James Volker - Chairman, Chief Executive Officer and Director of Whiting Oil & Gas Corporation Mark Williams - Senior Vice President of Exploration and Development John Kelso - Director of Investor Relations Michael Stevens - Chief Financial Officer and Vice President James Brown - President and Chief Operating Officer

Gray Peckham - Susquehanna Financial Group, LLLP Philip McPherson - Global Hunter Securities, LLC Scott Hanold - RBC Capital Markets, LLC Jeffrey Robertson - Barclays Capital Chris Sheehan Chris Pikul - Morgan Keegan & Company, Inc. Biju Perincheril - Jefferies & Company, Inc.

Jack Aydin - KeyBanc Capital Markets Inc. David Tameron - Wells Fargo Securities, LLC Pearce Hammond - Simmons & Company International Eric Hagen - Lazard Capital Markets LLC Gil Yang - BofA Merrill Lynch Jessica Chipman - Tudor, Pickering, Holt & Co.

Securities, Inc. Jason Wangler - SunTrust Robinson Humphrey, Inc.

Michael Scialla - Stifel, Nicolaus & Co., Inc. Joseph Allman - JP Morgan Chase & Co Unknown Analyst - John Freeman - Raymond James & Associates, Inc.

Joseph Magner - Tristone Capital

Thanks, Angela. Good morning, and welcome to Whiting Petroleum Corporation's Second Quarter 2011 Earnings Conference Call.

On the call for Whiting this morning are Jim Volker, our Chairman and CEO; Jim Brown, President and COO; Mike Stevens, our CFO, Mark Williams, Senior Vice President of Exploration and Development; Doug Lang, VP of Acquisitions and Reservoir Engineering; Bruce DeBoer, Vice President, General Counsel and Secretary; and Chuck LaCouture, VP of Marketing. During this call, we'll review our results for the second quarter of 2011, and then discuss the outlook for the remainder of 2011.

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 2011 earnings release, can be found on our website at www.whiting.com.

To access the call and webcast, 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've 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, 2010.

We disclaim any obligation to update these forward-looking statements. I'd also like to note that our Form 10-Q for the 3 months ended June 30, 2011, will be filed tomorrow.

During this conference call, we will also make references to adjusted net income and discretionary cash flow, which are non-GAAP financial measures. Reconciliations of these non-GAAP measures to the applicable GAAP measures can be found in our earnings release and in our webcast slides.

In this call, we also use the terms probable and possible reserves. Please refer to our webcast slides for more information on probable and possible reserves.

So with that, let's get going. I'll turn the call over to Jim Volker.

Thanks, John. Good morning, everyone, and thank you for your interest in Whiting Petroleum Second Quarter 2011 Conference Call.

We've shortened our presentation in terms of the slides. We're going to move quickly through our comments and slides, and we look forward to answering your questions.

Calling your attention to Slide 3. In terms of revenue, the $481 million and discretionary cash flow of $313 million Q2 2011 was a record quarter for Whiting.

Further, after 3 weeks of mostly dry weather in July, we've made great progress returning wells to production and frac-ing new wells. In the Williston Basin, we reached a new operated production record of 58,000 gross and 31,161 BOEs a day on July 19.

Our Sanish field is coming back strong after first half 2011 inclement weather, reaching 22,817 BOEs a day net on July 19, 2011. We currently have 2 full time dedicated Halliburton frac crews, and one half time Baker frac crew working in the Williston Basin.

We believe they're capable of frac-ing 18 to 20 wells per month between now and year end 2011. Therefore, we expect to reduce our 44 well inventory of operated wells waiting on completion to 25 or less by November 30.

Based on our current drilling rig count of 17 rigs working in the Williston Basin, 20 to 25 wells being prepared for completion, represents a typical inventory. We have 11 service units running in the Sanish field, and are placing back into production wells that were shut in during the inclement weather due to muddy conditions.

As of July 15, 2011, we had 27 wells waiting for a service unit. Consequently, we expect production to rise significantly in July through September because we expect this inventory to be eliminated by September 30, 2011.

Our 2 recent discoveries at Redtail and Hidden Bench, our new wells at Sanish and Lewis & Clark, and our encouraging results at Big Stick demonstrate our strategy and ability to develop new oil play areas for future multi-rig development, while successfully executing on our existing large-scale resource plays. These results caused us to increase our capital budget to $1.6 billion from $1.35 billion.

On Slide 4, you'll note that the Rocky Mountains, Permian and Mid Continent contributed 91% of our second quarter production of 64,120 BOEs per day. Calling your attention to Slide 5, our market cap is $7.2 billion.

Of our $1.06 billion long-term debt, $600 million is in 2 staggered maturity senior sub issues, the first coming due in 2014 in the amount of $250 million, paying 7%. And the second, in the amount of $350 million, paying 6.5% due in 2018.

Shares of common stock outstanding now total $117.4 million shares. You may recall our 2-for-1 stock split on February 22, 2011.

Our decision to split our stock reflects our confidence in our long-term growth strategies and business opportunities. On Slide 6, you can see the breakdown of our new 2011 capital budget of $1.6 billion, which is up from $1.35 billion.

Of this $250 million increase, we expect to invest approximately $90 million in additional land acquisitions, bringing the land total to $200 million. We expect to invest the remaining $160 million in drilling and facilities, and that would be split approximately 2/3 to drilling and 1/3 to facilities.

The increased budget is expected to be funded through internal cash flow, and temporarily by bank borrowings from our line of credit, only temporarily because these wells, as most of our additional drilling is proving to be, pay out in 1 year or less. On Slide 7, we show you our planned 2011 capital expenditure per project, as well as the growth in net wells that we plan to drill at each prospect.

For your convenience, this slide shows the total CapEx by region for the new and the old budget, so you can easily see where CapEx has been increased. New plays receiving a portion of our increased capital budget in 2011 include the Hidden Bench prospect in McKenzie County, North Dakota with 18 additional wells; the Cassandra prospect in Williams County, North Dakota with 6 more wells; the Starbuck prospect in Richland County, Montana with 5 additional wells; and our Redtail Niobrara prospect in Weld County, Colorado, with 4 more wells.

On Slide 8, I'd like to point out that in 2010, the combination of acreage and non-proved CapEx totaled 41% per the pie chart on the left. In 2011, the same 2 categories have increased to a total of 63%.

Consequently, in 2011, we're investing an additional $607 million and a greater portion of our budget into finding new reserves. Slide 9 shows our acreage position in the Bakken/Three Forks Hydrocarbon System at the Williston Basin.

The first thing I'd like to point out is that our Land Department has continued to be very successful. They've increased our core acreage position in the Bakken/Three Forks Hydrocarbon System of the Williston Basin by over 76,000 net acres to a total of over 680,000 net acres.

Further, our average acreage cost for our entire Williston basin acreage is currently $419 per net acre. Highlighting, done here in green, recent exploration results in the Williston Basin is the Arnegard 21-26 discovery well at our Hidden Bench prospect.

This well was completed flowing 3,092 BOEs per day from an 8,913-foot lateral in the Bakken formation. The well, which was drilled to a vertical depth of approximately 11,490 feet was fracture stimulated in a total of 30 stages, all using sliding sleeves.

We own 59,170 gross and 30,900 net acres in the Hidden Bench prospect, which is located in McKenzie County, North Dakota. We plan to drill or participate in the drilling of 26 wells on the prospect during 2011, and 11 of these will be operated.

Also at Hidden Bench, we completed the Rovelstad 21-13H, flowing 2,450 BOEs per day. The well was fracture stimulated in a total of 30 stages, all using sliding sleeves.

The Rovelstad well is located approximately 2 miles northeast of the Arnegard well. Slide 10 shows the reference points 1 through 9 for our cross section on the next slide.

Please make note of them. Moving to Slide 11, here's the cross-section of our core properties in the Williston Basin.

Numbers 1 through 6 represent what we refer to as the Lewis & Clark Greater Prospect area. Our in-house core analysis has permitted us to locate the sweet spot in each prospective interval.

Note that the Sanish sand is approximately 15 to 20 feet thick at Pronghorn at location #1 and thins out to about 2 feet at Beaver Creek, that's #5. Having a thick Sanish sand section is a plus.

We completed the Hecker 21-18TFH well in the Sanish sand at an initial flow rate of 3,612 BOEs per day. However, it is not necessary to have Sanish sand interval.

We completed both the Federal 32-4TFH discovery well and the recent Clemens 43-9TFH (sic) [Clemens 34-9TFH] in the underlying Three Forks formation with IPs of 1,970 and 2,108 BOEs per day, respectively. I'd like to slow down here to emphasize our confidence in the Greater Lewis & Clark well results by reviewing with you by moving from A to A prime, our well results.

Starting at point #1 on that Pronghorn side of this cross section, I'd like to remind you that the Kubas tested 1,953 BOEs a day; the Froehlich, 2,090; the Hecker, 3,612; the Richard, 1028; the Obergard [ph], 1,190, so that these wells have averaged 1,974 BOEs per day IP on a 24-hour test. Moving to Big Stick, the Teddy 44-30 IP-ed at 1,873 BOEs per day.

At Elkhorn Ranch in Beaver Creek south, we feel this new Clement 44-39 well, which IP-ed at 2,108, has done a great job of de-risking those areas. Moving to Beaver Creek, #5, the Federal 32-4, IP-ed at 1,970 BOEs per day.

And at Hidden Bench, the new Arnegard and Rovelstad wells, of 3,092 and 2,450, certainly show great results. So if as a fault of ours, we have not emphasized that correctly or if someone, in my opinion, doesn't get it, that these wells are excellent, and the results are great, we'll try to do a better job in forthcoming news releases to get that point across.

Because certainly, our confidence is high, and we feel we have de-risked over 60% of our acreage across Lewis & Clark. On Slide 12, I'd like to highlight the completion of the Clemens 34-9 in the Three Forks formation, producing 2,108 BOEs per day.

The Clemens well was drilled in the north central portion of the Lewis & Clark prospect in Billings County, North Dakota. This fracture was stimulated in a total of 30 stages.

It's new producer was drilled approximately 5 miles east of the federal 32-4TFH discovery well, which I mentioned was completed flowing 1,970 BOEs per day. Also at Lewis & Clark, in our Pronghorn area, Whiting completed the Richard 21-15TFH in the Sanish sand, flowing 1,028 BOEs per day.

The Richard, which was drilled on the southeast side of the prospect from Stark County, North Dakota, was fracture stimulated with 30 stages, all with sliding sleeves. We own over 387,000 gross and 254,000 net acres in the Lewis & Clark prospect, which is more than 3.5x larger than our Sanish field.

At Lewis & Clark, Whiting has controlling interest in 164 1,280-acre spacing units, with an average working interest of 64%. Based on production to date at Lewis & Clark, it appears that these wells have relatively shallow decline rate.

Therefore, we continue to believe that our wells at Lewis & Clark will have EURs in the 300,000 to 500,000 BOE range. Whiting's net production from the Lewis & Clark prospect averaged 2,640 BOEs per day in the second quarter of 2011, up 93% from the 1,370 BOEs per day average in the first quarter of 2011.

As of July 15, there were 9 wells being completed or awaiting completion and 6 wells being drilled. We currently have 6 drilling rigs operating in this project, and we expect to average 8 rigs working from September through December.

On Slide 13, is an example of the flat production profile of our Lewis & Clark wells. This slide shows the production performance of our 40 -- of our Federal 32-4H discovery well at Lewis & Clark.

This well produced a total of over 66,000 BOEs during the first 6 months of production, and had cumulative production through July 15 of over 137,000 BOEs. That's a great well in anybody's book.

Slide 14, you can see we continue to generate great results in the Sanish field. We've highlighted several wells for you on this map.

The Nesheim 11-24XH was completed flowing 3,752 BOEs per day from the middle Bakken. The well was fracture stimulated in a total of 30 stages, all using sliding sleeve technology.

We completed the Brookbank State 41-16XH, flowing 2,835 BOEs per day from the middle Bakken. This cross unit well was fracture stimulated in a total of 21 stages, all using the plug-and-perf method.

We use plug and perf on the harder rock in this area to compare with sliding sleeves, and saw no difference in the results except for the higher cost and longer timeframe required to complete the job. We recently completed our second wing well at Sanish.

This was the Oppeboen 14-5WH, and it was completed flowing 2,294 BOEs per day. The well's 6,100-foot lateral was fracture stimulated in a total of 22 stages, all using sliding sleeves.

Whiting has a total of up to 81 potential wing well locations in the Sanish field. The wing well is normally a well drilled within a typical east-west trending 1,280-acre unit near the north or south lease line, with an approximate 6,000- to 7,000-foot lateral.

We also saw strong results from the Three Forks well in the Sanish field, the Vangen 11-3TFH was tested, flowing 1,338 BOEs from the Three Forks Formation. On Slide 15, we've mapped how we are planning the ultimate development of Sanish field.

This incorporates 3 Bakken and 3 Three Forks wells per spacing unit to arrive at the total 469 planned operated wells. Including non-operated wells, we estimate that 261 wells remain to be drilled in the Sanish field as of July 15, 2011.

So we have a 2.5 year inventory of Sanish drilling. Slide 16 is one of our favorite slides.

Whiting continues to lead the pack in terms of cumulative production during the first 6 months from all Bakken wells drilled in North Dakota since January 2009. For anyone with a sample of over 10 wells, Whiting leads the pack by 15,000 to 70,000 BOEs in the first 6 months.

This is why I believe these results designate Whiting's employees as the premier Bakken operator. On Slide 17, please note the 17-mile oil line connecting the Sanish field to the Enbridge pipeline at Stanley, North Dakota is currently transporting approximately 33,000 barrels per day or about 85% of our gross operated oil production in the Sanish field area.

We're currently saving approximately $2 per barrel in transportation costs versus transporting it by truck. In addition, please note the Savage Companies recently reported they plan to build a new rail facility that's expected to add 90,000 barrels of takeaway capacity by the second quarter of 2012.

This brings our estimate to a total takeaway capacity from the Williston Basin to more than 1.1 million barrels per day by 2013. Slide 18 shows the exceptional results we are producing at Sanish and Lewis & Clark as proven by our average IPs and 30, 60 and 90-day rates for our Sanish Bakken wells, Sanish Three Forks wells and Lewis & Clark Three Forks wells in 2011.

With nearly 260 wells in our 2011 drilling budget, we've elected to go to this format, and try to get away from reporting results on every single well. But we hope we've been detailed enough in the press release to show you the great results we've been producing recently.

Now, I'd like to discuss our other exploration successes outside of the Bakken. And to do that, I'd like to introduce Jim Brown, our President and Chief Operating Officer.

Thanks, Jim. And good morning, everyone.

First, let's start on Slide 19 with our encouraging results in the DJ Niobrara. We completed the Wild Horse 16-13H discovery well at our Redtail prospect, flowing 1,321 BOE per day from the Niobrara formation at a vertical depth of 6,762 feet.

The well was fracture stimulated in 21 stages, all using sliding sleeve technology. The well's lateral length was 4,113 feet.

The Wild Horse well produced at an average rate of 454 BOE per day during its first 30 days of production. Based on the results of this well, we added 4 horizontal wells to our 2011 drilling program at Redtail.

As of July 15, 2011, we had acquired over 75,000 net acres in the Redtail prospect and the DJ Basin. Our average acreage cost to date is $462 per net acre, and we have an average working interest of 73%, and an average of net revenue interest of 61%.

I want to add that we are very early in this DJ program; however, we made changes to the Wild Horse well based on what we learned on our 3 earlier completions, and it worked. We changed the azimuth.

We changed our frac-ed wood [ph], and we think we have great results. Slide 20 shows our Big Tex prospect.

We frac-ed our first horizontal well at Big Tex the 1st week of July, 2011. The Bissett 9701 located in the Delaware Basin in Pecos County, Texas produced 788 BOE per day, that's 92% oil, from the Wolfbone on July 25, 2011.

The well is still cleaning up after frac. The well's 3,600-foot lateral was fracture stimulated in a total of 16 stages, all using sliding sleeve.

As of July 15, 2011, Whiting had accumulated over 88,000 net acres in our Big Tex prospect area and Pecos, Reeves and Ward counties, Texas, in the Delaware basin. Our average acreage cost to date is $540 per net acre, and we have an average working interest of 76%, and an average net revenue interest of 57%.

We currently have 2 rigs active at Big Tex, and we plan a total of 4 more wells by year end 2011. On Slide 21, I'd like to now turn to our 2 EOR projects, the Postle and North Ward Estes field.

These 2 fields, combined, represent 42% of Whiting's total proved reserves and 25% of our current production. For 2011, we are estimating our total capital expenditure at $314 million for the 2 projects.

On Slide 22, you can see the production forecast from the proved and probable reserves at Postle field. As of July 2011, Postle was producing 8,350 BOEs per day, and is expected to remain on a general decline for the next several years.

On Slide 23, in an attempt to get North Ward the recognition that we feel it deserves, we plotted North Ward Estes and the Postle production forecast on the same scale. Consequently, you can see the importance of our P2 and P3 reserves at the North Ward Estes field, which could add significant production to the field in the next several years.

As we reported in our news release on June 8, 2011, we have been experiencing under deliveries of CO2 contract quantities from our North Ward Estes field CO2 supplier. The shortfall in June 2011 was approximately 25 million cubic feet per day below our contracted delivery volume of 134 million cubic feet per day.

The supplier attributes the shortfall primarily to a production imbalance currently being made up by the supplier to a co-owner of McElmo Dome. For most of July 2011, our daily CO2 deliveries have increased to approximately 122 million cubic feet per day, and the supplier has informed us they plan to resume delivery of full contract quantities by September 30, 2011.

Whiting is currently injecting approximately $250 million cubic feet per day of CO2 into the field, of which about 60% is recycled gas. We recently signed a 15-year CO2 supply agreement with Summit Power Group, LLC and Blue Strategies, LLC.

Whiting will receive manmade CO2 as a byproduct of Summit's Texas Clean Energy Project, TCEP, a coal gasification project to be built in Penwell, Texas. Penwell is located only 18 miles east of the North Ward Estes field.

Whiting will be the first in the Permian Basin to purchase CO2 from a power project that will generate power to the coal gasification process. The plant is expected to commence operations by early 2015, at which time Whiting will receive 80 million cubic feet per day of compressed CO2 from our pipeline that will connect to the TCEP plant.

With our existing supplier of CO2 at North Ward Estes, Whiting recently executed an amendment to our contract for additional CO2 supply for a 6-year period beginning January 1, 2012. As a result of our TCEP contract and the amendment to our existing contract, we estimate that we have sufficient supplies of CO2 to fully execute our development plans at North Ward Estes for many years.

The first 2 phases of North Ward Estes project were completed by December 2009. Phase 3 began in December 2010, and Phase 4 is expected to be implemented before year end 2011.

On Slide 24, you can see that as of January 1, 2011, we began to accelerate our CO2 project at the North Ward Estes field located in Ward and Winkler counties, Texas. We plan to have all 8 phases of our CO2 project implemented by 2016.

We believe that in addition to improving the net present value of future production from the field, we will be able to increase production and convert probable and possible reserves to proved reserves at a faster pace. At year end 2010, a total of 130 million BOE of probable and possible reserves were assigned to the North Ward Estes field.

This represents a potential 43% increase to Whiting's 2010 proved reserves. On Slide 25, you can see that based on independent engineering as of December 31, 2010, remaining CapEx at North Ward Estes totaled $1.9 billion.

Slide 26 shows that production from our North Ward Estes field averaged 8,125 BOE per day in the second quarter of 2011. This average rate represented a 6% increase from the 7,700 net daily rate in the second quarter of 2010.

Slide 27 shows the curve our technical team uses to track performance from the flood. This curve is for the Phase 1 portion of the field, and shows the actual oil recovery compared to the original oil recovery forecast at the time we acquired the field in 2005.

The conclusion drawn from this slide is performance above the forecast line is good. Slide 28 is similar to a slide we previously had in our presentation.

This curve shows the proved, probable and possible recovery forecast, which total 15% incremental recovery. This curve also shows for a portion of the field, which is Phase 1, the proved reserve recovery moved up to just over 6% from the original 5.5%.

With continuing good performance and additional EOR production history in the field, we should be able to start gradually moving probable and possible reserve volumes into proved at year end 2011. In 2010, 18.2 million barrels of PUDs were moved into the proved developed category.

Slide 29 shows the significance of our 2 EOR projects in our Bakken play to our total production. In the second quarter of 2011, these 3 areas contributed 43,210 BOE per day or 67% of our total company-wide production of 64,120 BOE per day.

Now I'd like to turn the call over to Mike Stevens, our CFO, to discuss our financial results in the second quarter of 2011 and our guidance for the rest of 2011.

Thanks, Jim. Please note that all of the share and per share amounts prior to the first quarter of 2011 have been retroactively restated for all periods presented to reflect the company's February 22, 2011, 2-for-1 stock split.

On Slide 30, we show second quarter 2011 adjusted net income available to common shareholders of $120.3 million or $1.02 per basic and diluted share. This compared to second quarter 2010 adjusted net income available to common shareholders of $72.2 million or $0.71 per basic share and $0.66 per diluted share.

A reconciliation of adjusted net income available to common shareholders versus net income available to common shareholders is reflected on Slide #38. Discretionary cash flow in the second quarter of 2011 totaled a record $313.3 million, representing an increase of 37% over the $228.2 million reported for the same period in 2010.

The increase in discretionary cash flow in the second quarter of 2011 versus the comparable 2010 period was primarily the result of a 29% increase in the company's realized oil price. On Slide 31, you will see that we posted a record quarterly EBITDA margin in the second quarter of 69% of our average blended price of $78.45 per BOE.

We expect our EBITDA margin to improve to over 70% during the last half of 2011. On Slide #32, you can see we continue to maintain a strong balance sheet with total long-term debt of $1.06 billion, and a total debt to total capitalization ratio of 27.8%.

Slide 33 shows that our 2 senior sub-notes are trading well over par. It also shows that we are well within all of our covenants in our credit agreement and our bond indentures.

Our next redetermination date is November 1, 2011. Our guidance for the third quarter and full year 2011 is on Slide #34.

We expect a nice production increase in the third quarter now that the weather has improved in North Dakota. And we've begun to reduce our inventory wells, awaiting completion and service units.

On Slide 35, we show our current hedge position. We like to be 50-plus percent hedged on oil production.

This allows us a reliable stream of cash flow, while maintaining exposure to potential oil price upswings. For natural gas on Slide 36, we prefer to enter into flat fixed-price gas contracts.

This offers us a predictable cash flow stream on 30-plus percent of our current gas production. Since these contracts are well-head prices, it takes the risk of unfavorable differential movements out of the equation.

I'll turn the call back over to Jim Volker.

Thank you, Mike. Angela, please open up the conference call for questions.

On Lewis & Clark, could you talk about the shallower production declines you're seeing? Can you quantify that and compare it to what you saw on average at the Sanish field?

Well, the production decline curve is in our slide presentation. We just moved it slightly for you, and it's very typical for the example.

You'll find it in the sort of appendix, which is out there on the Web now, and it's very similar to the 32-4, and there's nothing in there that we think would indicate other than something in the range of in that particular well, perhaps, 400,000 BOEs per well. So we see that really pretty much on average across Lewis & Clark.

It is a shallower decline curve, so -- but the wells do come in at somewhat lower rates, essentially around 1/2 to 2/3 of the rates that we saw at Sanish. On the other hand, they don't decline as rapidly or as far, and they typically level off, as that decline curve shows you, at about -- first, at around 300, and then at around 200 to 250 BOEs a day, and you'll find that on Slide 13.

Okay. That's helpful, Jim.

And then in terms of the last 10 well results, you gave the 2 specifically, and if my math is right, the other 8 seem to average at 24-hour IP rate of just over 400 barrels a day. So could you talk about that, and could you talk about where are those wells located.

And then specifically, the Wolski well in the Northwest part, does the result of that well suggest that, that area just is not going to be as good as the 60 or so percent that you've de-risked?

No, I'm going to let Mark talk about this in a second. But I want to get the subject of the Wolski well put aside.

First of all, that well is not a Three Forks well. So it's basically a science well drilled in another zone, and is not comparable to what we're doing across Lewis & Clark.

And Mark, take it away after that.

Okay. Just a couple of things about Lewis & Clark.

Much of Lewis & Clark, we feel like we've de-risked probably up to around a third of it. But we continue because of the size of the acreage [indiscernible].

It's really important to recognize what our drilling program is all about down there. And if you look at the slide on Page 9 and kind of walk you through that.

Down in the southern part of Lewis & Clark, there's a tier of wells at the very bottom, that we had some lower IP rates in the neighborhood of 500 barrels a day, and what we're really doing down there is defining the margin of the reservoir. We effectively did that.

We probably drilled 2 too many wells down there to really do a good job of that. I think we could have done it with 2 less wells, but we have defined the southwestern margin of our Lewis & Clark.

And as you go north out of there, we've got substantially better results. And so we have a very nice development program going on in that southern part of Lewis & Clark that we call Pronghorn in there.

And so we've got an awful lot of good acreage, and you can see the results, we've already talked about them. A lot of good results there at Pronghorn.

As you go to the very opposite end of the Lewis & Clark prospect, there is a well up there, this Wolski well, that tested a different zone, that Jim just mentioned, where we continue to try to do some exploration in here. And so this is one area that we decided to go ahead and test what we call the false Bakken or Scallion interval, and that well ended up not being as successful as we had hoped for.

We don't feel like it condemns the play necessarily, but that well did not work out as well as we had hoped. So between those 2 kind of bookends on the play, we've got a lot of great results to talk about.

But anytime you're trying to de-risk 300,000 acres, which is what we're doing here, you're going to find some both good and bad results, and especially around the margins in the reservoir, and that's what kind of what happened on the south side.

To try to summarize for you, in terms of what we think on average across the play, I'm going to give you a range, 300,000 to 500,000 BOEs per well and about a $6 million well cost. So roughly somewhere between $18 million and $24 million of future net for a $6 million well cost.

I think that will be the range across the play. And by God, I think that's one of the best plays going on in the United States today.

That's very helpful. And then, I guess, Mark, in terms of those, I guess, some of the stinker wells you drilled down there in the southwest margin, the other wells besides those, were they kind of in line with...

Yes. So if you look at that very southern tier, that's where the disappointing wells were.

But you go immediately north of that, we've got a number of -- that mixture of wells virtually all of them are above 1,000 barrels a day. So we're back into the sweet spot for the vast majority of that Pronghorn area.

You got to test the margins as well as the center. You got to eat the crust of the pie or at least find out where it is as well as the thick part of the pie.

Staying on Lewis & Clark, the cross section that you all gave in terms of the average rates you've been seeing in areas like Pronghorn, then moving over, was really helpful. I'm trying to get a sense of how much of your acreage would you classify as being in Pronghorn within Lewis & Clark.

About 1/3 of it.

About 1/3 of your acreage, okay. And then the next thing, on your all’s production guidance, I'm trying to get a sense of how much of your production guidance did you all include for the 18 wells you're drilling in Hidden Bench, the stuff in Cassandra, Niobrara, is that included in your guidance?

And if so, if you could just kind of add some color to that.

Well, the answer is yes, I think we probably could have taken our guidance up a little bit over what we had done earlier. On the other hand, keep in mind that what's really happening to us is that we were relatively flat on production in the first half of the year due to weather.

Now what you're going to see in the second half of the year is basically a 14% increase in the second half of the year as we essentially moved out of the inclement weather conditions that we saw primarily in North Dakota and to a lesser extent, a couple of things that affected us, CO2-wise and weather-wise, at our 2 EOR projects. So we could have been somewhat more optimistic, I think.

And I'm very, very pleased, I will say with the reaction of all of our employees, especially at the North Dakota, who had to deal with the flood and everything else, some of them affecting their homes and family lives, and have really put the pedal to the metal, and brought us to a new record for our net daily production in operated in the Williston basin. So maybe we are still being a little conservative on guidance, but I want to make sure that we're past these hiccups and essentially do a good job getting all these wells back on production and it does appear, as I've just said, that that is well underway.

So maybe we'll raise it when we get through the third quarter. I would say that might be likely.

Okay. And then just the last question I had, and I'll turn over to somebody else.

At Big Island or any of the additional coupled wells you're going to drill there, are there any plans to pursue the Scallion?

We have. I think we announced this.

Maus well, you could see the Maus well, Red River well at Big Island. We do plan to do one more this year, Red River well that was a Red River test, and so it's conventional production.

And so we're pretty happy with the results of that. We have one well further to the north.

You can see it depicted on the map. It's a horizontal well, and it does test a zone that is non-Bakken.

And I guess it's fair to say that it will be a Scallion test. We've been working the Scallion pretty hard, and we think that we've got a decent shot up there.

And we've got an awful lot of acreage to follow-through on that if it's successful.

John, it looks different there than it did at the Wolski.

Yes. It's about a county away, so it's a – the Wolski certainly doesn't condemn the play.

Just trying to close the gap here on Lewis & Clark. What's your -- at that 300 to 500 MMBOE, 6 million with your decline rates, what are you projecting for IRRs?

We got a slide in here that pretty much answers that question for you on our typical Three Forks well.

Okay, so I should use that. The one that's on?

53, slide.

Page 53, yes, all right.

Yes, so typical Three Forks well at 400,000 BOEs and it’s about a 92% IRR, a 1.2 year payout, about 3.2:1 on our money at $90 WPI.

Okay. Yes, okay.

That's fine. I have that.

Can you give us any feel for how much weather impacted your production? You're at whatever the mid-point of guidance is, 7%, 8%.

If you were – do you have any feel for what the weather impact?

Well, on the optimistic side, I think we would have been up there around 15% for the year without it.

Okay. That's helpful.

All right, I always ask this question in August, but do you care to give us any color on '12?

No, we'll do that when we come out with our Q4 results. The only thing I can say on that, I think, advisably, is that you can see, hopefully, as a result of the new discoveries that we have, and I would say the quickening pace of development in all across our Bakken and Three Forks Hydrocarbon System, that 2012 is going to be a great year for us.

It’s going to be a great year. So again, I would just say that unlike perhaps some people who took a jump early here after reading our press release, we apologize that we didn't do a good job of getting the story across.

But Lewis & Clark, we believe, is a home run and maybe 3 home runs, i.e., 3 times as big as Sanish. So we're highly optimistic about it, because the economics are great.

The only thing I can say is maybe it'll average more like 3, 3.5:1, than the 4 or 5:1s that we were getting on our money early on in the little Bakken development at Sanish, but those are great results. In fact, the oil prices are going up and helping us.

We also still, in our opinion, going to pay out in somewhere between just under 1 year and 2 years across that 300,000 to 500,000 BOE EUR range. So I'm telling you, it's the best play I've seen in my now almost 40 years in this business, and we're going to take advantage of it.

One other thing, and we're going to pull off the hat trick for you herein too. We're going to have increasing net present value per share.

We're going to have increasing reserves. We're going to have increased production, and we're not going to have had to sell any stock or bonds to do it.

Good. One final question going back to the CO2.

I guess you indicated that you'd get that quantities, that they indicated to you that they’d resume full deliveries by the end of the third quarter, September 30. What's -- I mean, is there a chance it doesn't happen or could it be sooner, can you just give us some more clarity around that?

Well, the reason that could happen -- would happen sooner, and I can't say it could. But the reason that it might happen sooner is -- really has to do with this imbalance they're working off with their co-owner there.

And should that be called on quicker, then the imbalance situation would be taken care of sooner, and we would go back as with all of their customers, including themselves, who they say they've cut back equally, proportionately across everyone, and everyone would go back to full deliveries sooner. That would make the difference.

Okay. And if you do get it by September 30, does a Phase 4 still planned for before year-end if you get it by September 30?

Yes. This is Jim Brown.

Yes, we've scheduled that, that the shortfall will still allow us -- I mean if the shortfall continues, it will still allow us to move ahead with Phase 4.

And we handle that, now let me just say, Dave, by wetting up other parts of the field, in the wag [ph], [indiscernible] remaining gas and taking the CO2 we need in order to kick off Phase 4. Now let me put in a good word for Kinder Morgan here.

They're doing everything they can, in my opinion, to drill more wells up there at McElmo Dome and kick up the supply, which I think they will do. I mean, we're out there doing what we need to do in order to watch their activities, and they certainly are ramping up.

They're a good company, in my opinion, delivering on their contractual requirements. So we're not really worried about that.

I'm looking at Page 6 of your recent presentation, and I am comparing it to the previous presentation. When it comes to CapEx, it looks like you -- I would say you reduced your CapEx in the Sanish, and you increased your CapEx in Lewis & Clark, but you're talking about 1 gross, 1 net wells.

Not much difference really. As you can see, Jack, to sort of answer your question on a grand scale, in total, we've gone from $707 million in the Northern Rockies up to $767 million and the well count's up from $180 to $217 million.

And sorry, if we didn't do a good job on getting our Lewis & Clark results across to you. I'll tell you what, Jack, I think we're on the right track there.

Things are going well and we're going to ramp up there even greater next year. We're going to have more rigs working in the Lewis & Clark as we get to the end of the year and next year, just like we've said in the press release.

Our confidence is very high up there, very high. I think we're going to have somewhere in the range of 2 to 3 Sanish fields up there to develop.

Jim, could you give us an idea of what you're -- just based on the one well results, the Wild Horse well results at Redtail, what you're thinking about the EUR for that well?

Sure. You know, I mean, it's obviously early, but we are shooting for something in the 250,000, 300,000 BOE type range out there in the DJ Basin.

Okay. And so would that well be sort of right in the center of that, or do you think it's on the high or low side?

I know it's early but...

We think this well is probably going to be -- we're hoping -- we're pushing the upper limit on it with this well. Well, it's going to take some more time to see, but we remain very encouraged at this point.

And is there anything in the geology in that play that would skew the expectation on this well to being on the high side? Presumably you'll drill the better areas first?

Well, I mean this is -- you're talking about a project that I'm very kind of involved in, because I am very encouraged that the science that we have employed here has kind of led us to where we are. Mark Williams and his team, I think, has done just a tremendous job.

I mean, the first wells we drilled out there, we learned a lot, and we employed it on this Wild Horse well, and everything from -- we were drilling our wells with the same azimuth everybody else was out there, and you saw our results. We changed our azimuth by 90 degrees, drilled in another direction, and things really took off and started working.

So no, I think we are taking the science, and we're employing it across here. And the second well or the next well we're going to frac is one that's drilled with the same azimuth as the Wild Horse.

We remain very encouraged with what we saw when we drilled that well. So I'm very confident that we've kind of got this thing figured out.

And as we did early on in Sanish, it takes us a while to unlock what we're doing out here. But so far, everything we have changed seems to be working for us and taking us in the right direction.

Gil, I'll add to that by saying that in the last couple of days here, we've been in contact with some of our peers who own acreage in the area, and we've shared some of our data with them, and they in return have shared their data with us. And I'm going to say that in sort of reading both our results as well as the feelings from those discussions that we've had, that in general, the feeling is much more positive than it was as recently as 20 or 30 days ago.

And a lot of that, I believe, has to do with the way in which the wells are now being drilled, and the way in which we're frac-ing them. And when I say we, the collective we of all the people who are sort of out there in what I would call the mineral belt trend that runs basically northeast through Wattenberg.

So those of us who are out there were pretty -- we're highly optimistic, and I would ...

Does the fact that you're sharing data, does that suggest that you're done acquiring acreage at this point?

I would say that it indicates that, yes, a lot of the acreage has been acquired, and that we feel that we're in a commanding, I would say, each one of us feel that we're in a commanding position for filling in within the general outline of each of our respective acreage position, so that -- I'm not trying to tell you that our acreage position will grow, but I think we'll be able to do it now, each of us, sort of within the outlines of our plays.

All right. Just turning back to Lewis & Clark.

Could you just give us an idea of -- do the higher IP rates decline at a higher rate than the lower IP rates?

So far, no. It's a good thing.

Yes, in terms of the variation of results from the sort of 600 over the last -- of the average of the last 10 wells versus the ones that you've highlighted that are 1,000 or well over 1,000, is that just a sort of randomness or unpredictability that we should expect to see? Or do you think that there are some things that you can do to take out that variation?

Well, we can stop drilling on the lower -- the absolute, so the lowest 1 to 2 sections there at the southern end of Pronghorn, which we did. So I think we've already accomplished the location of the edge of the reservoir down there, and we're going to concentrate on drilling [indiscernible] now.

So I think the answer to your question is yes. We think we have de-risked not only the southeast end, but also now the northern and western portion of our acreage, with wells that on average are about 1,900 BOEs a day, IPs.

So our confidence is high, and we intend to get after it with more rigs. We're going to ramp up there as we've already described with a couple more rigs between now and the end of the year and get after it hard in 2012.

Can you comment a little bit on the incremental acreage dollars in the sense -- are those to add acreage in existing prospects, or you all still putting together other acreage positions? And if so, can you shed any light on where?

It would be primarily to add acreage in and around our existing plays, both at Big Tex primarily, and then filling in our acreage positions at across the Bakken Hydrocarbon System. Essentially, it's at virtually every prospect that we show you there on Page 10, as well as I previously mentioned, filling in at Redtail.

I guess I shouldn't ask you if you like Lewis & Clark. That came through pretty clear.

Yes, it's a good looking lady.

Any results from the Cassandra area, I didn't see anything there.

Yes, Cassandra's actually a fair bit smaller for us. But we've got one Three Forks well up there and a couple of Bakken wells, all 3 of which look pretty good.

And I'd say our average up there is right around 1,200 BOEs a day, something like that.

And then given the results you've seen in those Hidden Bench wells, any thoughts of adding rigs there?

We have done that.

Yes, we've done that.

And Hidden Bench, 2 of the wells that we've announced there are outstanding by any standard in the basin. And so going forward there at Hidden Bench, we've added on to our operated wells there this year, 11 operated wells, 6 of which we've already drilled.

It's also a pretty active area, non-operated-wise. There's a number of other operators in there doing very well for themselves and for us.

So there's a total of 15 non-operated wells that we're involved in out there as well. So that's a pretty darned active part of the basin with both ourselves and everybody in there getting really good results.

And you talked about the Scallion a little bit in the Big Island area. Do you view that as a potential resource play, or is it more conventional?

Could you talk about that a little more?

Definitely a resource play, you'll find it very similar to the Bakken. It's a great source rock by any standard.

You can compare it to any of the other things that we're doing right now so. But it is a swing for the fence, there.

What we're really trying to do is demonstrate the presence of reservoir rock and therefore, OOIP, and there's very little information out there. So we got a lot of what we call acorns in that part of the world, that kind of 2 or 3 county area that are all vertical wells that have produced oil out of the Scallion, and so that's one of the big things we go by.

And so we're going to try it with a modern horizontal, and see how that works for us, and a lot of running room. You could see our acreage block there on the slide on Page 9.

We have a very solid acreage position in there if this works, and so there's some risk to it. Any time you got a new play, start a new play like that, there's going to be some risk.

But we feel like it's a risk worth taking, and could be very meaningful to us.

And sorry to jump around here, but I want to go back to inventory for a second. Now what are the costs on the Arnegard and the Rovelstad wells?

Those wells are going to be in the range of $6.5 million, and I just want to talk a little bit just about our drilling down at the whole Lewis & Clark. You know our guys, our drilling team was very successful up at Sanish by implementing this DWOP program up there to get our well cost down.

Currently, for all the rigs running out of Sanish, they've installed this DWOP program in about half the rigs, and that we're already seeing success from that. They have drilled one well down at Lewis & Clark in under 15 days.

They drilled that well in 14.5 days. So we're going to see our well costs outside of Sanish start to approach what our well costs are in Sanish.

So we're fully expecting these well costs at Hidden Bench, Lewis & Clark, everywhere to start getting under the $6 million range and approach that $5.5 million range.

So your 300,000 MMBOE kind of low end of the range that you expect in Lewis & Clark if you can get that under $6 million, that's going to work fine, economically, I would assume.

That's a knock-the-ball-out-of-the-park one.

Okay. And then on the Niobrara, you said you're just kind of looking at filling in acreage at this point.

Any thoughts on looking south of Wattenberg?

We don't normally comment on where we're going to lease, and we're pretty happy with what we've got there in our what we call Redtail prospect up there. We think that, that's going to end up being the sweet spot of the play for a number of geologic reasons, but we are looking elsewhere in the basin, always looking.

Okay. And then just last one for me, on the Bissett.

Was that in the horizontal, was that in the -- that was in the Bone Spring, correct?

Correct, yes.

And do you plan to try one in the Wolfcamp later this year as well?

Where we are for the core of our acreage there, it is -- the Wolfcamp is not the primary zone, it's really the Bone Spring and Brushy Canyon. There are -- as we get out towards the western edge of our acreage, there are a few other operator who are having success in the Wolfcamp, so we may try a couple of vertical wells out there later this year.

And what do you think the EUR of that Bissett well is it at this point?

Well, it's really pretty early, but I wouldn't be surprised at all if we're in the 250,000 to 300,000 BOE range, something like that.

So just staying on Big Tex for a second since we're there, with your first vertical that like came in, I think, was 862. Obviously, the nearly 800 a day rate on the horizontal well is pretty good.

But when you look at this, is this possibly more of a vertical development play where your economics are a little bit stronger there, or how do you kind of look at that at this point?

Well, to be honest, it could be both, both a vertical play and a horizontal play. So we tried both.

And in short, I think we've drilled 14 wells there. We had 2 real good verticals, and one real good horizontal now.

If I had to say what we were going to do next, it would be -- I mean what we're going to do next is we’re going to continue to drill horizontal wells, and try to come up with consistency there in the range of 700 to 800 barrels a day IPs, because we think we are -- through all the science we've done and the core that we've evaluated, we think we have found at least one, if not 2 sweet spots to go horizontal in. In addition, if I were to say what we would next do is that we would go back to all but one of the vertical wells that we drilled, and we'd go horizontal in those.

Why would we not go back into one, simply because the casing in that one is such that it was too small to go horizontal in. So I believe that we have at least 10 highly prospective horizontal prospects there, that is to be reentered.

And then as well as, of course, a large acreage position that can be developed, I would say, with confidence now horizontally, with greater confidence horizontally. With respect to the vertical play, as Mark has said, as we move to the west, we do think the vertical play becomes something that might be prospective for us in the Wolfcamp.

So those are our plans. Basically, horizontal in the second bone, and then we'll look at the potential for some vertical play out there in the Wolfcamp on the west side.

Okay. That's some good color.

And then, I guess, I'll ask another question on Lewis & Clark since that's sort of the topic du jour today. And can you clarify something for me?

You all, I think, expected 350,000 to 500,000 MMBOE per well previously, and you sort of lowered the bottom end of the range on that to 300,000. Can you kind of give me a sense of what kind of drove that sort of, I guess, revision?

Really just a desire to give a slightly wider range, not necessarily on the basis of anything that we see on average across the -- the average is obviously 400,000. And I would say based upon recent well results, we're more confident of being over 300,000 now than we were when we made that last range adjustment.

So I would say on the better portion of our acreage position, we certainly hope to do better than 300,000.

Okay. So if I'm hearing you right, you're still at a mid-point of around 400,000, but you've just widened the range?

That's right.

Okay. And then in terms of how you're completing those wells, I mean you guys have done a great job of being sort of committed to sliding sleeves successfully.

And remind me, have you tested sort of the plug-and-perf concept down in Lewis & Clark on by itself on a well just to see how that would perform versus just doing the sliding sleeve for a hybrid?

Yes, we have. One of the first wells that we did out there, you might remember, we had some issues when we did our frac job, and we had to convert the sliding sleeve into a plug-and-perf job, and that well performed reasonably well.

That was the Paluck well that we did that. And then recently, Mark mentioned the wells that we were drilling down along the southern tier down there.

We were questioning about, is it -- are the results we're getting down there are based on just our sliding sleeve completion technology, or would plug and perf perform better down in that lower tier. We went down there and did a plug-and-perf job on one of those, and the results weren’t markedly different from everything else we did down there.

So we have tested the plug-and-perf completion technology down in this part of the world.

It's all about the rock, better rock, better wells. It doesn't matter, in our opinion, whether you did it with plug-and-perf or hit it with sliding sleeves, and the sliding sleeves to us seem to work the best or at least as well.

And we can do them in a day rather than 7 or 8 days, and they cost a lot less.

And so the work that you all did in Big Tex as well as Redtail, those were all sliding sleeves as well, is that correct?

That is correct, yes.

Is anybody else kind of following your lead on that in some of these other areas, or are you – one of the only ones using that?

We've heard rumors that some of the more committed plug-and-perf guys actually have some sliding sleeve completions in the ground right now.

Is that a comment for the Williston Basin, or in some other area?

It's actually 2 different areas. But the Williston is for sure one of them.

Scott, the other think I’d like to add is just we do have a couple of these, the newer completion technologies in the ground right now, the ones that take a sliding sleeve, and you have -- actually the one we have 2, we're going to set 2 sets of fracs between each sliding sleeve, but we've got to -- we actually have 3 sets of this equipment in the ground right now, and we will be frac-ing those here very soon to see what that looks like.

Okay. And that's in the Lewis & Clark area that you're doing that?

So far it's in the -- everything we've done is in Sanish, and it's just because we want to have the microseismic up there to see what we're doing.

I got it. And then just -- on the completion too, and is that all -- and I think you said you were going to push to something like a sort of simulated 60-stage completion, is that what you're referring to on that you're testing?

Is that -- are you...

You're correct. You're exactly right.

That's the technology that we're testing right now.

Okay. And that's Baker?

Actually, we have 2 different companies’ equipment in the ground right now. We have Baker, and we also have Halliburton.

Just had a question on Hidden Bench, besides your drilling in that area, how much additional well control do you have across your acreage? And just in general, how would you risk your acreage?

I'll answer that, Mark Williams. We have a nice acreage position up there.

You can see in general where the location of that is on the slide on Page 9. You can see where our wells, our operated wells, anyway, are shown by the red lines on there.

So there are other operators that are actively developing in there as well. We've been pretty successful at swapping acreage out to improve our working interest in the 12 80s that we have there, and have given up some of our low interest sections.

But the other areas that are working well are both to the east of us and to the west of us. And so we're pretty well bracketed in there by a pretty active program by other operators.

Newfield, in particular, on the east side, and Brigham more on the west side, as you get over towards Brigham's Rough Rider area. So quite a bit of industry activity happening all along what we call the Hidden Bench trend in there.

The operators are planning to seize all of the middle Bakken, and so that's working out very well for everybody, and it cuts sort of a east-west trend through Hidden Bench.

Excellent question, Eric. [Technical difficulty] try to be succinct here.

I think the drilling that we have done and the drilling that other people have done have essentially de-risked most of Hidden Bench for us.

Okay. Great.

And then in terms of North Ward Estes, what would be just a general expectation for production here? Should we expect kind of maybe a gradual decline through year-end as you reconfigure and as -- until the CO2 deliveries ramp up, should we expect flattish?

Just to kind of set expectations through the second half of the year.

I think flat to gently rising.

Okay, super. And just because we can't say enough about Lewis & Clark, when you look at the variability in wells there, and let’s throw out the wells in that southern tier, do you think there's any real greater variability on maybe a 30-, 60-day basis than you're seeing up in Sanish?

Is there greater variability in the underlying rock, do you think, somehow?

Well, again I would say not on average, not on average.

Okay. So it looks like over a 30- and 60-day, or let’s say over a 30-day rate, where you have a handful of wells, but maybe enough to make some -- it seems like they're stabilizing somewhere in that 400 to 500 barrel a day range which is similar to Sanish, is that fair to say?

Yes, very similar. I mean the decline rate, we think, will level off pretty quick.

Has. And if you go to sort of Page 18, and so you look there at our average over the first 30 days, and we think it's going to be in the 400 to 500 barrel a day range, BOE a day range in the first 60 days, it's interesting that...

Still 500?

Yes, because it's got a slightly smaller...

Smaller number of wells in there.

Smaller number of wells in there. But anyway, it does tend to indicate that by the time you get out there around 60 days, things have really started to already show a flattening.

And the last one I had was just in terms of mid-year. Have you done a mid-year reserve report?

And if so, do you have any idea what your PV10 might be mid-year, or even -- have you done an updated PV10 from year-end at current prices? I just want to kind of get an idea of what the value of the company might be just on a proved basis.

I don't want to go into that not because the -- I mean, the answer, to be honest and direct, yes, we've done it. No, we're not going to release it.

We'll release it at year end. And I've already said, I think you're going to see a nice reserve increase at year end, a nice increase in MPV per share as a result, and good increases in production between now and year end that, basically, I think we're going to be – it would have been in the teens, overall, had we not have the severe weather problems as a year-over-year growth factor.

And now, we're going to be cut to half of that. So from the mid-teens to half of that as a result of the bad weather.

But basically, we're going to make it all up here in the second half of the year.

The 2 dedicated frac crews that you have currently, when are those agreements set to expire?

Biju, this Jim Brown. We just went through the renegotiation process on those, and we just extended both of those crews for 2 years.

Okay. And can you talk about what the new price is versus what the price was before?

Sure, yes, we've seen a -- as you might suspect, we've seen a price increase. It wasn't near what we'd heard some people talking in the market out there.

I'm going to say we're in the range of 10%, 15%, something like that.

Okay. That's helpful.

And then on the new CapEx numbers, the number for other Permian went up something like, I think, 40-something million. I was just wondering, is that a new player that you were testing there, or is that some of your legacy programs.

The well count also, looks like the well count went down.

Well, I think you might be -- we might have done something there to slightly confuse you. Actually, the well count is down and the total drilling budget is down.

It's down from $120 million to $107 million across the total Permian, and that's because we had some old legacy properties that we were going to do some additional drilling on, but those were held by production. There's no hurry in doing that.

And the results that we -- the good results that we've seen at Big Tex encourage us to put that capital to work at Big Tex. And as I mentioned earlier, some of our opportunities there are now to go horizontal in well bores that we've already drilled.

So we'll actually get essentially a bigger bang for our buck doing it this way than involving any of those legacy wells that we previously planned to drill. So these are higher ROI, higher IRR wells, and we can also help our production, and do it, I'm going to say, more efficiently and effectively by concentrating on Big Tex rather than the areas outside of Big Tex that were legacy for us.

Right, but I was looking at the other Permian line that went from, I think, the old number was something like $3 million versus $47 million in the new budget.

Yes, that just reflects the -- a little bit of -- I shouldn’t say a little bit -- that just reflects, I guess, what I'd say, a quantification of some continuing programs that we have down there on legacy properties that we didn't cut.

Got it. And then on Page 15, if I look at the inventory, you have about twice as many Three Forks locations remaining at the Sanish field compared to Bakken locations.

From a drilling standpoint, should I think that ratio would go about twice as many in Three Forks wells, or would you drill the Bakken well first, or some mix of that?

It’s Mark Williams here. It's important to realize there that we've set out drilling primarily Bakken wells, and so we have an awful lot more Bakken wells that have been drilled, which leaves us a greater number of Three Forks wells.

This year, we're really focusing on developing the Three Forks. So I think by the end of the year, we'll have substantially – or perhaps by this time next year, we’ll have caught up in the ratio of Three Forks to Bakken wells.

Just curious on the $200 million land budget. About how much of that has already been spent this year and obviously, how much is going to be spent in the next 6 months?

I'd say we're probably about 70% of that budget already spent. So we've made some pretty big acreage acquisitions already this year.

But we feel like we've got -- we're pretty full up in terms of -- especially for our Bakken stuff.

There's about $90 million of it that hasn't been -- what we've just disclosed in the press release, $90 million of it hasn't been spent.

Okay. And then, I guess, just looking to next year, do you think that, that's going to be a similar-type number, in the $200 million range, or do you think that's going to move up or down?

Right now, I guess, it will be similar.

Most of my questions have been asked. Just to clarify though, can you talk about the Three Forks potential and well control in your Hidden Bench and Cassandra areas, as well as just sort of comment on any new or changing interpretations of your Montana acreage as the play extends to the west?

I'll start out by trying to be succinct on that. I think Hidden Bench has excellent potential.

We think we have good sub-surface control there. And so if I had to say at this time, whether we thought we thought there was any portion of Hidden Bench that wasn't prospective, the answer would be no.

We think it's all good. Over in Starbuck, I would tell you that our barter for that prospect is increasing because of not only the work being done by others, but preliminary, let me say, science that we did on the 2 wells that we drilled in terms of looking at the core, et cetera, and we will have some production results on them here within the next couple of weeks.

So basically, people are drilling wells in and around Starbuck that have come in between 1,000 and 1,800 BOEs a day. I believe the numbers are 1,080 and 1,800.

And those are basically other operators over there like Brigham, drilling those kind of wells. And now, there's a couple other new operator coming in and drilling, let's say, within our Starbuck general outline, and then some immediately to the east.

So Starbuck does appear to be getting de-risked, and the issues that we and others thought might be there in terms of why the production has not materialized, and I would say that you're looking for somewhere between 250,000 and say 350,000 BOEs out there as a preliminary guess.

Most of my questions have been answered. Jim, I just wanted to ask you kind of a general question on the Bakken and the weather.

Can you give us what it’s like on the ground right now and how things are cleaning up? And are you guys doing anything differently from an infrastructure standpoint in case we have another bad winter or weather type of issues?

Yes, it's dry. It's dry, hot and dusty.

So that's all good. In terms of infrastructure, essentially, I mean, we did well there in the sense that our wells were connected in general to the line and so those wells that we were able to keep on production didn't have any issues.

What basically slowed us down there was a couple of things. Number one, if anything happened like a wild fire or anything, that well had to be basically shut in because we couldn't get a workover rig to it when everything was really snowy, icy or muddy.

The other thing that happens is from time to -- when we frac a well, we sometimes shut in wells around there just in case there might be some sort of communication. From time to time in limited circumstances that does happen.

So as a caution, we shut those wells in and if those wells happen to be shut in at the time that the bad weather hit and then the mud, we’re just getting around to getting service units back there to put them back on. Because basically we take the tubing out of them and then we have to run the tubing back in.

So in terms of our plans for next year, because a greater number of our wells will already be hooked to the pipeline, I don't think that we'll have as big a situation next year. We can't predict the weather, but I would say to kind of look at our slides for today, if you go back to that Slide #3, you can see that basically about once every 2 years or so, there is some event that occurs usually related to weather that causes a downward spike over a short period of time in production.

So all I can say is, I think next year because of where we are in our development plan, it will not be as marked a result on us, even if weather is as severe as it was this year.

Great. I appreciate the color.

I got one other question, and maybe I'm looking too much into this. On that Niobrara well, it seemed like you tested it with an unrestricted choke.

Was there anything behind that or a reason how you're kind of producing those wells? Are you producing them wide open like that?

Or...

Yes, on those Niobrara wells, the pressure out there, these aren't as overpressured as the wells that we have up in North Dakota. And one of our concerns is we want to make sure that we get the entire lateral on production and what we feel helps us do that is put the greatest effort, delta [indiscernible] across there as we can.

So that's one of the reasons we produce these a little more aggressively than we do perhaps one of our Bakken wells.

And that 4,100-foot lateral, you think that's the norm or are you going to push the limit and try to make it go a little bit longer?

We're going to push the limit and go a little bit longer. The next couple of wells we have permitted, we've got some 960-acre spacing units put together, which will give us about a 7,000-foot lateral.

You had -- were just talking a little bit about weather in the Bakken and so on. And I'm just curious if you could update on Bakken logistics, specifically the rails.

I know they’ve had some issues and you may have had some issues and other producers getting white sand delivered. So if you can just catch us up on just general logistics post the flooding.

Well I'll try to be direct, if Jim Brown wants to add more. I think there's only been 2 wells where our frac-ing operations have been slowed down as a result of the inability of our service people, the frac-ing crews that we're using up there, in order to get sand or ceramics.

So it hasn't really affected us on that score more than a day or 2. Second, with respect to overall takeaway capacity out of the Bakken, we've got a slide for you there on Slide 17, which shows that things are headed towards the 1.1 million-barrel takeaway capacity.

The other thing I'd like to point out is that on the top line there on Page 17, you'll note that the Enbridge addition has already happened in Q2 of 2011, and they're working hard to bring that additional 145,000 barrel-a-day increase much earlier in 2012 in Q4. So not to pat ourselves too much on the back here, but I think the best thing we ever did was to lay our own line right up there to Enbridge.

Because that's the market, that's the best market. The Midwestern market basically on Enbridge into the Midwest is the best.

And thanks to efforts of our marketing department, and I might say Enbridge, with getting this crude essentially indexed now to a Louisiana light sweet, the differential has improved. So we're feeling good about both the takeaway capacity and the price that we're getting there.

We're happy to see that other people are taking steps to get their crude out and I'm going to say not trying to get it all into the Enbridge line, that's good news for us. Because we were early and prime mover, moving directly into the Enbridge line, which is, I'm going to say, the premier market out of the area.

So it has the lowest differential. And we're lucky to be hooked up to it and, frankly, we think Enbridge is doing a credible job of increasing the capacity of that line.

It's going to be a real moneymaker for them.

My follow-up would go to Jim Brown on the Redtail Niobrara, you've been pretty clear today on the call that you feel like you've got it figured out after those first 3 wells were poor and then you had the real strong Wild Horse well. Could you give us sort of the top 2, 3 reasons as to why you feel that way as you move forward in this play?

Sure. The first 3 wells we drilled out there, we kind of did what everybody else did.

We drilled them with the same azimuth that other operators were drilling with. As we ran microseismic on one of those 3 wells, and it became clear to us that we needed to do something different, and so we actually changed the direction of our azimuth by 90 degrees, took off in another direction that seems to have worked very well.

We've also changed the pH of our drilling fluids, and I always get this confused. We either went from a low pH drilling fluid to a high pH drilling fluid, and I might have that backwards.

But anyway, we switched the pH on our drilling fluid, and we also greatly increased the amount of profit we pumped in this last well. And it just seems the combination of the work that we had done, all of the science told us we needed to go that direction, we did it and it appears to work.

Great. And then finally, on service cost inflation and the outlook there, where do you see service as very tight and what's your expectation for service cost inflation moving forward and then how much of this CapEx increase is related to that?

We are probably seeing a service cost increase on the range of 10%. But let me point out that on our frac crew, the way that works, I mean, they're dedicated to us full-time.

So the more wells we frac, actually our frac cost goes down because we get to divide the cost of that frac crew over a greater number of frac jobs. So as the weather improves and as we're able to pump more frac jobs per week, we actually see a decrease in our frac job cost.

As far as we're seeing new pressure pumping services come into the market, up in North Dakota, down in the Permian, here in the DJ, so we are very -- our opinion is that we're going to see the pressure pumping costs start to come down as we get into 2012.

Hey Jim, can you help us back at Hidden Bench, give us an idea of how much room you've got to run there? You're already ramping up to 26 wells but if things work out, what's your potential inventory of locations there?

And I know you've talked in terms of some of your neighboring operators having good well results, but what other color can you give us in terms of your conviction level there?

Our conviction level is high. I can say that.

In terms of the total number of wells that we can drill there, you can just kind of take a look at our map and divide by 1,280 acres and you’ll come up with the number of potential units and then multiply it times 3 and you’ll get the total number of possible wells. So it's a great area for us.

Okay. And then another question just on terms of acreage, you mentioned in terms of having derisked more of Lewis & Clark.

Could you sort of give us a sense of what you thought the acreage was that was core in Lewis & Clark? I imagine more towards the southeast portion.

What you think it is now in terms of core acreage. And on a comparative basis, what's it compared to in terms of Sanish, in terms of acreage size?

I think we tried to summarize for you that at Lewis & Clark, we think that we've -- in terms of the gross acres, we're somewhere around 2/3 of it. So that's about 2/3 or 387,000 acres.

So that's around 260,000 acres that we think we've reasonably derisked. And so I would say that other than that 1- or 2-section tier on the southern part of Pronghorn, we think everything North of there, as you could tell by where the red lines are on the map on Page 9, is prospective, highly prospective.

And then as you move to the Northwest, everything basically from the southwestern edge of our acreage out to where the Clemens well is, at 2,100 BOE a day does, in our opinion, appear to be highly prospective and for the most part derisked.

Just a few quick ones, hopefully. The latest crew you've added is from a different service provider than you've typically used in the basin.

Any, I guess, comfort you have with the results that, that crew has provided relative to legacy results in the basin?

Sure, the crew we've added halftime is a Baker Hughes crew, or what used to be BJ. And they’re guys we've used off and on basically since we got started in the Bakken up there.

So we have good success with those guys. It just make sense now we're running a lot of Baker equipment out there, we might as well be using a Baker frac crew and see if we can’t get some synergy for this whole project moving forward.

But they've performed well.

And any chance that, that crew gets brought on full-time?

That is our very distinct goal. That's what we're working for right now.

If you’ll allow me. Just to comment about our relationships with the service companies.

In general, I would say that what Whiting tries to do and what we've tried to do for over 30 years is pay our bills on time, have good long-term relationships with these people so that when we call on them and tell them that we need them, they show up with the number of crews that we ask for. And if they're short of equipment or people, or I'm going to say supplies, parts, chemicals or repairs, they provide that.

They enhance their capability in the area. And I would say that Halliburton has done that in really a remarkable manner for us all across our Bakken and Three Forks hydrocarbon system.

And now, Baker's doing the same thing. Baker's been very helpful for us on the sliding sleeves and now they've moved, helped with a greater number of frac crews and a greater number of supplies.

So we think that they're reacting to our request as they should, as they have in the past. And to be honest, that's why I think we have these good long-term relationships.

That's why we didn't see more than around a 10% to 15% increase when we renegotiated for up to 2 years with them here. So I'm very pleased with those relationships and we intend to continue to live up to our side of the bargain.

And I don't know if I missed it in all the discussion. Just -- did you make a comment on what your EURs, payout ratios, any other economic assumptions are for your Hidden Bench area?

You can go back and look at that decline curve again on the 32-4 well. That's exactly what we think on average the Three Forks is going to do for us but I didn’t mention the Bakken.

I would say the average will be more like 400,000 BOEs.

Okay, I’ll take a look at that. And then just one more on Lewis & Clark just for clarification.

The Clemens well, I think the second best well you've drilled in the play. There was some earlier commentary for, I guess, some questions around any of the wells -- or maybe not any of the wells, but some of the wells that were going to be drilled in and around the old Bicentennial Field that perhaps there would be some impact from development of the upper Bakken.

That well again is one of the best wells you've drilled. Any, I guess, clarification on what your expectations are up in that portion of the play and how future wells may or may not be impacted by that legacy development?

Let me take a crack at that. The old Bicentennial field, it's important to recognize, really has a different stratographic objective than the stuff that we're doing right now.

Those were shale-only wells. They were drilled in the shale back in the day when that field was developed.

The feeling was that that's where the hydrocarbons were. What we've now recognized is the shale has great fractures but in terms of the bulk volume of that shale in the oil in place in that shale was relatively low.

So what we're doing is we're targeting a separate zone below the shale. And our belief is, and I think we’ve borne this out in most of the areas that we've drilled in Lewis & Clark, they intersect with that old Bicentennial field is that the ductility or the plastic nature of that shale is such that when the overpressure was relieved off of the fractures in the shale, it closed up.

So those wells did not do a very good job of depleting the oil in the underlying zone that we're drilling in, which is this Pronghorn sand. It's now called the Pronghorn sand.

It used to be called the Sanish sand. So we have seen where we get too close to one of those old wells, we've seen some depletion.

But we've very definitely been able to quantify the area around some of those old wells that we need to stay away from and so we've long since figured that problem out. And so the wells that we’re drilling now really don't have that issue.

A quick question for you, and maybe you've kind of answered in a bit of a different way already. But in your release, you mentioned you're going to step up your activity in Stark and Billings portions of Lewis & Clark.

Could you mention your thinking on what you're going to do this year with your portion of Lewis & Clark that's in Golden Valley? Or have you kind of answered that in a bit of a different way already?

Well, the Golden Valley stuff, by and large, is really our big item project. So we've got 2 things going on over there.

One is a Red River play and the other one is a somewhat riskier Scallion play. And what we had done out there originally before we got started drilling is to shuttle logs 3D [ph] out there in Golden Valley.

And so we've identified a number of Red River prospects. And a few years ago, we had a very active Red River program going further to the north that we were 11 out of 13 wells that we drilled and identified porosity in the Red River.

So we took what we knew from McKenzie and Williams County and brought it down to Golden Valley County. And our first well roll out there, which is this Maus well, it looks like it's going to be a very good well.

And we've seen a number of different Red River bumps that are very analogous to that Maus well and we’ve got a rig moving on location to drill the second one right now. There's 2 more that we have waiting to follow up on it.

So that's a conventional play. You don't get the high IPs with those because they're vertical wells.

They're a lot less expensive. They don't have the hyperbolic decline either.

So we're pretty happy with what's happening there. In addition to that, we have a riskier play.

That's the Scallion play that is also developed out there at Big Island. We have one well that shows up on our slide on Page 9.

You can see the red horizontal well in there that we're going to be drilling after this next Red River well. So it will be sometime around October that'll test the Scallion in there.

And for me, I'd say that I'm really excited about the potential there. We see a lot of geologic prospectivity, but if we're successful -- and it's hard to say what the risk is on that right now -- we have a tremendous amount of acreage out there to follow up on that horizontal test.

So a little more risk but potentially a home run for us if we're successful there because of the acreage.

And just a quick -- another quick question. Given your average 24, 25 or so well backlog that you mentioned before, could you consider adding a third dedicated frac crew or does that pace just favor what you're doing now currently to that just not work out so well if you were to do that?

No, we are looking to add a third dedicated frac crew and we probably might even entertain getting another one part time above that just to make sure we can do some of the things we want to do out there.

Just have a quick clarification on the Niobrara wells. I just wanted to know, was there a difference in natural fracturing present within the reservoir between Wild Horse and on the other 3 wells that you drilled?

The amount of natural fracturing probably is no different. What's different is our azimuth.

And so what we had done on the first 3 wells there is drill a long and natural fracture. If you do that, you're lucky if you're exposed to one good fracture.

If you go perpendicular to the direction of the open fractures, then you expose yourself to a lot more. Our problem was, originally, we didn't know what the direction of the open fractures was.

We assumed, as Jim Volker mentioned earlier and Jim Brown, that the direction was northeast, which is consistent with the orientation of the Colorado mineral belt, kind of lining up with the Wattenberg field in there. But what we found out as we get out away from Wattenberg, towards the east side of the play, stress orientation changes and now the direction of the open fractures is more sort of east-west or east-northeast.

And so when we changed the orientation on that Wild Horse well, we ended up getting dramatically better results. And so, it takes a while to figure that out.

The same happened to us when we were at Sanish field originally. But we think we got that figured out now and so that, combined with changing the lateral length a little bit, we think we've derisked a significant amount of our acreage out there.

That’s very helpful. And then just quickly, so your 30-day rate was 450 barrels a day versus the 1,300 barrel-a-day IP.

Is there any worry that when you draw too hard on these wells, you actually damage the natural fracturing and they might close, and you have to go back and re-complete? Or is this just the typical IP and decline rate that you expect?

We're expecting that it's just the typical IP and decline that we have seen.

Just briefly, trying to close the gap between another big Bakken operator, reported completed well costs about 50% higher than what you guys have indicated at Hidden Bench and just trying to close the gap here, I know you've got the DWOP program but can you make it a little more tangible, what does that $6.5 million completed well costs entail for frac stages and could you describe are you using sand or ceramic prop-in and I understand the plug and perf is more expensive than sliding sleeve but anything you could do to help me out to understand to your credit how you're keeping the well costs down?

I've mentioned it before, I can't give just the best compliments to our drilling group for what they've been able to accomplish. Beyond that, we are using all sliding sleeve, we’re doing 30-stage sliding sleeve jobs so our frac job goes in 24 hours plus or minus so we get that down fairly quickly.

We are white sand guys. We will pump white sand if we can get it.

There have been the occasional frac job here recently where we’ve had to pump ceramic because that’s the only prop-ins that was available. So I think the combination of our operations group that we’ve got in North Dakota to kind of herd this thing from start to finish, the work our drilling group does and then the completion efficiency we've got up there, I think those all contribute to our reduced well cost.

Okay and then just lastly on the Niobrara again, in your discussions with other operators, does the industry feel that this will migrate or evolve from being more of a natural fracture play to one where you can actually access the oil trapped in the floor spaces?

In short, yes.

Just one quick one, I don’t know if you have this handy but was just wondering if you --if you don't, I’ll follow up after the call -- but wonder if you have the names of those wells that you would consider edge wells on the southern end of Lewis & Clark.

We can tell you what the names of those wells are. Look in IHS or other places to follow up on that.

Just give me a second here and I’ll pull those up. So essentially, again we're talking about the southern tier wells and I'll just make a general comment here, while we were talking I went through and I averaged all of the wells along that southern tier, and they really pulled down the average of the rest of our wells but we're looking at something slightly less than 500 barrels per day, they're actually a little closer to 300 barrels in terms of the average.

And then if you look at the specific wells that contributed to that – here we are, okay, so there’s the Bin-Stock [ph], the Arthaud well, A-R-T-H-A-U-D, the Pollock well, and the Roland [ph] wells are the ones that were on the low end, that southern tier.

Thank you, Angela. I'd like to reference Slide 37 now, which shows several key points.

First that we've grown our proved reserves 325% from 72 million barrels back in our IPO in November 2003, to 305 million barrels at the end of 2010. Second, we've grown our production 277% in the same period.

Third, we have a drilling inventory and this is a new number for you of 4,600 gross operated wells across our reserve and resource space and we've broken it out for you here on this slide between the resource space and the PPP reserves. And of course, we see significant organic growth potential from our drilling programs.

In addition, we expect production and reserve growth a very moderate risk at our North Ward Estes field. Further, the new exploration projects that we spoke about today offer, we believe, exceptional upside.

We’ve grown through the drill bit and our debt-to-cap puts us in an excellent position to execute on our plans. I'd like to thank all of our Whiting employees, especially our Bakken and EUR teams for doing a remarkable job during the severe weather conditions in Q1 and Q2.

And I also express my thanks to our directors for their continued contribution to Whiting's success. Our 2 recent discoveries at Redtail and Hidden Bench, our new wells at Sanish and Lewis & Clark and our encouraging results at Big Tex, I believe demonstrate our strategy and ability to develop new oil plays for future multi-rig development while successfully executing on our existing large-scale resource plays.

And frankly, if you don't see that, then you just don't get it. We hold more 680,000 net acres, in the Bakken-Three Forks hydrocarbon system that we believe will provide increased production and reserve additions.

With our planned development in these new areas and our existing core properties, we expect a strong second half in 2011. I'll now mention several upcoming events in which Whiting will participate where we hope to meet with you personally.

I'll be presenting on unconventional oil plays at the COGA Conference next week at the Colorado Convention Center. The presentation begins at 1 p.m.

on Wednesday, August 3. Jim Brown is scheduled to host one-on-ones at the Tuohy Brothers’ E&P Midstream Conference on Wednesday – or on Tuesday, August 9, and that conference being held at the 3 West Club, Rockefeller Center in New York City.

We'll present at EnerCom, as we always do. That's scheduled for the Westin Tabor Center in Denver at 1:30 p.m.

on August 15. And we're going to present at Barclays Capital CEO Conference at the Sheraton New York Hotel & Towers.

That conference is being held on Tuesday and Wednesday, September 6 and 7. We plan to also present, as we do every year, at OGIS West at The Palace Hotel in San Francisco.

That conference is being held September 26 through 28. We look forward to seeing you at these events.

In closing, I want to thank all of you on this call for your new or continuing interest in Whiting Petroleum Corporation. All the best and we look forward to seeing and speaking with you soon.