Whiting Petroleum Corp. Q4 2007 Earnings Call Transcript

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Whiting Petroleum Corp. (NYSE:WLL) Q4 2007 Earnings Call February 28, 2008 11:00 AM ET


John Kelso - Director of IR

Jim Volker - President and CEO

Mike Stevens - CFO

Doug Lang - VP of Acquisitions and Reservoir Engineering

Mark Williams - VP of Exploration


Scott Hanold - RBC Capital Markets

Wayne Andrews - Raymond James

Jeff Robertson - Lehman Brothers

Jim Busoni - Northern Webster


Good day, ladies and gentlemen, and welcome to the fourth quarter 2007 Whiting Petroleum Corporation Earnings Call. My name is Heather and I'll be your coordinator for today. At this time, all participants are in a listen-only mode. We will be facilitating a question-and-answer session towards the end of today's conference. (Operator Instructions).

I would now turn the presentation over to your host for today's conference, Mr. John Kelso, Director of Investor Relations. Please proceed, sir.

John Kelso

Thanks a lot, Heather. Good morning and welcome to Whiting Petroleum Corporation's fourth quarter 2007 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'll review our results for the fourth quarter and full year 2007, and then discuss the outlook for 2008. 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 2007 earnings release can be found on our website at www.whiting.com. To access the call on 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 31st, 2007, which will be filed today. We disclaim any obligation to update these forward-looking statements.

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

During this 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.

We will also make references to our pre-tax PV10 which may be considered a non-GAAP financial measures as defined by the SEC and it is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure.

Pre-tax PV10 is computed on the same basis as the standardized measure of discounted future net cash flow, but without deducting the future income taxes. Pre-tax PV10 is not a substitute for the standardized measure of discounted future net cash flows, and neither of these calculations purports to present the fair value of our oil and natural gas reserves.

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

Jim Volker

Thanks John. Good morning and welcome everyone to Whiting Petroleum's fourth quarter 2007 conference call. As you can imagine, we are very pleased with our fourth quarter results and our 2008 plans, which we look forward to discussing with you on this call.

We'll also answer any questions you may have following this presentation. This is an exciting time for Whiting and its shareholders as the value of the company grew significantly from yearend 2006 to yearend 2007.

As of December 31, 2007, our pre-tax PV10 value totaled $5.86 billion and our standardized measure of discounted future net after-tax cash flows totaled $4 billion. At year end 2006, these values were $3.35 billion and $3.4 billion respectively, so pre-tax PV10 value rose 75%, primarily as a result of yearend over yearend price rises.

The year end NYMEX oil price rose from $61.05 in 2006 to $96 per barrel in 2007, and the NYMEX gas price rose from $5.52 per MMBtu to $7.10, so in 2007, and so far in 2008, it’s been good to be oily.

At year end 2007, our proved reserves were $250.8 million BOEs, of which 78% was oil. Our proved developed reserves rose to 67% of proved reserves, up from 65% in 2006 and 59% in 2005, thereby continuing the important de-risking of our reserve base. Proved developed producing reserves increased by $10 million BOEs from year end 2006. With only 27% of our 2007 capital budget directed toward adding new reserves, we increased our total reserves to $250.8 million BOEs, from $248.2 million BOEs at year end 2006.

During 2007 we produced $14.8 million BOEs, and had $2.9 million BOEs of divestitures. Offsetting this $17.6 million BOEs of production and property sales, $20.2 million BOEs of proved reserves were added. Of this $20.2 million BOEs of additions, $17.8 million BOEs was generated through extensions and discoveries, and $2.4 million BOEs came from acquisitions and revisions to previous estimates.

In 2008, we expect to show organic growth in both production and reserves. We expect production and reserve growth through our drilling programs in the Bakken and the Piceance Basin. We expect production growth from the further implementation of our two CO2 projects. To accomplish this growth, we've set a 2008 capital budget of $640 million. Importantly, we plan to invest 54% of the $640 million in exploration and development of currently non-proved reserves. This represents a substantial change, a doubling from 2007, when 27% of our $556.6 million in exploration and development expenditures was directed for non-proved reserves.

In 2007, $285 million was directed to our CO2 projects, including CO2 purchases. In 2008, we expect to invest approximately $154 million, including CO2 purchases in these two projects, the Postle Field and the North Ward Estes Field. The $154 million is composed of $80 million at Postle and $74 million at North Ward Estes. Therefore, investment in these properties will decline approximately $130.9 million on a year-over-year basis.

Turning from our capital budget to our Bakken oil play where, as shown on page 4 of our press release, we recently drilled three wells that over their first 30 days of production averaged 1,114,946 and 825 BOEs per day respectively. We currently have four rigs drilling for us at Robinson Lake, which has been designated by the MBIC as the Sanish field. We expect a fifth rig to arrive in April. By year end 2008, we expect to have up to nine rigs drilling in the Sanish field.

Most of the wells we plan in 2008 are expected to be single-lateral wells drilled on a 1,280- acre spacing units. The locations of these wells are being determined based on interpretations of the 98 square mile 3-D seismic survey that was completed in early 2007, as well as the subsurface data gained from the wells we and others are drilling.

We hold one of the largest acreage positions in the area, 118,348 gross acres, 83,033 net acres in the Sanish field area. Consequently, we have a total of 170 potential well locations, 118 of those operated, and up to 52 non-operated.

Based on drilling two wells per 1,280 spacing unit, we plan to drill and complete 36 of these wells in 2008. As we continue to drill at the Sanish field, we are reducing our total well costs due to improved drilling techniques, and some significant advances in our completion design.

Specifically, we have implemented a single-lateral well design over 1,280 acres that makes use of swelling packer completion technology. We believe this design allows us to contact significantly greater rock volume with our fracs.

Our Peery State discovery well, a tri-lateral horizontal well drilled on a 1,280 acre spacing unit cost about $8 million. Our most recent completion, the Liffrig well was a single-lateral well, drilled on a 1,280 acre spacing unit that cost approximately 5.4 million to drill in complete, a savings of $2.6 million per well.

A large part of this savings results from our single-lateral design, and importantly, the ability with our current design stimulate up to eleven intervals in one day. Currently, at the Sanish field, we're drilling four wells, in which we hold an average working interest of 90%.

In addition to our 36 operated wells, we expect to participate in up to 20 non-operated Sanish wells in 2008. As we have previously reported, the oil produced from the Sanish field is high-quality sweet crude. For the first quarter of 2008, we expect the oil price to average NYMEX less $5.60 for this crude.

In addition, the gas produced from the Sanish field contains large amounts of NGLs. It has a Btu content of approximately 1,700 per cubic foot. In December, we broke ground on the construction of a natural gas processing plant that will extract these liquids and allow the natural gas to be transported by pipeline to market. We anticipate the plant will be on stream in April 2008. The initial capacity of the plant will be 3 million cubic feet of gas per day, and it is expected to increase to approximately 33 million cubic feet of gas per day in the fourth quarter of 2008, when an expansion project is scheduled to be finished. The yield from the plant is expected to be 150 to 170 barrels of NGLs per million cubic feet of gas.

Immediately, east of the Sanish field is the Parshall field, where Whiting owns 66,957 gross and 13,470 net acres. We have participated in 24 wells that produce from the Bakken formation, 19 of which were drilled in 2007. The first 15 of these wells have now produced for 120 days, at rates averaging 591 BOEs per day per well. Our net production from the Parshall field in January was running at about 1,400 barrels of oil per day. We expect to participate in 50 to 60 wells in the Parshall field in 2008, with an average working interest of 20%. Eight drilling rigs are currently working in the Parshall field.

Moving to the Piceance Basin in North West Colorado, we drilled and completed three gas producers at our Boies Ranch prospect in Rio Blanco, Colorado during 2007. Each well flowed at an initial rate of approximately 2.3 million cubic feet of gas per day, from approximately 565 feet of net pay in the Williams Fork and Iles formations, perforated at depths between 6,500 and 10,900 feet. We hold an average working interest of 50%, and an average net revenue interest of 45% in the three gas producers. Production from these wells was shut in for most of the third quarter, and all of October 2007, as repairs were made to a nearby gas plant where Boies Ranch gas is currently processed. Production resumed from the Boies Ranch area in November 2007, at a combined rate of approximately 3.5 million cubic feet of gas per day, or 1.6 million cubic feet of gas per day net to the Whiting's interests.

Currently at Boies Ranch, we have drilled eight more wells. In six of these, we own a 100% working interest, at an average 85.35% net revenue interest. In addition, we drilled one well with a 75% working interest and a 64% net revenue interest, and the second well with a 50% working interest and a 43.75% net revenue interest. We expect seven of these eight wells to be on production by May 31, 2008. Whiting holds 2,760 gross acres, 1,571 net acres in the Boies Ranch and Jimmy Gulch prospects. In addition, we own 14,133 gross federal lease acres, 2,501 net acres adjacent to Boies Ranch and Jimmy Gulch. We plan to drill a total of 110 wells on Boies Ranch and Jimmy Gulch. 24 of which are planned for 2008.

The wells are scheduled to be drilled on 20 acre spacing units. We planned to have a minimum of two drilling rigs running full time in the Piceance Basin through 2008. Drilling operations are expected to commence at Jimmy Gulch in the third quarter of 2008, and we are drilling groups of four to eight wells off of each pad, as our rigs move from well-to-well.

Across our Boies Ranch in Jimmy Gulch's prospects, our ownership ranges from 50% to 100% working interest and 49% to 89% net revenue interest. Approximately April 15, 2008, we expect to complete and have our gas flowing through a new pipeline we are now laying at Boies Ranch.

It's a 2.9 mile, 10-inch diameter line that will have a daily capacity of approximately 80 million cubic feet of gas. We will connect this 10-inch line to a third-party trunk line feeding a 750 million cubic feet of gas per day treating and processing facility near Meeker, Colorado.

The treating and processing facility is connected to the Rockies Express or REX pipeline, and gives us access to multiple intrastate and interstate markets. In addition, in November 2008, we expect the White River hub will be connected to the same facility giving us access to four more interstate and two intrastate lines. We expect 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 transport capacity of 1.5 billion cubic feet of gas per day. When REX came on stream in January 2008, Rocky Mountain gas price differentials narrowed significantly. Currently, we expect our Boies Ranch gas will receive NYMEX prices less approximately $1.00 to a $1.40 during the remainder of 2008.

I'd now like to update you on the progress we've been making at our two CO2 projects. Our expansion of the CO2 flood 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 6,000 net BOEs per day so far in February 2008, an increase of 43%. Many thanks to our Postle team for this accomplishment.

In January, we also received and achieved our objective of increasing CO2 injection into the fields, producing more sand reservoir to 120 million cubic feet of gas per day, thereby doubling the 60 million cubic feet of gas per day rate at the time we acquired the field.

The increase in CO2 injection and production was made possible through development drilling and the expansion of the 100% owned Dry Trail Gas Plant. This included the installation of new compressors and the associated infrastructure. Importantly, the majority of capital expenditures required for the expansion of the Postle CO2 flood are now behind us. Future capital expenditures for the Postle field are currently estimated at approximately $259 million, of which $152 million is for the purchase of CO2.

Now I'd like to move on to our North Ward Estes Field in the Permian Basin. We expect to see initial response from our CO2 flood there during the fourth quarter of 2008. On May 22, 2007 we initiated the CO2 flood in the field which is located in Ward and Winkler Counties, Texas. Our target for CO2 injection into the field was 100 million cubic feet per day by the end of the first quarter.

This milestone was reached in January 2008. We are currently injecting approximately 120 million cubic feet CO2 per day into the Yates formation, the field's producing reservoir, at a depth of approximately 2,600 feet. Kudos to our North Ward Estes team for successfully implementing this project on schedule and with great efficiency. Construction of the gas plant facility and the related infrastructure at North Ward Estes is expected to be completed in 2008.

Future capital expenditures for this CO2 project are estimated to be approximately $625 million, of which $372 million is for CO2 purchases. Over time, we believe significant upside exists at Postle and North Ward Estes and the ancillary fields acquired at the same time, as our efforts may convert $94.4 million BOEs of probable and possible reserves to proved reserves. Of that $94.4 million, North Ward Estes contains $88.5 million BOEs of those volumes, Postle has $2.1 million of BOEs, and the ancillary properties $3.8 million BOEs.

Company-wide, we are currently running eleven operated drilling rates, four in the Williston Basin, three in the North Ward Estes field, two in the Postle field and two in the Piceance Basin. We are also participating in the drilling of 14 non-operated wells. Most of these in the partial field Bakken oil play.

In addition, we have 44 work over rigs in service. 23 of these in the North Ward Estes field, and six in the Postle field.

Now Mike Stevens, Whiting's CFO will discuss some key financial results.

Mike Stevens

Thanks, Jim. Our net income in the fourth quarter 2007 was $45.8 million, or $1.8 per basic and diluted share, and total revenues of $232.4 million. In the fourth quarter of 2006, net income totaled $28 million, or $0.76 per basic and diluted share, and total revenues of $186.6 million. Discretionary cash flow in the fourth quarter of 2007 totaled $139.9 million, compared to the $83.3 million reported for the same period in 2006.

The increase in fourth quarter 2007 net income and discretionary cash flow, compared to the fourth quarter of 2006 was primarily the result of a 48% increase in our realized oil price, which was $74.66 per barrel after adjusting for hedging settlements.

For the year ended December 31st 2007, Whiting reported net income of $130.6 million, or $3.31 per basic share and $3.29 per diluted share, and total revenues of $818.7 million. This compares to net income of $156.4 million, or $4.26 per basic share and $4.25 per diluted share, on total revenues of $778.8 million.

Discretionary cash flow during 2007 totaled $422.2 million, which is almost equal to the $426.2 generated during last year. Our lease operating expense during the fourth quarter of 2007 was $14.67 per BOE.

Although part of our ongoing development plan, a portion of the continuing wellbore work at company's North Ward Estes and Postle CO2 projects must be expensed for the accounting purposes. We expect this type of work to continue through 2008.

Our general and administrative expenses of $2.99 per BOE in the fourth quarter of 2008 exceeded our guidance due primarily to higher net revenues and sale proceeds, which caused additional payments due under our Production Participation Plan.

The company's fourth quarter DD&A rate per BOE was below previously announced guidance. This was primarily the result of positive reserve adjustments and an increase in the pricing assumptions used in our reserve report, which had the effect of extending the economic life of many of our wells. This created additional economic reserve volumes and a correspondently lower DD&A rate.

During the fourth quarter, our company-wide basis differential for crude oil compared to NYMEX was $8.25 per barrel, which compared to $9.65 per barrel in the fourth quarter of 2006 and $7.52 per barrel in the third quarter of 2007.

The increase from the third quarter of 2007 was due to increase in differentials in our Rocky Mountain and Permian regions. We expect our oil price differential to continue at approximately $8.00 to $8.50 in 2008.

During the fourth quarter, our company-wide basis differential for natural gas compared to NYMEX was $0.60 per Mcf, which is lower than our third quarter differential of $1.10 per Mcf. The smaller differential was the result of narrowing price differentials for all of our regions. We expect our gas price differential to remain at $0.50 to $0.70 in 2008.

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

Jim Volker

Thanks, Mike, and I'd now like to address our production guidance. The 54.6 million BOE midpoint of our 2008 guidance would be a 6% increase over 2007. With all of our drilling activity scheduled for 2008, we will of course revisit this estimate quarterly and be prepared to makes changes reflective of our results.

I'd now like to review the slides on our webcast, which will provide some more color and detail on our primary operating areas.

First, I'd like to call your attention to the forward-looking statement disclosure reserve information and non-GAAP measures page; page one. Please give that special attention, especially the risk factors seen in the companies Form-10K for the year ended December 31, 2007.

On the second page you can see that our market cap is currently $2.5 billion, long-term debt down as a result of our capital raised to $868 million, fully diluted shares rounds to 42.5 million shares outstanding. And our debt to total cap is under our target of 46.8%, we're very pleased with that. As well as our 40, I am sorry, 36.8%, as well as the increase in our reserves to 250.8 million BOEs, 78% of which is oil giving us an RP ratio based on our current production of 40,300 barrels per day of 17.1 years.

Moving to page 3, as you can see the PV10 pre-tax of our 250.8 million BOEs of reserves has grown significantly as a result of price increases from last year. Again it's up 75% to $5.858 billion.

This page 4, is somewhat of a change from what we've been showing before. Certainly Whiting continues to have a diversified long life reserve base and we have been a disciplined acquirer with the, I think, strong record of accretive and low cost acquisitions including the Postle and North Ward Estes fields, which I think frankly was accrual for the company.

Currently, Whiting is characterized by something new, a multi-year inventory of development and exploitation projects to drive organic growth. These are characterized by the moderate risk organic growth potential from Postle and North Ward Estes that will give us some production growth, and over time, in my opinion beginning three years from now or so, growth in reserves, as we have the potential to convert approximately 94.4 million BOEs of probable and possible reserves to proved reserves, if performance of those fields warrants it. That alone, without any additional drilling in other areas, would represent a 38% increase in comparison to our year end 2007 reserves.

In addition, through drilling in other areas we now have significant organic growth potential from drilling programs in the Williston and in the Piceance Basin. Further, we have some exploration potential, which we will test with the drillbit this year in the Rockies, also some acreage positions in the Piceance and in the Gulf Coast. Those will also be especially in the Gulf Coast, tested this year. While doing this, we will remain to have a commitment to financial strength, and by that we mean trying to keep our debt to total cap under 40%. And we'll try to keep the management team together and add to our, what I believe is excellent, technical and employee team.

Our formula for success, which is shown on page 5, has changed somewhat since you've looked at it, if you followed Whiting since its IPO in 2003. For example, although we've always been an acquire, exploit and explore company, some new things that you have seen from us, although Whiting has done at many times in its history, is to monetize some of its reserves. For example, this year we sold 52.6 million BOEs of reserves, and importantly, in those sales the average LOE per BOE without one sale of gas property i.e. -- so most of our sales were properties that had high LOE per BOE averaging about $22.35 per barrel.

In addition, as I have mentioned in prior calls and as you are well aware of, as a result of our filings, we have filed for the sale of the royalty trust. I won't comment more on that, other than to say that you should look at the filing there for information on that particular planned offering.

Moving onto page six, here we break down for you the PV10 value again of each of our areas and in footnote number two, which again I think is important. I would point out that the $5.858 billion of PV10 value at year end 2007 is a 75% increase from that $3.35 billion at year end 2006.

Moving to page seven, as you can tell, we're now disclosing that Whiting has a significant amount of probable and possible reserves. An increase for example, I'm now concentrating on the 2007 MBOE column there, an increase of about a 114 million BOEs in 2007 over 2006, as the total there of probable and possible reserves rose to 242.7 million BOEs, from 129.1 million BOEs in 2006.

Moving on to our finding costs, this is on Slide 2008. We've summarized for you here our funding cost, calculated as it's typically done by people on Wall Street, as $28.90 per BOE for 2007.

However, if you look at our five year average, which of course, I think, most of you are familiar with at this point, you can see that for the five-year average on proved reserves, it’s $12.27 over that five year period. It's $17.17, including the future cost of proved reserves to develop the undeveloped reserves.

And here we disclose that with the development cost of the probable reserves, and we show you there the total of the probable reserves, we think the cost will remain at about $12.21 per BOE.

But we didn't put all on the years on here, but for your information, I'll now tell you what our finding costs were in each of these particular years. For '03 it was $5.28, again calculated in the same manner as shown here; '04, $7.78.

In '05, the year of our large acquisition of over $800 million for the Postle in North Ward Estes field, it was $8.82. In '06, as we poured the capital into those two projects in order to develop the large portion of undeveloped reserves associated with that acquisition, our annual finding cost rose to $502 per BOE. It's down now in 2007 to $28.90, and as I have just said, it averages $17.17 over the five years with estimated future proved development cost that we throw in the probable and possible reserves. With development cost, we think it will be in the range of around $12.

Reserve replacement as addressed on slide 9, it was a 138% in 2007 and 433% over the five year average, '03 through '07. Reserve and production profiles on page 10 are important, in the sense that, if you look at the far left hand pie graph, pie chart here, you will see that we're up to 67% proved developed reserves as a percentage of our total 250.8 million BOEs, that's up from 59% going back to 2005. If you look at the center pie chart, you can see that our proved reserves by core area are obviously concentrated in the Rocky's, the Mid-Continent and the Permian, with 90% of them in those three core areas. And 65% of production, looking at the pie chart on the far right, coming from the very same three core areas, although, in my opinion, that's a good example for why we are not selling our Michigan properties, for example, or some of our other Mid-Continent properties.

With respect to page 11, this, I think, shows markedly here that there has been a significant change in our budget from 2007 to 2008. Not only are we going to be investing more money in the drilling, but as you can tell from the light blue area or the dollars directed toward non-crude reserves, its 54% in 2008, up from 27% in 2007.

And with that, I'd like to just ask Mark Williams to review quickly for you how those dollars are divided out amongst our regions.

Mark Williams

Thank you, Jim. I'll just mention what our CapEx budget is for the rest of this year or for the full year. Essentially we have a fairly even distribution of capital spending through the year with 24% in the first quarter, 28% in the second quarter, 25% in the third quarter and 23% in the fourth quarter. What's really happening there is, as we wind down our investment capital at North Ward Estes primarily, this slack is being taken up by increasing capital in our Robinson Lake and partial development projects of the North Dakota.

If you look at it by region, 4% of our capital is directed towards the projects in the Gulf Coast, 15% is directed towards the projects in the Mid-Continent including the Postle field., 62% of our capital is going up to the Rockies, of that I'll just say that 260 million is directed towards Bakken drilling of our total of 640%, that represents 41% of our capital drilling in the Bakken. And then finally, in the Permian, 19% of our capital budget is going to be directed mostly towards development in North Ward Estes field.

In terms of the number of wells, the Gulf Coast has 10 wells, the Mid-Continent will have 50 wells and of those 50, 37 are in the Postle field. The Rockies will have a 170 wells drilled, these are gross numbers, 170 wells drilled this year of which 102 will be Bakken wells this is what we are estimating right now and then in the Permian, we are projecting 36 total wells.

Jim Volker

Great, thanks Mark. Moving on to page 12, our 2007 versus 2008 exploration and development expenditures by core area again shows a big increase in the amount of money as Mark has just described going into the Rockies as it will increase from 35% to 62% of our total budget. We'll be going to page 13, as you can tell our debt to total cap was 36.8%.

Moving to page 14, we continue to have strong EBITDA margins thanks to increasing oil prices, where we're now netting $31.29 out of each BOE after lease operating expenses, production taxes, G&A and exploration expense.

Here is a new slide for you on page 15. Thanks to Dave Seery, for working this up for us. This shows Whiting's gross and net acreage by core area and total in the lower right hand corner. You can see our company gross acres 1.750 million, net acres 883,000 net acres and the big portion of both the gross and net, there in the Rocky's that is 1.1 million gross and 517,000 net acres.

Moving to page 16, we break it out for you here between developed and undeveloped acres, and of course if you look at the lower right hand corner, the company totals here 45% of our net acres are undeveloped, that's the 401,571, of net undeveloped acres and the big portion of that undeveloped portion is in the Rockies as you can tell, 308,949 net undeveloped acres in the Rockies. We'll be testing some of those new acreage positions in 2008.

Slide 17, summarizes for you the activity that is going on for us in the Bakken exploration area, we estimate the EURs here of between 400,000 and 900,000 barrels of oil per well, that’s BOEs per well. As you can tell, we brought our completed well cost and will continue to try to keep it down in the range of $5.5 million to $6 million per well.

With respect to, I know a lot of you are wondering what we think the reserves are out there in the Sanish field, that is the biggest portion of our acreage position and we expect those to be in the 575,000 to 602,000 barrels of oil per well and that’s our best guess right now.

In addition to the Bakken where we had, we drilled 33 wells in 2007, and we expect to drill 36 in 2008. Our sales and participate in at least 20 non-operated wells. We also have a play going on in the Red River, where nine 3-D seismic surveys were acquired in 2005 through 2007 that help us identify structures. We've got one more plan for 2008. We've identified 24 drilling prospects. Six wells were drilled in 2007, seven wells are planned for 2008. We're estimating about 450,000 BOEs per well, and completed well cost has been running from $2.5 million to $3.7 million per well.

Nine of eleven of the wells we drilled in 2005 to 2007 were successful using our 3-D seismic to identify the structures. Seven wells and one new 3-D seismic program are planned for 2008.

Turning to page 18, here this simply shows in the upper left-hand corner the Williston Basin and within the Williston Basin the Bakken formation and where our acreage at Sanish-Parshall lies in relation to Elm Coulee field, which was first field to be significantly developed using horizontal technology in the Middle Bakken and also where it lies in relation to the North Schematic line.

And as you can see from the cross-section in the lower left-hand corner of the page, we think as you go to point A prime on the cross-section the zone is coming up, it's spinning and it's getting fractured as you get there near to edge of the basin. Essentially, we think we are in the cooking pot, we think the zone is in the expulsion phase and we think we have got frankly a great acreage position in the heart of the play.

As you can tell in the lower right-hand corner of this particular slide, in the Sanish field, Our three wells, our three most recent wells have averaged over 30 days and 912 BOEs per day and in the Parshall field, the wells there that we participated over the 120 days has averaged about, as they have been on production longer, 591 BOEs per day.

You can also tell there in the lower right-hand corner that in total, we expect 50 to 60 wells including not only the 36, we intend to drill, but others at we intend to participate in due to our acreage position where others would be the operator at Sanish.

So 50 to 60 in Sanish and of those, around 36 will be operated. And then due to participation in the non-operated wells the total will go up as we said, to 50 to 60. Likewise the operator of the Parshall field has indicated that they will drill between 50 and 60 and right now, we intend to participate in all of those.

I think this Page nineteen, maybe one of the most interesting slides here in the presentation, as it sets forth for you, currently, our fully developed plan for our acreage position over about the next 36 months. As you can tell, all those grey lines there indicate drilling on 288 acre units that is two sections or two square miles per unit, with two horizontal wells per unit, that is two wells each drilled over the 1,280.

So in 2008, looking at the table in the lower left-hand corner here, you can see we plan 36 wells, in which we think we have an 82% average working interest. In 2009, since our nine drillings rigs can each drill about six wells a year, 54 wells and 28 plants for 2010, so that's a total of 118 wells plus non-ops estimated here at about 52 to get to the 170 total that we have mentioned before and which we would have an average at least 56% working interest. But most importantly, probably a 70% working interest in the operated wells. We're very pleased therefore, with this acreage position. We are also very pleased with our partner who is the operator in the Parshall field, who got in here and kicked off this play with high activity initially, and as a result, I think its been a great partner to be with and to share what we're learning in the area.

Moving on to the exploration slide on page 20, about the Piceance Basin as you can tell here, at Boies Ranch and Jimmy Gulch, our working interest is between 50% and 100%. We're drilling the continuous gas phase of the Williams Fork and Iles, we plan 110 wells here, $270 million drilling budget including processing based upon our estimates of future CapEx at December 31. Estimated well costs here are in a range of around $2.8 million per well with stimulation and our guesstimated reserves here are in the range of around $2 Bcf per well.

Page 21, I think it's a great slide, also. It shows the location in the dark yellow of our Boies Ranch acreage, and over on the right hand side, our Jimmy Gulch acreage. And as you can tell, it shows that so far we've got three producers. We have two that are drilling and we also have six wells that are either being completed or waiting on completion. So that's a total of 11 wells here that we've drilled so far on our way to 110. And with that, about 24 scheduled for 2008. Here is a picture of the build for purpose 1,500 horse power rig which is one of the two that we're using there currently and we may expand to three rigs out there at Boies Ranch depending upon, I should say the Boies Ranch and Jimmy Gulch depending upon the results at Jimmy Gulch and we may go to three rigs in July or August of 2008. The results continue to be as good as they've been in the past.

On page 23, another great in my opinion key slide, showing in the right hand side of the dark blue section that currently Postle and North Ward Estes represent 49% of our total proved reserve base and 29% of our total production.

Commenting on page 24, with respect to our fully developed cost for BOEs here, we think the slide does it well because you can see it adds to 800 million that we have paid to acquire the property, our estimated future CapEx as of 12/31/2007 of $902 million, the CapEx that we spent in '05 and '06 and '07, less some minor properties that we sold in 2006 and 2007. And that in comparison that totals $2.27 billion and in comparison to the proved reserves here at year-end plus production of 134.5 million BOEs gives you an acquisition and development cost of $16.93 per BOE including the probable and possible reserves and the estimated costs to develop $10.62.

I really believe that the footnotes here on this page are key, and they point out that more than half of the $225 million increase that we had in our all improved cost estimate from $2.05 billion at year end '06, $2.27 billion at year end '07, is attributable to the price increase we've seen in our CO2, which is somewhat index to the NYMEX price. Obviously, we think it's about as high here that is, we run it at year end prices here. So, we think we've captured that estimate of future cost increase.

Importantly in comparison to that, the estimated capital expenditures is pointed out in footnote two. Also reflected is an expanded scope in the projects, as we've added some additional sections in our plans in order to CO2 flood. So, although acquisition and development cost increased 11%, the pre-tax PV10 value of these fields increased from $1.4 billion at year end 2006, to $2.9 billion at year end 2007, a 106% increase.

On the miscible CO2 recovery process is summarized for you here on page 25, since what we are doing here is we're injecting in a WAG method that is water alternating gas. First, water into the reservoir to raise the pressure to miscibility pressure, we're putting the CO2 into the formation in order to combine with the remaining oil in the reservoir. Thereby reducing the fluid surface tension and resulting in oil movement through the reservoir up to the producing wells, where the full production stream of oil, gas and water is produced. Obviously, we then separate the oil from the gas and the water. We sell the oil, we separate the CO2 from the hydrocarbon gas, we inject the CO2 back into the reservoir, we strip the liquids out of the hydrocarbon gas, sell that, and sell the residue gas.

Our development plan for Postle, we've shown in page 26. And going forward, 2008 through 2010, we plan 82 additional wells. The total CapEx going forward from 2008 through 2010, is $259 million and $152 million of that is CO2 purchases, $100 million is going for drilling, completion and plant cost. As you can see, down there in the white box, at the bottom of the map, so far in '05 through '07, we completed 94 wells and there are 82 plants going forward.

On page 27, nice picture of the original plant that we acquired when we bought this asset and then the newer, more modern membrane type plant with electric compression, which is modular and efficient at the bottom of the page.

I'd like to turn now to page 28, and our CO2 flood at North Ward Estes, where phases 1 through 5, encompass 28 sections. There is 700 million barrel oil in place, target in the flood area. With respect to the CO2 only, about a 5% estimated recovery factor. The CO2 supply agreement is in place for 269 Bcf, deliveries started in 2007, at around 10 million a day on average and in 2008, we're over a 100 million a day. We currently have 91 injectors and we are putting a 120 million a day into the reservoir.

This show plant going up on page 29 and simply shows in the lower portion of this slide the gas coming in going through the Inlet Compression, 88% of which is CO2, the CO2 is recovered.

The residue hydrocarbon gas is then dealt with, i.e. stripped and then sold, and the CO2 is compressed and put back into the field, obviously the oil in the water are also separated oil sales and water re-injected.

On page 30, I like the slide because it shows clearly the phases one through five that it's going to extend through 2015 and that our CapEx here is estimated at $625 million, $253 for hard CapEx and $372 million for CO2 purchases.

A new slide on page 31, I think is a good summary. As you can tell, we're attributing in this area 887 million BOEs to CO2 related activities, so 87 million of the reserves attributable to the North Ward Estes Field here including proved, probable and possible, proved at 34 million, probable at 24 million BOEs and possible at 29 million BOEs are related to CO2 activities.

For the field in total is shown in the right-hand side here in the white portion. There is a 162 million total reserves broken up between 39.5 million crude well producing, 19 proved non-producing PUD at $41 million for a total proved to $73.7 million proved probable including water flood activities of 36 million and possible including water flood activities in not necessarily just the CO2 activities of $52 million to get to in this particular field 162 million BOE on 3P.

Just like to ask you to remember that when we bought Postle in North Ward Estes, the total attributable proved reserves to North Ward Estes was 80 million barrels, so, the probable and possible reserves here give us a chance to double the reserves at North Ward Estes.

The North Ward Estes schedule shown on page thirty two is a good one, in the sense that the green here is CO2 activities. The blue is the water flood activities. As you can tell, the water flood activities proceed the CO2 activities in order to raise reservoir pressure, get it ready for the injunction of CO2.

And so in each one of these bars, I'd just like to point out what it says at the bottom of the page here, and that the in-date of the CO2 injection bars is an estimate of when all the sections in that phase will again start it up to CO2.

Initially each injection well will be on continuous CO2 injection for approximately one year. Thereafter, each injection well will start the WAG process of one week on water followed by about three weeks on CO2 injection, plus the fuller WAG cycle repeats about every four weeks. CO2 injection continues through the life of the project as CO2 is produced and re-injected over an approximate 20-year period.

And page thirty three shows why we are doing all this and making this large capital investment, because we think we can take the production of Postle up to 8000 BOEs to 9000 BOEs per day net to us.

And at North Ward Estes field to 10,000 to 13,000 BOEs net loss per day. So these estimated ranges of production are 90% or 100% of independent engineering at year-end '07 at Postle where we obviously are further along in the flood and 80% to 100% of the independent engineering at North Ward Estes. Obviously results may vary.

Finally on page 34, this summarizes the fact that, although we wish weren't, we were hedged; we are hedged about 40% on oil through the end of 2008. Thereafter, we have no oil or natural gas hedges. We had to put on some of these hedges as a result of the acquisition of the Postle and North Ward Estes field. So, that will may go off.

On page 35, then in summary, Whiting is all of these things, five core regions where we've taken since our IPO, our reserves from 71 million barrels to 250 million BOEs, as a result primarily of 13 acquisitions in 2004 through 2007, of 208 million BOEs at an average acquisition cost of $7 per BOE. We now have a five year drilling inventory and significant growth potential from our CO2 recovery projects, as well as exploration potential at Sanish and Parshall, at Boies Ranch and Jimmy Gulch, in the Permian and along the Gulf Coast and essentially that in the Permian, we'll be doing some activity in the Montoya, the Devonian and the Penn. And then the Gulf Coast and the expanded Wilcox section, those will be exploration things tested in 2008.

That brought our total debt to total cap down to 36.8% is the result of our recent capital raise, and again we remain proud of our management and technical team. Discretionary cash flows summarized for you there and at year-end 2007, it was $442 million.

Operator, with that I would like to open the conference call for questions. Thank you very much.

Question-and-Answer Session


(Operator Instructions) Your first question comes from line of Scott Hanold from RBC Capital Markets. Please proceed sir.

Scott Hanold - RBC Capital Markets

Thanks, good morning guys.

Jim Volker

Hi, Scott.

Scott Hanold - RBC Capital Markets

Good quarter. I had a couple of questions particularly on the Williston Basin and the Sanish and Parshall field. I guess you indicated in some of your final comments that talked about exploration potential in those fields is that referring to the sands below the lower Bakken interval?

Jim Volker

No, we're just talking about the Bakken there.

Scott Hanold - RBC Capital Markets

Okay. Can you say anything about the sands that are below it? Are you guys looking at that right now or have you tested that much?

Jim Volker

We're along with other operators testing all perspective reservoir intervals including what's called the Sanish sand beneath the Bakken. The designation of Sanish field really refers to that's the name it was given to this field by the [NDAC], which is not specifically refer to that reservoir interval, we're producing it from the middle Bakken, but we're looking at all other perspective intervals.

Scott Hanold - RBC Capital Markets

Okay, okay. And is there any color you can lend us as far as what you found so far is it some we could expect here on the coming quarters?

Jim Volker

Well, as we learn more, you can expect to find we'll certainly disclose it. But right now all of our production is from middle Bakken.

Scott Hanold - RBC Capital Markets

Okay, got it. And you also indicated that you've the 3D survey issue that you're looking at covered some of the area. What kind of things did you see in that 3D issue that you can kind of talk about it lends you to drill certain locations before others has it is shown through the areas sort of in the eastern edge of your fields a bit more highly fractured or can you just kind of give us a sense of what you saw there?

Jim Volker

I can just say that we've 3D seismic over all of our acreage, as to our partners out here essentially everything that's on the map and is covered with 3D .And we use it in multiple different ways to help us to refine our drilling. But we're really trying to integrate that with all of the results from the drilling to optimize the locations that we're going through first. You know, really, it's a very integrated project and so there is a lot of different information we're getting out of that. But there is not one specific thing that I can point to that's says that -- that we're using indifference to anything else that helps us to prioritize our locations.

Scott Hanold - RBC Capital Markets

Okay. And obviously you're moving a little bit more to those single lateral wells. Does that -- I mean, with the sense of if you look at your inventory, I think you've indicated of a 170 wells and you map those out. How -- would there still be a handful of tri-lateral wells or do you think the single laterals will work off across the vast majority of your position?

Jim Volker

The single laterals are the way -- we've done a lot of work here recently with this Locken and Liffrig wells and we've really, we believe strongly now that's the key to success. We can frac all of those, all of the length of Locken and Liffrig wells, whereas with the tri-lateral design, we're really aren't unable to do one leg. The cost is significantly lower and I think the results speak for themselves. So, we're sticking with the single lateral design.

Scott Hanold - RBC Capital Markets

Okay, got it. And one last question. Jim, you sort of indicated, I guess that you would have rather not been hedged with some of those who have positioned you had to put in place because of the acquisitions. Can you kind of speak of what your thoughts going forward, obviously oil at $100, is this something that you would rather leave open at this point of time or considering where commodities are, would you opportunistically lock-in some hedges on some of your later '08, '09 quarters?

Jim Volker

We'd rather be open and unhedged especially with our debt below 40% debt to total cap and Sherwin Artus, who preceded me here as President says he likes to drive down once a week and smack me on the back of the head for having these hedges on. So, all I can say is, I think the direction of myself and our Board is to have fewer hedges as long as our debt's down.

Scott Hanold - RBC Capital Markets

Fair enough, thanks a lot guys.

Jim Volker



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

Wayne Andrews - Raymond James

Good morning gentlemen, congratulations on a nice year end. I've a couple of questions just sort of regarding what's -- and may be I'm not sure how much detail you'll be able to give us, what's booked as far as number of locations in your current Bakken wells for the future versus how many wells you're drilling? And then, I've a couple of follow-ups. But first if you could discuss; you haven't drilled many wells there yet, but how many did you book at year end and when might we see some nice reserve additions through your drilling program this year?

Doug Lang

Hey, Wayne, this is Doug. At year end, you're right; we're just starting our Sanish development project there. We only had five wells that were PDP. And actually that's high and we only booked seven PUDs.

Wayne Andrews - Raymond James


Doug Lang

That's reflective of a couple of things I guess, one is just the vicinity of the wells to each other that's a limiting factor. And also we just want to be careful, as we go forward in our bookings, so we've been fairly conservative. We only have seven PUDs that would leave another 163 wells that are in our probable and possible categories.

Wayne Andrews - Raymond James


Doug Lang

Essentially those shown on the map there that's kind of to fully develop our program. But those right now are in the probable and possible category. So, a lot of those will definitely be moving in as we drill more wells.

Wayne Andrews - Raymond James

Great. As we're waiting for the gas plant to be in place are there any oil sales that are held up waiting on that plant?

Doug Lang

No. We're permitted to [vent] the gas up there, but we're hustling to get that gas plant in obviously and also to strip the liquids.

Wayne Andrews - Raymond James

Very good. One last question with a large portion of your entire reserve base now both in Postle and North Ward Estes on a growth trend and the program that you've planed for the Bakken, it seems like you're being pretty conservative on your estimates for volume growth during the course of the year, any comments on that?

Doug Lang

Yes. We're being somewhat conservative I think. Keep in mind that what we’re doing here however is ramping up in the Bakken. We expect to be at five rigs in April, six rigs in June, seven rigs probably by September, eight rigs in November and nine rigs in December.

So, we're going to watch our results here and if they continue to merit development-wide we will continue to press the accelerator down and accelerate our drilling phase. If, however things would go the other way, why will we pull back? I think group of us here in this room would tell you that we think it's all good.

By that I mean everything we have there in the Bakken, we think will be productive. We don't know whether it will all be as good as where we have been drilling right now as we move to the West and the North and the South.

However, I would say in our recent results of our wells and I'm not going to make announcements for other people here, but there's all sorts of data coming out, both publicly filed data at the NDAC and then the normal rumor mails and blogs that you can hear about.

And in general everything that we have heard is positive, so we feel that at least within this roughly 120,000 acre, acreage position that we have, it will all be productive. It may be productive to vary in degrees, but we think the well design we have come up with will allow us to tap the potential of the four corners of our acreage position.

Wayne Andrews - Raymond James

Excellent. Well, we are looking forward for additional good results there. I've one last question also on just booking procedures in North Ward Estes and Postle, what do you need to see and what are you waiting for before we see additional reserve bookings in those fields for the probables and possibles that you have mentioned?

Jim Volker

Generally, what you've got to see, we've got a curve that the independent engineers have come up with. And, so you need to see in my opinion as I said earlier, you may not have caught it, but I said I think, it probably be around 30 to 36 months before we have enough production in order to say whether we are over that estimated proved that combines the various proved categories, to see if we can then start adding some of the probables and possibles. And I'll let Doug comment on that, but in general, I think its going to be somewhere out there around 30 months or so.

Doug Lang

Wayne, it's graphically represented I guess in that slide 31 and its not strict engineering that we put that, the Michigan's curved along with our reserves and so forth, but essentially, we have to see how the process works in the North Ward Estes -- we had some history from the project that they had on six sections back in the late 80s, early 90s, but really we need to get our project implemented and do it the way we want to do it, which is as kind of accelerated, use more CO2 upfront. But essentially we have to kind of see how the production response to the CO2 injection and how efficient the process is, how fast did the reservoir takes in the CO2 and how fast it processes it and what kind of oil response you get.

So you got to kind of walk up that curve as shown on slide 31 and essentially show that you are going to be on -- you see that blue curve, you have to show that well -- no, we are going to get better efficiency and we are going to get more recovery and then we are on that kind of light green curve or maybe possibly on the green curve. So, it's going to take some time to demonstrate that and actually we'll be doing that kind of analysis on a section-by-section basis. So, some of the parts of the field maybe -- may process more efficiently and get better recovery than others. So, it will be a section-by-section look and as we demonstrate that we are on a different curve and we can start to move some of that probably into proved, but it's just going to take some time and some history to demonstrate that.

Wayne Andrews - Raymond James

Very good. We'll be looking forward to those results as well. Thanks for your time.

Jim Volker

Thanks, Wayne. In answer to Wayne's final question I would like to say that, nothing that we have seen so far is negative about that and frankly, we wouldn't talking about it, if the results to-date hadn't given us optimism about those probable and possible reserves. And that's solely based upon the initial response we have seen in the start-up area. It seems to be processing the CO2, the whole thing seems to be processing pretty fast. So, we are getting what we think are excellent responses in that area.

Wayne Andrews - Raymond James



(Operator Instructions). And your next question is from the line of Jeff Robertson with Lehman Brothers. Please proceed Sir.

Jeff Robertson - Lehman Brothers

Thanks, Jim. I guess this is partially answered by the previous question. But on the probable and possibles, are those concentrated in any one of the phases that you all have planned or is it just a spread from increased recovery off of all of them?

Jim Volker

It will be increased recovery essentially on all areas. And again it's just relative to what kind of percent of oil in place we will recover as we move from the kind of 5% average over the core area that were flooding up to potentially 12%, at the top end with all the proved probable and possible. So, it's throughout all the areas.

Jeff Robertson - Lehman Brothers

Okay. I want to follow-up on the expected production growth for 2012 and '14 at North Ward Estes. Does that include a contribution from the probable and possible or is that just converting the PUDs and bringing them into proved?

Jim Volker

That just proved.

Jeff Robertson - Lehman Brothers

Okay. Thank you.

Jim Volker

Thank you, Jeff.


And your next question is from the line of [Jim Busoni with Northern Webster]. Please proceed, sir.

Jim Busoni - Northern Webster

Good morning folks. Just a quick question, could you just give an update and status of where you are on the MLP and also in the filing that you did, in your recent TV [tenders], just put out now, are the proved reserves are they excluded from the properties that are identified in the MLP?

Jim Volker

Well, all I can say as we've -- you seen the initial filing, we're in the process of the responding to the SEC's comment latter and just stay tuned you'll see, when and whether in fact we file our response, which would be amendment number one and we are working on that. And then, the reserves that we have just disclosed the $250 million BOEs include reserves that would be in this trust, it's not an MLP, it's a trust that we would sell.

Jim Busoni - Northern Webster

Okay. I apologize for misidentifying that. Thank you.

Jim Volker

You're welcome.


(Operator Instructions) As there are no further questions. I'd like to turn the call back over to Jim Volker for closing remarks.

Jim Volker

Great. Thank you very much, Heather. In closing, I'd very much like to underscore the excitement, all of us waiting are feeling about executing on our drilling and CO2 projects in 2008. We believe 2008, maybe a breakout year for organic production and reserve growth. I'd also like to mention, several events that Whiting will be participating in over the next several weeks that may allow us the opportunity to meet personally with you. We'll be presenting at the Raymond James 29th Annual Institutional Investor's Conference at the Hyatt Regency in Orlando, Florida on March 3rd at 2:15 PM Eastern Time.

We'll also present at the IPAA, Oil and Gas Investment Symposium at the Sheraton, New York Hotel & Towers on Wednesday, April 9th, at 11:20 AM, Eastern Time. Both of these presentations will be available on the Internet and on our website. And we look forward to seeing you at those events.

In closing, I'd like to thank all of you on this call for your new or continuing interest 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 success in 2007 and our plans for significant growth in 2008. Again, all the best and we look forward to seeing and speaking with you soon.


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

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