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Whiting Petroleum (NYSE:WLL)

Q3 2011 Earnings Call

November 03, 2011 11:00 am ET

Executives

David M. Seery - Vice President of Land

James J. Volker - Chairman, Chief Executive Officer and Director of Whiting Oil & Gas Corporation

James T. Brown - President and Chief Operating Officer

Michael J. Stevens - Chief Financial Officer and Vice President

Eric Hagen - Vice President of Investor Relations

J. Douglas Lang - Vice President of Reservoir, Engineering & Acquisitions

Analysts

Pearce W. Hammond - Simmons & Company International, Research Division

Jack N. Aydin - KeyBanc Capital Markets Inc., Research Division

Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division

John Freeman - Raymond James & Associates, Inc., Research Division

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

Jason A. Wangler - SunTrust Robinson Humphrey, Inc., Research Division

Gil Yang - BofA Merrill Lynch, Research Division

Unknown Analyst -

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Operator

Good day, ladies and gentlemen, and welcome to Q3 2011 Whiting Petroleum Corp. Earnings Conference Call. My name is Sandra, and I'm your operator today. [Operator Instructions] As a reminder, this call is being recorded for replay purposes. I'd now like to hand the call over to Mr. Eric Hagen, Vice President of Investor Relations. Please go ahead.

Eric Hagen

Thanks, Sandra. Good morning, and welcome to Whiting Petroleum Corporation's Third 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; Chuck LaCouture, VP of Marketing; and Dave Seery, Vice President of Land.

During this call, we'll discuss our results for the third 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 third quarter 2011 earnings release can be found on our website at www.whiting.com. To access the call and the webcast, please click on the Investor Relations box on the menu, and then click on the Webcasts link.

Please note the forward-looking statements, non-GAAP measures, reserve and resource information and de-risked definition on Slide 1. Please take note that our Form 10-Q for the 3 months ended September 30, 2011, is expected to be filed today.

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.

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

James J. Volker

Thanks, Eric, and great job. And a special welcome to Eric as he joined us for his first earnings call as our Vice President of Investor Relations. We had a record third quarter. In terms of production, our 70,675 BOE per day average was up 10% over the second quarter, total revenue was $487.6 million and discretionary cash flow totaled a record $316.5 million.

Slide 2 summarizes key statistics for the company. On Slide 3, you can see a breakdown of our production by region. You'll note that more than 80% of our total production is coming from our core Rocky Mountain and Permian regions.

Slide 4 shows our 2011 capital budget, which is $1.7 billion. Slide 5 provides a detailed breakdown of our budget: the $100 million recent increase primarily reflects increased non-operated drilling activity. As detailed on Page 8 of our press release, we are adding 5 net non-operated wells at a cost of approximately $8 million per well for these non-operated wells and 4 net operated wells at a cost of about $5 million per well. These wells will primarily impact our 2012 production outlook.

At our Sanish field, one of our 3 frac crews used ceramic proppant in the third quarter due to a temporary sand shortage that increased our cost by about $850,000 per well. This issue has been addressed and we're currently drilling wells at Sanish for approximately $6 million per well. In addition to this, we added $17 million to our land budget and $5 million to our facilities budget.

Slide 6 shows that we hold 683,000 net acres in the Bakken/Three Forks Hydrocarbon System. This acreage position is expected to provide increased production and reserve additions for many years. Slide 6 also shows the reference points 1 through 10 on our cross-section on the next slide.

Slide 7 is our Williston basin prospect area cross-section. We've broken our Lewis & Clark and Pronghorn into separate areas. Numbers 5 through 9 represent what we refer to as Lewis & Clark prospect area. Number 10 is our Pronghorn area. This slide also shows the initial production rates for every well that we've completed to date at Lewis & Clark and Pronghorn. Our average IP at Lewis & Clark is 922 BOE per day from 17 completed wells. From 16 wells, our average IP at Pronghorn is 1,480 BOE per day, excluding the 5 delineation wells drilled below the southern boundary of our Pronghorn prospect. Combined, our IPs at Lewis & Clark and Pronghorn averaged 1,192 BOEs per day from 33 wells. Across our non-Sanish Williston Basin prospect areas, the average IP is 1,545 BOEs per day.

On Slide 8, our 2 typical production profiles for non-Sanish field, Bakken or Pronghorn sand/Three Forks wells. Note the NDIC has recently renamed the Sanish Sand the Pronghorn Sand. This is the zone we drill in across Lewis & Clark and Pronghorn. The production profile EURs range from 600,000 BOEs to 350,000 BOEs, which we believe reflects the range of our Lewis & Clark, Pronghorn, Hidden Bench, Tarpon and Cassandra Prospect wells. Average well cost is estimated at $7 million. As you can see, these wells have excellent economics at current oil prices.

Moving to Slide 9, you can see we continue to generate great results at Sanish field. We've highlighted several new wells for you on this map. The IPs of these wells averaged 2,068 BOE per day.

On Slide 10, we've mapped how we are planning the ultimate development of Sanish field, including non-operated wells, we estimate that 245 wells remained to be drilled in the Sanish field. At 100 wells per year, that's approximately 2.5 years of drilling inventory remaining.

Slide 11 shows that Whiting continues to lead the pack in terms of cumulative production during the first 6 months from all Bakken wells drilled in North Dakota. Our average is 13,000 BOE or 15% higher than the second ranked Bakken operator and 50,000 BOE per day better than the average of the next 20 operators.

Please note on Slide 12 that the expansion of the Enbridge and Bridger/Belle Fourche pipelines and the Lario rail system also known as Bakken Oil Express, brings total takeaway capacity from the Williston Basin to 580,000 barrels per day, which includes 155,000 barrels of increased capacity added to date in 2011.

Slide 13 shows the results of our Sanish, Lewis & Clark/Pronghorn and Hidden Bench prospect areas. For example, at Lewis & Clark, results remain strong as our 90-day average is up from 356 BOEs to 387 BOEs, and the newly added Hidden Bench wells are on par with our Sanish Bakken wells.

Slide 14 shows our estimate of the de-risked acreage across our prospect areas in the Williston Basin. We now believe based on the drilling results and geological mapping that 100% of Hidden Bench, Cassandra and Tarpon are de-risked.

Slide 15 illustrates that we estimate 46% of our Lewis & Clark area is de-risked to date. On the map, you'll see the first 30-day production results from the prospect area wells and key Bakken well geological control points.

Slide 16 shows that we estimate that 59% of Pronghorn has been de-risked to date. Combined, we estimate that 52% of Lewis & Clark and Pronghorn is de-risked to date. This equates with 389 de-risked locations out of a total of 733 potential locations. Again, we estimate that EURs from these wells are in the range of 350,000 to 600,000 BOEs, with an average $7 million well cost currently.

Slide 17 shows Hidden Bench. We're pleased to announce that after we prepared these slides, we completed our Schilke 34-32H well, where we have a 98.4% working interest. The well had a 24-hour IP of 2,680 BOE per day. It's located in the unit just east of the #635 on that map. Based on our drilling to date, we estimate that 100% of our 59,700 gross acres and 29,300 net acres are now de-risked.

In addition to Hidden Bench, we believe that 100% of our Tarpon prospect is de-risked as shown on Slide 18. As reported yesterday, we set a new initial production record for all Bakken wells drilled in the Williston Basin, with the completion of our Tarpon Federal 21-4H well. This well was completed in the Middle Bakken after a 30-stage sliding sleeve frac job flowing 7,009 BOE per day on October 17, 2011.

Moving to Slide 19 and completing our overview of new areas, we think we have de-risked all of Cassandra, where we hold 30,700 gross and 14,500 net acres.

In summary, based on results at Lewis & Clark, Pronghorn, Hidden Bench, Tarpon and Cassandra, we believe we have de-risked a total of approximately 460 future drilling locations, which is about 4.5 years of drilling using 9 rigs. With further successful drilling at Lewis & Clark and Pronghorn, we estimate we have the potential to add another 200 to 400 locations.

Now to discuss our exploration results outside of the Bakken and our EUR projects, I'd like to introduce my colleague, Jim Brown, Whiting's President and Chief Operating Officer.

James T. Brown

Thanks, Jim. First, let's start on Slide #20 with our Big Tex prospect. Whiting has accumulated about 122,000 gross and 90,000 net acres in Big Tex. We currently have 2 rigs drilling in the area. We've drilled 3 horizontal wells to date and completed one of them, the Bissett 9701, which we previously announced. On July 25, it tested it at 788 BOE per day and is currently producing 243 BOE per day. We have completed 2 other horizontal wells that are still flowing back load.

We are encouraged by our horizontal Bone Spring well results and believe we have 8 offsets to our Bissett and Trainer wells -- Trainer Trust wells. Given we have multiple objectives to test, we are still in the early stages of drilling.

Slide 21 shows our Redtail prospect in the Weld County, Colorado portion of the DJ Basin. We have acquired 104,000 gross and 76,000 net acres in the Redtail prospect. Our discovery well, the Wild Horse 16-13H, is currently producing 328 BOE per day. Our most recent horizontal well, the Two Mile Creek 22-13H, was completed in the Niobrara flowing 216 BOE per day. The Two Mile well was drilled about 17 miles northeast of the Wild Horse well. Based on the results of these wells, we added 4 horizontal wells to our 2011 drilling program at Redtail.

Two wells will be drilled on 960-acre spacing units for approximately $5.5 million each, and 2 wells will be drilled on 640-acre spacing units for approximately $4 million each. I would just want to mention that our focus out in the DJ Basin is to reduce drilling costs out here. A current well that we are drilling, we've just reached TD on our Runway well and our cost is just over $1.2 million. We expect to be able to complete this well for under the $4 million target we mentioned above.

Now I'd like to turn to our 2 EUR projects, the Postle and North Ward Estes field. Combined, they represent 42% of Whiting's total proved reserves and 23% of our production. On Slide 23, you can see the production forecast from the proved, probable reserves at Postle field. Postle is currently producing 8,200 BOE per day, which is 3% higher than its third quarter average daily rate of 7,980 BOE per day.

On Slide 24, you can see the production forecast from the proved and probable reserves at North Ward Estes. We're very pleased with the recent performance of the field, which is currently producing about 8,900 BOE per day or 5% higher than its third quarter average daily rate of 8,440 BOE per day. There are multiple reasons. The primary reason for the recent ramp up in production is that we are back to our full contracted delivery volumes of 130 million cubic feet of CO2 per day. Also Phases 2 and 3 of the EUR project are on good uptrends.

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. This should accelerate the conversion of 130 million BOE of probable and possible reserves to proved reserves.

The curve on Slide 26 shows the proved, probable and possible recovery forecast for North Ward Estes. This curve shows that the proved reserve recovery moved up to just over 6% from the original 5.5%. With continuing good performance, we should be able to start moving probable reserve volumes into proved at year end 2011.

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

Michael J. Stevens

Thanks, Jim. On Slide 27, we show third quarter 2011 adjusted net income available to common shareholders of $112.9 million or $0.96 per basic share and $0.95 per diluted share. These compare to third quarter 2010 adjusted net income available to common shareholders of $71.6 million or $0.70 per basic share and $0.65 per diluted share. A reconciliation of adjusted net income available to common shareholders versus net income available to common shareholders is on Slide #35.

Discretionary cash flow in the third quarter of 2011 totaled a record $316.5 million, representing an increase of 38% over the $229.5 million reported for the same period in 2010. The increase in discretionary cash flow in the third quarter of 2011 versus the comparable 2010 period was primarily the result of a 22% increase in the company's realized oil price and a 7% increase in Whiting's production. A reconciliation of net cash provided by operating activities to discretionary cash flow is on Slide #36.

We're within guidance for all items except LOE, which came in at $11.94 per BOE. This was slightly above the high end of the guidance range of $11.50 to $11.80 per BOE, as we experience greater-than-expected workover activity at North Ward Estes, as we move to accelerate the conversion of 130 million BOEs of P2 and P3 reserves. Our fourth quarter guidance for LOE to come in at $11.40 to $11.70 per BOE.

On Slide #28, you will see that we posted a record quarterly EBITDA margin in the third quarter of 69% of our average blended price of $71.80 per BOE. At current prices, we expect our EBITDA margin to improve over 70% in the fourth quarter of 2011.

On Slide #29, you can see we continue to maintain a strong balance sheet with total long-term debt of $1.2 billion and a total debt-to-total capitalization ratio of 28.9%. On October 12, 2011, we entered into an amendment with our banking syndicate that increase the borrowing base under our credit agreement from $1.1 billion to $1.5 billion until May 1, 2012, the next redetermination date of the credit agreement. No other terms of the credit agreement were changed.

Slide #30 shows that our 2 senior sub notes are trading well above par. It also shows that we're well within all the covenants in our credit agreement and our bond indentures.

Our guidance for the fourth quarter and full year 2011 is on Slide #31. We expect another nice production increase in the fourth quarter as we complete additional wells and place more wells on production.

On Slide #32, we show our current hedge position. We'd like to be around 50% hedged on oil production using costless collars. This allows us a reliable stream of cash flow, while maintaining exposure to potential oil price upswings.

For natural gas on Slide #33, we prefer to enter in the flat fixed-price gas contracts. This offers us a predictable cash flow stream on over 30% of our current gas production. Since these contracts are well ahead prices, it takes the risk of unfavorable differential movements out of the equation.

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

James J. Volker

Thanks, Mike. Before we go to Q&A, I'd like to provide our initial thoughts on the 2012 outlook. Our plan is to release our official guidance shortly after our next board meeting, which is scheduled for December 14. On the production side, note that holding our fourth quarter rate flat through 2012 would equate to a double-digit growth. We're working through an inventory of about 66 wells in the Sanish field requiring service rig work. About 1/3 of those wells are to be placed on pump, about 1/3 are a waiting normal rod repairs and other maintenance and about 1/3 are offline, as a precautionary measure we take as we frac adjacent wells. Bringing these wells back online should impact production late this year and early in 2012. Further, by July 2012, we expect to be drilling with 27 rigs versus the 22 to 23 we averaged in 2011. So we're on track to deliver a good year of growth in 2012, and yet, stay, we believe, right around our discretionary cash flow.

Operator, please open the conference call for questions.

Question-and-Answer Session

Operator

[Operator Instructions] And your first question comes from the line of John Freeman and he's from Raymond James.

John Freeman - Raymond James & Associates, Inc., Research Division

First question I had just on a lot of the discussion on how much of Lewis & Clark/Pronghorn has been de-risked. Can you just sort of elaborate a little bit more sort of the methodology that goes into de-risking the acreage?

James J. Volker

Well, obviously, we're looking at 30-day rates as we've shown you there on that map. That's exactly what we do here. We also, of course, are looking at the control points so that we can see in comparison to the thickness of the Pronghorn Sand in wells that we have drilled and completed successfully. The aerial extent of that sand and then basically, we're looking for areas that are in terms of ROIs, the worse than 2:1 on our money and obviously better all the way the higher end of the range up to around 600,000 BOEs. So what you see on our Slide #8 is essentially the range of results that we expect across Lewis & Clark and Pronghorn and the other prospect areas that we've documented for you here this morning.

John Freeman - Raymond James & Associates, Inc., Research Division

And then so is this the increased confidence, does that has something to do with -- it looks like you took up the low end of your EUR range on Lewis & Clark/Pronghorn. Last quarter, it was 300,000, it was the bottom end, and now it's 350,000?

James J. Volker

Correct. Yes, confidence factor is up. And I guess, I'll jump ahead and I'll try to answer what I think is an obvious question. Tell me if you don't like it, John and then I'll -- but I think as we look across Lewis & Clark and Pronghorn, we would say that at Lewis & Clark, we definitely see a range of results there and we would have to say that the majority would be toward the lower to the middle end. At Pronghorn, again, we see a range, but we would say that we think the average is going to be about right in the middle between that 350,000 and 600,000 or about 475,000 BOEs. Talking briefly about Cassandra, we would say, again, about in the middle of the range. As to Tarpon, it's obvious there that the first well is at the high end of the range and perhaps even above that. But we're going to stick with our higher end of the range there for now until we get a chance to drill a few more wells up there. And at Hidden Bench, I would say that more of the wells would be toward the upper end of the range. So I hope that's helpful.

John Freeman - Raymond James & Associates, Inc., Research Division

That's very helpful. Just last question for me is in the Slide 13 where you showed the average of first 90 days of Lewis & Clark/Pronghorn. Of those 21 wells that were used in that, how many of those were Pronghorn?

James J. Volker

They're all Pronghorn Sand wells. They're all in that range.

John Freeman - Raymond James & Associates, Inc., Research Division

I guess what I'm saying is how you break out between the Pronghorn acreage and Lewis & Clark acreage?

James J. Volker

13.

John Freeman - Raymond James & Associates, Inc., Research Division

13 of the 21?

James J. Volker

Right.

Operator

Your next question comes from Mike Scialla from Stifel, Nicolaus.

Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division

I have a follow-up on John's question on looking at Slide 14, the 168,000 net acres that you're calling Pronghorn. It looks like -- does that stretch up to the Demores area?

James J. Volker

Just south of the Demores area. If you look at that map, you can see that the greater Lewis & Clark area is broken into 2 parts by those black bounty boxes. So Pronghorn refers to the southern area, Lewis & Clark on this map refers to the northern area.

Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division

Okay, got it. And I think you've got -- maybe you said 13, Jim, I thought there may be 16 wells that are -- in what you've originally defined as the Pronghorn area. And how much acreage did those wells surround at this point?

James J. Volker

Those wells are really in the red dash line, which is what we believe we have de-risked to date on that map. And so those 13 are exclusively within that red dash line. So we have a lot more control on the West side of that, a little bit less control on the east side. But we have now one very good well on the east side and our mapping, as Jim mentioned, we -- it's a combination of the results today, as well as the pre-existing control points that give us confidence in this de-risked area.

Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division

Okay. And the 7 rigs that you have operating in that trend, can you say by subarea where you have those working right now?

James T. Brown

Virtually all Pronghorn right now. I think 7 are in Pronghorn and 2 are in Lewis & Clark.

James J. Volker

That's correct. 5 and 2, Mike.

Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division

Okay. And you mentioned in your release that you plan on developing the Pronghorn area with 3 wells per drilling unit and, I guess, the northern acreage is what you call Lewis & Clark now that was 2 wells per unit. I would have thought that might be the reverse given that it looks like maybe the rock quality is better in the Pronghorn area. Can you talk at all about that?

James J. Volker

I'd say that the reason we're not higher in Lewis & Clark is that there is a pre-existing field out there, it's the Bicentennial Field. We've discussed it many times in the past. And so there are a number of shale wells, Bakken shale wells that have been drilled in there. And so if you average it all out, it ends up being about 2 wells for 1,280 there. Otherwise, our average will be higher at Lewis & Clark. At Pronghorn, there is -- both the Pronghorn Sand, which is our primarily drilling target, as well as Three Forks underneath that. And when we go through, when you do the volumetrics, we look at our frac radius, we feel like 3 is the appropriate number there.

Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division

So Lewis & Clark area, I guess, that implies you think the Bicentennial wells have essentially drained some of the Three Forks as well?

James J. Volker

Yes. We've stated that many times in the past. We're having -- we have had to be a little bit selective in where we drill in Lewis & Clark because of those wells. There's only a partial overlap. As you go further north, there are more Bicentennial Wells and the southern part of Lewis & Clark, there are none. So you really have to average it out. It ends up being about 2 wells for 1,280.

Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division

Okay. And then on the well costs, you're at $7 million now. I think you'd been talking about a $6.5 million number previously. Is the difference anything to do in terms of the completion design or is that strictly inflation?

James J. Volker

It's not just inflation. There's more science that we're doing with the current wells and we hope to bring that cost down over time. So essentially, what's happened to us is 2 things. Sort of, one, unrelated to your question, which is that why we're well cost higher. The answer is we had to rely on some ceramic proppant for a while. I think we've addressed that by having that particular frac crew set aside for a while until they can come back with sand. And then second, with respect to what we're doing right now, we're doing some additional coring, some additional scientific work logging while we're drilling, so that our costs are up there around $7 million right now. But we -- that's why I'm going to say emphasize the word, currently, during my portion of our little presentation, so that I hope you'll get the idea that we're going to be working to try to bring those costs down.

Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division

I've got some more. I'll jump back in the queue. But one last one. The Tarpon well that came in at such a higher rate. Anything different you did there, or is it just a matter of thickness, or did you preset in a larger choke, or why was that rate so high?

James J. Volker

It's high because the rock is great there. Mother Nature helped us a bit. It's fairly well fractured in that area and consequently helped the rate.

Operator

Your next question comes from Gil Yang and he's from Bank of America Merrill Lynch.

Gil Yang - BofA Merrill Lynch, Research Division

Just following up on Mike's question about Tarpon. The Tarpon well, do you have any data on decline yet that -- do you know how it's declining? Is it like the Three Forks wells or is it more slower decline like the Bakken wells up in Sanish?

James J. Volker

This is a recent well for us. So we're just putting it on production right now. So the rate that we mention in there is a full 24-hour rate flow test. We had dual separators out there. We knew it was going to be a good well. But we have not got it on production yet. We're just doing that right now.

Gil Yang - BofA Merrill Lynch, Research Division

Moving to Redtail, pretty dramatically different results between Wild Horse and Two Mile Creek. Can you comment on what the difference is in the -- sort of postmortem on those 2 wells in terms of what the differences are?

James J. Volker

Well, we did get a higher rate. A lot of that had to do with the fact that the rock is a little better, we think, at the Wild Horse well, then 17 miles away at the Two Mile well. However, try to be succinct with you here. We think the target EUR here is around 200,000 to 250,000 BOEs per well. So even at the lower end of that range and at today's oil prices, that's about $10 million of future net revenue and at $4 million well cost, that's about 2.5:1 on your money and a great IRR and a quick payout. So we like the area. We don't like it as well as the Bakken, but we like it. We think the acreage position that we've taken, they're essentially within the Colorado Mineral Belt as the rock clipped to the right degree, so that we found one of the sweeter spots within the Niobrara. And for that reason, we've elected to drill another 4 wells there and keep going.

Gil Yang - BofA Merrill Lynch, Research Division

But are those 4 wells closer to Wild Horse than they are to Two Mile Creek?

James J. Volker

We're going to be doing some development offsets to the Wild Horse. We're trying to work our way in the development mode here, so that's a primary thing that we're doing. The other thing is we're testing out longer laterals. We're trying to gain some economy of scale. As Jim Brown mentioned, we've got our drilling costs down, we think, on this current well down below $4 million. We think we can maybe multiply the lateral length by 1.5 on these 960-acre wells and still keep the drilling cost below $5.5. million. So we're really doing 2 things, develop wells there around Wild Horse and testing these longer laterals, all trying to gear up and developing our acreage there.

Gil Yang - BofA Merrill Lynch, Research Division

Okay. Turning to sort of Lewis & Clark -- the broader Lewis & Clark area, you made some nice comments about de-risking many of your new plays. Can I turn that comment around or that metric around and ask in all your work, I would say for the areas you have de-risked 100% that's positive, but can you talk about how much of your acreage you have sort of condemned, if you will. It's a very strong word, but just sort of condemned based on your drilling. So of the acreage that's not been de-risked, how much has been de-risked the wrong way, if you will?

James J. Volker

The only thing that we've condemned so far is the area south of what we call the border of southern end of Pronghorn down there, where we drilled several of those wells that essentially were below the edge of the reservoir and came up with 300 BOE IPs rather than the 1,000 BOE IPs.

Gil Yang - BofA Merrill Lynch, Research Division

Okay. So those 4 wells in row in south are -- you're not going look at going forward?

James J. Volker

Right. That's on Slide 16. You see them below the red line currently. Now that doesn't mean that as we move to the Southeast, that more of that won't be de-risked. As we continue to drill out there, our drilling results I'm going to say on the northern part of that red line will tell us whether, as we move to the Southeast, more of that will become de-risked.

Gil Yang - BofA Merrill Lynch, Research Division

Okay. So the red line may move south in -- the southeastern part but it probably not going to move south on the western part in that picture?

James J. Volker

Correct.

James T. Brown

I'd like to add just one other comment there. We have long-term leases in Pronghorn. And during the past 2 to 3 years, the average rate across the basin continues to rise while we're holding our drilling costs at a relatively constant value. So those are 4- and 5-year leases out there. These are on the Southeast side is close but not quite what we would consider 2::1 right now. So as we go to more frac stages and improve performance, we think a lot of this is going to end up being de-risked.

Gil Yang - BofA Merrill Lynch, Research Division

Okay, great. And then can I just ask a question about the frac issues -- this frac sand issue. It sounds like you're just going to of sort of not used that crew until they can find sands and frac the wells at a more reasonable cost. I guess my question is why would [indiscernible] given the frac these wells at a $800,000, $900,000 incremental cost in the quarter anyway? Why weren't they immediately sidelined?

James J. Volker

Because the rate's still great, the reserves are still great even there's an $850,000 higher cost per well. And we had a large inventory as we talked about, roughly 50 wells. We worked that down to less than 25 wells now. And so we did that temporarily. That was one of the 3 crews we used during that period of time to work on that inventory. But economics per well are still excellent.

Gil Yang - BofA Merrill Lynch, Research Division

Sure, I understand that. But if -- and the sideline that couldn't slow down at least temporarily your development going forward or that's an extra spot crew?

James J. Volker

Well, basically it helped us move through the inventory and we've basically finished working off the extra inventory that we had, so we don't need that well or that extra crew right now. However, when operations slow down up there in potentially December, when it's harder to frac in December, we may bring that crew back. And by that time, we believe they will have a sand supply that is sufficient to meet our needs.

Operator

Your next question comes from David Tameron from Wells Fargo.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Lewis & Clark, and I think you've talked about this before, is -- when I think about the decline curve, Lewis & Clark versus Sanish partial, can you talk about does it flatten out a little quicker, or what's the right way to think about that?

J. Douglas Lang

This is Doug Lang. We think it will. The best evidence [indiscernible] our Federal 32-4H, that's the well with the most history. Of course, you can appreciate it in a new area. It takes 3 years really before you know long term, but there is an indication of that. We may not have the eye-popping IPs but we seem to have a real steadier, shallower decline at least on early on. So that's our expectation. But we'll have to wait and see until we get more data.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

All right. And I assume you've incorporate that, that into your EURs, that assumption?

J. Douglas Lang

You bet. Just from a reservoir engineering standpoint, I mean, we talked about the 30-, 69-day IP rates and so forth, that we do a lot of work behind the scenes obviously, look at each of these prospect areas, what kind of rock we have, what kind of volumetrics we have to work with, what's the -- I'll take you for the fracs in that area, pressure data. There's a lot of tools that we use to try to be exactly we can in our EUR estimates. So it's -- I hope you appreciate that there's a lot more that goes into it. It's just looking at the early production decline.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Yes, I know. I'm really just more than just [indiscernible] on my spreadsheet I have in front of me. Let me see what else I have. Questions, Jim, you mentioned cash flow next year will approximate CapEx. Are you referring -- and obviously, I'm trying to get a number out of you, but are you referring to current strip or an $80 more of a budgeting number kind of how should we think about that?

James J. Volker

Burned [ph].

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Okay. And I assume with more rigs running -- you have more rigs run next year than this year?

James J. Volker

Right.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

So if we take this year as the proxy and then adjust from there, is that the right way to think about it?

James J. Volker

Yes.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Okay. Final question, I'm getting a lot of questions. I'm sure you are. Do your well costs are substantially lower than everybody else is?

James J. Volker

Yes.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

At 6 to 8, every other operator was part of this quarter's thrown out at 9 or 10 or some 11. Can you talk about, I mean, obviously, sand versus ceramic makes a difference, maybe sliding sleeve makes a difference. Can you just talk about why else your numbers are so much lower?

James J. Volker

Well you hit on 2 of the points. The third one is, I would say, that I'm taking the direct dial phone numbers of all of our drilling engineers who were responsible for these record costs, and I'm pulling the plug because I'm tired of having people call to try to hire them away. They're doing a great job for us. They've implemented, as we've talked about in the past, a drill wells on paper plan. And this is where, essentially, we maximize the efficiency of the drilling operation. And we have, in my opinion, the roughest, toughest, best, most efficient group of both, I'm going to say, younger and more older and more experienced drilling engineers working together on every well to maximize in 500-foot intervals the penetration rates that we get. To see that all supplies, parts, chemicals, repairs, everything is delivered to the rig in such a manner as to not slow down the drilling operation. So whether we're talking about bit type, mud weight, weight on the bit or the pre-planning work that goes into the particular rigs that we have working for us out there, all of that, I say, ends up with drilling costs currently in the range of around $7 million. And you can see that when you look at our budget, just take the net wells and divide it into the cost that we have there at Sanish. And keep in mind that, that costs is even slightly skewed by some of the non-operated wells, which as you point out, have higher costs associated with them. So I can't say enough about that. Those are the 3 main reasons.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

So it is really just your longevity or experience in the basin, maybe that's a better word. And your crews and efficiency, not necessarily something you're doing different as far as pads or anything different than any other operator?

James J. Volker

Well, I don't think -- I mean, first of all, there are other operators who are very experienced as well. But I think the techniques that we're using as we drill that well from spud to TD are having the efficiencies that result in lower cost per well. And whether everybody else spends as much time on the rig with the crew, helping them think through the issues that arise when you are drilling 10,000 feet deep, 10,000 feet horizontally, I don't think they have -- I don't think they've placed the emphasis on it that we do. That's not to say that they're not doing a good job, it's just that saying that it's resulting in somewhat lower costs for us and for other people. And that's one of the reasons in my opinion that when you see a package of non-operated interest come up and Whiting is the operator, it sells at a premium price here in the Williston Basin.

Operator

Your next question comes from Jack Aydin from KeyBanc Capital Markets.

Jack N. Aydin - KeyBanc Capital Markets Inc., Research Division

You mentioned that if you keep the flat -- fourth quarter production flat for the balance of 2011, you will have double digit. What kind of capital you need to do that? Two -- second part of the question, if you're going to -- then the extra capital, above that, what kind of growth could generate?

James J. Volker

Well, as the previous questions are asked and surmised, if we stay I'm going to say on that growth trend with the current strip, we will be right around our discretionary cash flow in 2012. So we won't have much, if any, excess of CapEx over discretionary cash flow in 2012. I realize other people are out there announcing their numbers are saying that they're going to outspend their discretionary cash flow by close to $500 million in order to get a bigger -- and they're going to have projecting higher percentage increases in production. But here at Whiting, what we're trying to do is grow reserve, grow production and essentially stay right around our discretionary cash flow and not have to either dilute by issuing more shares or existing shareholders or burden the company with much additional debt. So that's we consider to be the hat trick. That's what we're trying to do. And I believe that in 2012, we've got a good chance to do it assuming the prices stay like the forward curve for 2012 and then there's, I'm going to say, a continuation of our ability up there to deal with the normal issues that arise every winter in North Dakota.

Operator

Your next question comes from Biju Perincheril from with Jefferies.

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

Big Tex. I think you had some very good vertical test there early on. What are those wells in the same area? Is it recent horizontal wells? And judging from the results of the horizontal wells, is there any plan to maybe go back and test the verticals?

James T. Brown

Yes, Biju, this is Jim Brown. We still remain very committed to the horizontal wells out there, but we are going to test a vertical well. We're actually drilling the well right now farther west in our acreage position, and we're going to go give another -- we're actually going to drill 2, but we're going to give a vertical well another swing at the bat out there and see what we can do -- see if we can improve our recovery out there.

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

And with the verticals, were you sort of targeting the Bone Springs and the Brushy Canyon, or was that a different concept to your testing there?

James J. Volker

In the vertical wells, you can think about it as basically being what other people are doing out there to the west of our acreage position, which would be the Wolfcamp and the Bone Springs combined in vertical wells, so -- typically known as the Bones Spring play or the Wolfbone play.

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

Okay. And then looking at the CapEx for next year, when you say you could be close to your cash flow, are you baking in any sort of efficiency gains in bringing down your well cost, or is that assuming current well cost?

James J. Volker

We're assuming current well cost, Bij.

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

Okay. And in ballpark, if I'm running, what's a number that you think could be the CapEx on one rig for the full year in the Williston?

James J. Volker

Well, I'll answer it this way. We think it takes about 40 days out there -- 40 days from spud to completion. The drilling time is typically somewhere around 15 days but -- with rig move and everything. You're generally around a rig drilling one well a month from spud to complete.

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

Okay. And on the acreage side, is it fair to say you'll have lower spending next year or will it be about flattish?

James J. Volker

Well, I don't want to get into breaking down our estimated budget for next year yet because we're still -- obviously, we've had some great results here and there's some more drilling that could occur, so I don't want to go into that. There's also some leasing that's going on. I don't want to go into that for competitive reasons. But I would say, yes, no more than what we currently, I would guess, somewhere -- no more than what we spend on acreage this year, which we've broken out for you there on our budget.

Operator

Your next question comes from [indiscernible] from UBS.

Unknown Analyst -

[indiscernible] tested at the lower Three Forks and just had initial success. Are you guys planning to test those lower Three Forks expenses at some point?

James T. Brown

Yes, in all of our prospect areas, the ones that are de-risked Cassandra, Tarpon and Hidden Bench, we think that we've got great Three Forks potential there as well. We have not included yet the Three Forks in what we believe that those areas are capable of producing, but we have early on in 2012 a test the lower Three Forks plant at Hidden Bench there in McKenzie County. So as well as further south, all the way down in the Stark County where we think we have outstanding potential in the lower Three Forks down there as well. So we're definitely making that part of our exploration program. We don't count that in our development program just yet.

Unknown Analyst -

Okay. Are you seeing additional pressure pumping fastly moving into the Williston? And when do you think completion costs will begin to come down?

James J. Volker

Well, I think they're going to be flattening here in 2012 as more crews show up.

Operator

Your next question comes from Jason Wangler from SunTrust.

Jason A. Wangler - SunTrust Robinson Humphrey, Inc., Research Division

Just curious as far as the Eagle Ford transaction, is there anything else you're looking for on a non-core basis to potentially move out, just add some cash as you go through the rest of this year and then the next?

James J. Volker

The answer is yes, but I'm not prepared to say what or where. But there are relatively small amounts of BOEs per day, and it would be in areas where again people have come to us or through our own efforts in talking to the people who are offset operators or that sort of thing. we're being offered what I would consider to be compelling prices for our acreage, our undeveloped acreage.

Jason A. Wangler - SunTrust Robinson Humphrey, Inc., Research Division

Okay. And then just curious, on the release, you had the one Scallion well. How does that look versus your expectations? And do you plan on drilling another one given those results?

James T. Brown

On Scallion, we continue to believe in the Scallion. We have not seen the results yet from the Scallion that we would like. We did drill a well out there in O'Neil Creek and we -- but it's important to recognize that, that area on the north end of Lewis & Clark, as well as what we call Big Island, which shows up on our map here, we have multiple objectives out there. We're working on both the Three Forks. And as we've mentioned last quarter, we're working on the Tyler, as well as the Scallion. So we've got a number objectives and a lot of things that we're trying to do out there. Scallion so far hasn't been what we'd hoped it would be. But I think the really good thing about that area is there's quite a bit of economy of scale. So when we drill a Red River well, we get the opportunity to get another data point and typically a core out of the other intervals that we're interested in. So we're working on that interval. We've had good success in the Red River, which allows us to keep this project going and then we're going to figure it out.

James J. Volker

I'd like to expand just a little bit on sort of some of the comments that have been made by Mark and Jim and myself, especially as we talk about the Three Forks. First of all, I'd like to sort of remind you that I think the production results that Jim talked about when we say we're -- over the first half year or a little more of the production from our prospect wells versus other people's wells, where we document for you that on average 50,000-barrel excess of production or superiority of production of our wells versus other people's wells, that comes about because of the -- again, lay this squarely at the door of our geoscientists because of the work that we've done in order to isolate what we think are sweet spots within either the Bakken or the Three Forks. And in particular, we think this Pronghorn Sand is, to date, the best reservoir for going horizontal in because when we frac it, we do get a chance to frac down into the upper Three Forks. Now having said that, we've also selected areas, prospect areas, especially along the southwest edge of the basin there where the Three Forks based upon our coring is field to base with oil, field to base with oil. So from the southwest edge back all the way up to the top of Hidden Bench, we think that we have additional potential, which we've yet to tap in as we go deeper in the Three Forks. But so far, that Bench, that porosity that lies right on top of the Three Forks has been the best tank, and that's why we're putting our wells there, that's why our horizontals are there and that's why, in my opinion, our results in the Three Forks are going to be better than other people's.

Operator

Your next question comes from Pearce Hammond from Simmons.

Pearce W. Hammond - Simmons & Company International, Research Division

In the past, Jim, you've talked about the potential maybe doing a royalty trust. I was wondering if you could update us on that.

James J. Volker

Still under consideration, but nothing to announce. And where we got lots of properties to do that and so I would say that we're -- I mean, I hope that it's apparent to the market that what we've done is manage our balance sheet in what we think is a very responsible way with 30% debt to total cap, and we intend to keep it in that range. And there are all sorts of opportunities available to us, including royalty trusts, including some minor property sales. And so managing basically what you're spending is the first thing. I think maybe Washington could take a hint from us on that score. But at any rate, right now, we're concentrating on making Whiting good and staying out of Washington.

Pearce W. Hammond - Simmons & Company International, Research Division

And then CapEx for land as we look for next year. Do you think it'll be roughly the same level of this year or it will actually tone down just a little bit on your leasehold?

James J. Volker

Well, I wouldn't -- I don't want to predict that yet as I said before, but I would say equal to or slightly less than, it'll be at above the same range.

Pearce W. Hammond - Simmons & Company International, Research Division

Great. And then finally, as you look at the service environment right now in the Bakken, where do you see it tightest?

James J. Volker

I guess, I'll let Jim Brown opine on that after I make one initial comment, and that is that at Whiting, we prided ourselves for almost 30 years in having good relationships with the major service companies. When we started our operation to rejuvenate in CO2 flood the North Ward Estes field, something very interesting happened. When we spoke to Halliburton, they came to us with a plan that they said was reserved for their best customers. They threw away their price book, they brought in their crews, they frac for us 4 days out of 7 and left their equipment there and moved their crews some place else. So our price per frac based upon my personal calculation was somewhere around 30% of the retail price in their book after everything was said and done. And I can't say enough about our relationship there for with the Halliburton's, with the Bakers, with the Schlumbergers, they've all done a great job for us. And so when people talk to us about the -- and I don't want to leave the drilling contractor side of that either. The drilling contractors that we worked with have -- essentially been people that we worked with for many years as well. So when people talk to us about rising prices, yes, we have to say yes, there has been price pressure. But on the other hand, the cooperation from the Halliburtons, the BJs, the drilling contractors, the Schlumbergers has helped us become more efficient and drill wells in less period of time, frac wells quicker. For example, we typically using our sliding sleeves to do a 30- or even 40-stage job in one day. One day, not one week. And so, again, when you ask us, "Why is your cost $7 million and other people are talking about $8 million to $10 million?" That's the answer, Efficiency. And in large part, that's due to the cooperation that we get from our service companies. Jim, do you want to add to that?

James T. Brown

Yes, I'm sitting here thinking of all the things we've got going on. Service rigs was an issue. We've got that handled, we've got that under control. I'm going to take the position if there's a problem I've heard about, right now, I'm not hearing a lot of problems. We had the frac sand issue. A lot of -- several things have happened, a lot of frac sand is coming on the market from a supply end and also a lot of the companies are getting their storage facilities and handling facilities in place and in operation in third and fourth quarter. So right now, I think -- right now, for Whiting, I think everything is working fairly well, fairly smooth.

Operator

Your next question comes from Mike Scialla from Stifel, Nicolaus.

Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division

Just a couple of follow-ups. I appreciate the acreage cost number you gave for $21 per acre in the Williston. Do you have that broken out by chance by area, like say Sanish and Lewis & Clark in particular? I could follow-up if that's easier.

James J. Volker

We love you, Mike, but we're not going to do that.

Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division

Okay. Fair enough. And then looking at the workovers, you have a lot of workovers in Sanish. I'm just wondering what kind of work you're doing on the wells and how much of those typically cost?

James J. Volker

Okay. Well, Jim will answer that question. First, let me say that the only reason that I don't want to answer that question right now is for competitive reason on some leasing that we're still doing. And maybe by the time we get to July of next year, we'll be happy to answer that question for you because it will be a backward-looking answer.

Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division

Could you do it for Sanish since that one's obviously an area you're not adding to?

James J. Volker

Go ahead, Dave.

David M. Seery

Our average cost in Sanish, we've got in there very early. Less than $250 an acre.

Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division

Okay, great. And then on the workovers, could you talk about that?

David M. Seery

Sure. As Jim mentioned, we got kind of 3 things going on out there. The first one is just putting the wells on artificial lift. We've got about 1/3 of the wells that we have off-production right now, that's what we're doing. And that's just -- that's a couple of hundred thousand dollars. And all of those costs are included in the drill in AFE. So that's just standard work as the wells cease flowing, we get them on lift. Then because we have 200-plus wells on production right now at Sanish, you always have some maintenance to do out there. You've got a rod part, you've got a tubing leak, something like that. So we've got those wells out there. And that could be anywhere from $20,000 to go out there and fix the rod part to maybe $100,000. You got a hole in the tubing, you got to replace part of your tubing string out there. And then the others is just precautionary work that we do. And when we frac an offset well, we occasionally -- not very often, we occasionally we'll frac into the adjacent well. So that's the other thing we have down. We just pull the rods out of there so we don't stick the rods in there with the sand, if there is any. So that's basically what we've got going on out there.

Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division

Have you tried to refrac any of your older wells in the field?

David M. Seery

We've not, but it's something we sure want to try because you've always got those wells that you had high hopes for and something just didn't go right during the frac job, and you're scratching your head. We have not done that yet, but it's sure something we're talking about and looking at. And the guys recently did perform some work that we think may provide us the opportunity to go in there and refrac. So it's something we're going to look at.

Operator

You have no more questions at the moment. I'd now like to hand the call back over to Mr. Volker for closing remarks.

James J. Volker

Thank you, Sandra. I'd like to reference Slide 34, which shows some key points. First, we've grown our production 315% from our IPO to 70,675 BOE per day. Second, at January 1 of this year, we had a drilling inventory of 4,600 gross operated wells across our reserve and resource base, and we believe our drilling results in 2011 will increase this drilling inventory at year end. In summary, we're growing through the drillbit and our discretionary cash flow and our debt to cap puts us in an excellent position to execute on our plans. I'd like to thank all Whiting employees for a job well done in the third quarter and our plans for a strong fourth quarter. I also express my thanks to our directors for their continued contribution to Whiting's success. And Eric will now mention the several upcoming events in which Whiting will participate.

Eric Hagen

Thanks, Jim. We're participating in Barclays Capital Energy, Engineering, Construction Forum, Dallas November 10; Bank of America Merrill Lynch Global Energy Conference, Miami, November 14 through 16; Citigroup's Small and Mid-Cap Conference in Las Vegas, November 15 and 16; Bank of America Merrill Lynch's Leverage Finance Conference in Orlando, November 30 to December 1; JPMorgan's Oil & Gas One-on-One Conference in Boston, December 6; and the Capital One Southcoast Energy Conference, New Orleans, Tuesday, December 6.

Now I'll turn it over to Jim for -- to close us out.

James J. Volker

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

Operator

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

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