thank you.

Operator

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

Wayne Andrews - Raymond James

Good afternoon, Jim, gentlemen.

Jim Volker

Hi, Wayne.

Wayne Andrews - Raymond James

Maybe you can comment a little bit, Jim, on what other spending, I noticed you increased the budget at North Ward Estes, and maybe could you be more specific on what sort of construction and projects you are adding to increase that budget there?

Jim Volker

Okay. Well, about $88 million out of that $100 million is represented by roughly $47 million of that's coming from acceleration of Phase II, because frankly things are going very well, and about $41 million is just purchasing CO2 at a somewhat faster rate.

Wayne Andrews - Raymond James

Very good said. And what signs are you seeing there other than the reserve growth -- I'm sorry -- the production growth looks pretty outstanding, so you'd expect those fields to be continuing to rise in volumes through the remainder of the year?

Jim Volker

We do. We are pleased with the rate at which the reservoir seems to be processing the CO2. In part, it may be going faster for us than it did on the pilot that the major oil company did there, because our team up there made special effort to really clean out both the producers as well as the injectors there. Also, we made special efforts to make sure that our water injection system puts in good, clean water. So that may be some of the reason for the somewhat faster processing that we are seeing. We are not quite ready yet to yell "Eureka!" but we'd like to watch if for most of this year. But anyway, we are positive enough about it that we are going to do this acceleration.

Wayne Andrews - Raymond James

Excellent, sounds very encouraging. If I look at that, I mean that is a substantial part of your volumes that will be accelerating, and then kind of walk through some of the math on your drilling efforts in the Bakken, and add in a Boies Ranch pipeline coming on in June, I get to numbers that are little bit higher than your guidance. Maybe comment on your thoughts if there is potentially any upside there in the remainder of the year?

Jim Volker

Yes. I noticed that you did not say we were sandbagging, but Jack did.

Wayne Andrews - Raymond James

Well, I think we are all coming at the same conclusion.

Jim Volker

Anyway, we are just trying to be conservative here. If we were maybe another 90 days down the road, we'd be a little bit more optimistic and be a little quicker to raise our guidance for the rest of the year. So, I just ask your forbearance here for this particular quarter, let us skid about 90 days down the road.

Wayne Andrews - Raymond James

We will be looking forward to hearing from you again soon. Thanks, Jim.

Jim Volker

Thank you.

Operator

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

Biju Perincheril - Jefferies & Company

Hi, good afternoon. Congratulations on a very good quarter.

Jim Volker

Thank you, Biju.

Biju Perincheril - Jefferies & Company

In the Bakken, we have seen some increased permitting activities into the play to the north, are you looking to pick up any acreage additional acreage that way or are you quite happy with what you have for now?

Jim Volker

Well, we would like to acquire more acreage, obviously, as the land grab is done out there, and at this point we have to buy somebody else out. As we look around our acreage, we would not want to go too far east of Parshall. North still looks good for us, although, I think everybody is aware that the wells to the north aren't quite as prolific as the ones that we and EOG have drilled. What I would call the sweet spot here of the Bakken, was naturally outlined by their acreage position and our acreage position. We are encouraged Biju by the fact that based upon the drilling that's been done by others in our acreage position that everything that we have, that's as our acreage goes appears to be productive to us and our permit well also.

To the south fewer wells have been drilled as you know, that abuts against a reservation down there and of course the lake. So we do not know as much as that going south. We do know that another company, another large, and sophisticated producer did take a deal down there on the reservation and left down there.

Biju Perincheril - Jefferies & Company

Okay. Going back to the acquisition you talked about 59 wells to be drilled. Can you give us some timing on that?

Jim Volker

Sure. Doug, will do that for you here.

Doug Lang

Its early in the development here it will be subject somewhat to our plans and the other operator in the field. The way we sort of engineered it, it takes about seven years to get all these wells drilled. I really believe it will be compressed into a shorter timeframe.

Biju Perincheril - Jefferies & Company

Okay. What will be the timing for converting some of the other probables and possibles. I would imagine initially you will be drilling up the PUD locations or…

Jim Volker

Right. As I said before there are 14 PUDs and basically we have those being drilled now with a few in '08, about eight in '09 and about four in 2010. Then just logically the locations switch to the probable category. We got 11 of those currently in the schedule and those would occur in 2010. And then the remaining 34 possibles gets spread out sort of from the last half of 2010, all the way through first part of 2014.

Biju Perincheril - Jefferies & Company

Okay, perfect. What do you think your CapEx will be on this property this year, once the transaction is complete?

Jim Volker

Well, as Doug was saying we scheduled only a couple of wells, operated wells this year in round numbers those would be about $8.7 million to $9 million.

Biju Perincheril - Jefferies & Company

Okay.

Jim Volker

However, we are cautioning ourselves here to the fact that, on the jointly owned acreage where we own about 37.5% -- let me just kind of run through that acreage for you after I make this point. We expect the operator of that acreage, which is a large sort of E&P/utility company based here in the west with what we consider to be a very professional and highly confident personnel who are going to get drafted out there. And so we realized that some of this CapEx maybe accelerated forward.

Then to answer the question I posed myself about the acreage. In summary, we have about 5,109 gross acres where Whiting has 100% working interest. Well, that is obviously 5,109 net working interest acres. We have got about 640 acres where our working interest would be 50%, well that’s 320 net acres and then we have 16,280 gross acres on which we have 37.5% working interest or 6,105 net. When you add up the grosses you get the 22,029 and the net is 11,534.

Biju Perincheril - Jefferies & Company

Perfect. Thank you.

Jim Volker

You are welcome.

Operator

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

Eric Hagen - Merrill Lynch

Hi, good afternoon.

Jim Volker

Hi, Eric.

Eric Hagen - Merrill Lynch

Another question regarding Uinta Basin. Is there any need for an EIS, are there any drilling restrictions out there?

Mark Williams

No. None at this time.

Eric Hagen - Merrill Lynch

Great. The second was just a little bit of housekeeping. So on the second quarter, the deferred, I missed that, the deferred gain is $120 million, was that right or $112 million?

Mike Stevens

$112.4 million.

Eric Hagen - Merrill Lynch

And that's about $3 million a quarter?

Mike Stevens

Yes, roughly. That goes up to about little over $4 million a quarter after the second quarter because we only have it after months in the second quarter.

Eric Hagen - Merrill Lynch

Okay. In terms of any cash tax impacts, should we model a higher cash tax rate in that quarter?

Mike Stevens

No. Right around 37% net effective tax rate.

Eric Hagen - Merrill Lynch

Great. And in plans for 2009 in the Bakken still around nine rigs to be…

Jim Volker

Absolutely.

Eric Hagen - Merrill Lynch

Okay, good. That is all I had. Great quarter, thanks.

Jim Volker

Thank you, Eric.

Operator

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

Jack Aydin - KeyBanc Capital Markets

Hi, Jim. I knew I will get your attention.

Jim Volker

Hi, sandbag. How are you doing?

Jack Aydin - Keybanc Capital Markets

Hi, how are you?

Jim Volker

Good.

Jack Aydin - Keybanc Capital Markets

Most of the questions are answered, but I know you are drilling a well next to the EOG Austin well and you are hoping to get some results soon. Where we stand on that well?

Jim Volker

Just getting ready to complete it, I do not have a rate for you yet, Jack. But the thing drilled like a charm and we had great shows where we were drilling.

Jack Aydin - Keybanc Capital Markets

And that's on 12,080 acres of 640 acres?

Jim Volker

640.

Jack Aydin - Keybanc Capital Markets

640 and single lateral?

Jim Volker

Yes, sir.

Jack Aydin - Keybanc Capital Markets

And still the cost about $6 million.

Jim Volker

Yes, little less.

Jack Aydin - Keybanc Capital Markets

Okay. Thanks a lot.

Jim Volker

Thank you, Jack.

Jack Aydin - Keybanc Capital Markets

Thanks.

Operator

And your next question comes from the line of Jeff Robertson with Lehman Brothers. Please proceed.

Jeff Robertson - Lehman Brothers

Thanks Jim. On the Uinta Basin acquisition, are there any other formations in that area that are perspective?

Jim Volker

Yes, there are, and we will talk about them here. I will let Mark talk about that.

Mark Williams

There are other formations that are both productive already, the Navajo produces, the Wingate produces, the Dakota and the Wasatch also produce. But all of those formations are somewhat overshadowed by the Entrada Reservoir here. But we have continued development activity in all of those other formations.

Jeff Robertson - Lehman Brothers

Are the Navajo and the Wingate below the Entrada or above it?

Mark Williams

The Navajo is below and so is the Wingate.

Jeff Robertson - Lehman Brothers

Okay. I mean what depth are those?

Mark Williams

They are at 12,500 feet at Wingate.

Jeff Robertson - Lehman Brothers

Okay. And what kind of BTU gases does this field produce out of the Entrada?

Mark Williams

1,030.

Jeff Robertson - Lehman Brothers

Okay. Thank you.

Joe Volker

Thank you, Jeff

Operator

Your next question comes from the line of John Ragozzino with Wachovia.

Dave Tameron - Wachovia

Hi. It is actually Dave Tameron.

Joe Volker

Hi, Dave.

Dave Tameron - Wachovia

Hi. How are you doing?

Joe Volker

Great.

Dave Tameron - Wachovia

Get back to the acquisition, and maybe you mentioned I apologize if I missed it, but what are these wells costing?

Joe Volker

Well, these wells have cost, round numbers, of about $4.35 million per well. We sort of give you a range here of about $4.2 million to $4.5 million for a vertical well, $4.9 million to $5.3 million for a directional well, and the average across the all 59 wells is about $4.35 million.

Dave Tameron - Wachovia

Okay. When you say directional, can you give me a little more detail on that?

Jim Brown

Sure. This is Jim Brown. Some of the topography out there is pretty rough. So you just can not locate your service location where you want it. You just have to directionally drill them to get into the appropriate bottom of the location.

Dave Tameron - Wachovia

Okay. And of the production right now, the 19 million a day, how much is coming from the Entrada versus the Wasatch and the Dakota?

Jim Brown

97%.

Dave Tameron - Wachovia

That is right there on the slide, I guess I can not read the bullet point. The other question you mentioned in the press release, you mentioned of the 59 additional wells to be drilled, 44 are going to be by the outside operator?

Jim Volker

Right.

Dave Tameron - Wachovia

And who is the operator?

Jim Volker

Well, it is a very large sophisticated energy company, headquartered in the west here. It is a combination of the utility and E&P company.

Dave Tameron - Wachovia

So, it's the same answer you gave before this one. You just won't commit the name.

Jim Volker

Yes, you could probably look around; I will give me hint at that. Salt Lake could be a good place to look for that.

Dave Tameron - Wachovia

Okay. That's what I thought. I just want to confirm that.

Jim Volker

All right.

Dave Tameron - Wachovia

I guess, that's all I got. Thanks.

Jim Volker

All the best.

Operator

Your next question is a follow-up from the line Eric Hagen with Merrill Lynch.

Eric Hagen - Merrill Lynch

Just to clear one thing, about the gas volumes were down sequentially, is that just because you are ready to hook up those wells in the Piceance with just natural declines.

Jim Volker

Yes.

Eric Hagen - Merrill Lynch

Okay. Great, thank you.

Jim Volker

Thanks.

Operator

And at this time, there are no additional questions in queue. I would now turn the call back over to management for the final remarks.

Jim Volker

Great. Thank you, Ms. Ricks and, I would like to underscore the excitement that all of us at Whiting are feeling about executing on our Bakken, Piceance and now our Uinta drilling, as well as our Postle in North Ward Estes CO2 projects in 2008. We truly believe 2008 maybe a breakout year for organic production and reserve growth of Whiting.

I would like to mention several events that Whiting will be participating in where we hope we have the opportunity to meet with you personally. We will be presenting at the Tristone Capital Global Forum in Paris, France, and we will be speaking at 11:35 am Paris time on Thursday, May 15. That will be about 5:35 am New York time, but the presentation will be available on our website live and on replay.

We will also present at the RBC Capital Markets Energy Conference at the Ritz-Carlton Battery Park at 9:05 am on East Coast time on Monday, June 2.

We will also be presenting at the Tristone Capital Rocky Mountain Energy Forum at the Brown Palace hotel here in Denver in the week of June 9 and at the COGA Rocky Mountain Natural Gas Strategy Conference and Investment Forum at the Colorado Convention Center in Denver, the week of July 9. And we look forward again to seeing you at those events.

I would like to thank al of you on this call for your new or continuing interest in Whiting Petroleum Corporation. I want to express my personal thanks to all of Whiting's employees and our Directors for their contributions to Whiting's success and our plans for significant growth in 2008, especially by going three-for-three at that through April of this year by starting our organic growth of the drill bit and CO2 production increases, structuring and selling the unique Whiting USA Trust I and by agreeing to acquire the Flat Rock field with its production of 19 million cubic feet of gas per day, its reserves of 115 BCF and its potential for growth in reserves and production.

Again, all the best and we look forward to seeing and speaking with you soon.

Operator

Ladies and gentlemen, thank you joining in today's conference. This concludes the presentation. You may now disconnect. Please have a wonderful day.

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Source: Whiting Petroleum Corp. Q1 2008 Earnings Call Transcript
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